Written by rjs, MarketWatch 666
Here are some selected news articles from the week ended 31 July 2021. Part 2 is available here.
This is a feature at Global Economic Intersection every Monday evening or Tuesday morning.
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US oil supplies fall to lowest level since January 2020; natural gas prices back off new 31 month high on a break in the heat
Oil prices rose for the 8th time in the past ten weeks as crude, gasoline, and distillates supplies all fell more than was expected…..after rising 0.7% to $72.07 a barrel last week on tight crude supplies and signs that fuel demand was holding up despite the Covid surge, the contract price of US light sweet crude for September delivery moved lower early Monday after heavy flooding and typhoons in China led to concerns over short-term demand weakness in the world’s largest oil importing country, but steadied after a choppy session to settle 16 cents lower at $71.91 a barrel, as the spread of the Delta Covid variant stoked fears about fuel demand, while losses were limited by forecasts that crude supply will be tight the rest of the year...oil moved higher in Asian trading Tuesday as traders hoped that tight supply and rising vaccination rates would offset the impact of rising global Covid cases on fuel demand and then opened higher in New York, but later faded to finish 26 cents lower at a barrel, as traders backed off to await the weekly crude and products inventory data and a policy announcement from the Fed that could signal earlier-than-expected monetary tightening…after the American Petroleum Institute reported a larger than expected draw from crude supplies, oil prices rose in overnight trading and opened higher on Wednesday, and then rallied to close 74 cents higher at $72.39 a barrel after the EIA reported big across the board declines in US crude, gasoline and distillate inventories…oil prices slipped in Asian trading early Thursday on worries that fuel demand in the US and Europe was plateauing well below pre-pandemic levels, but rallied in New York on a report that inventories at the Cushing, Oklahoma storage hub continued to fall, and then extended the rally to close $1.23 higher at $73.62 a barrel on the back of a weaker US dollar…oil prices softened in early trade on Friday, after the BEA had reported US economy expanded by 6.5% during the 2nd quarter, missing expectations for an 8.5% growth rate, but recovered to close 33 cents higher at $73.95 a barrel as steady demand and tight supplies calmed concerns that a new wave of Covid-19 infections would cripple energy consumption...oil prices thus finished 2.6% higher on the week, and managed to end July 0.7% higher, their 4th-straight monthly gain..
Natural gas prices, on the other hand, ended the week lower, on signs the long & oppresive heat wave was finally breaking….after surging 11% to a new 31 month high at $4.060 per mmBTU last week as yet another continental heat wave loomed, the contract price of natural gas for August delivery advanced for a seventh consecutive session on Monday to close 4.2 cents higher as robust domestic cooling demand and strong LNG exports continued to drive up prices that were again at their highest levels since late 2018… after hitting another new 31 month high at at $4.114 per mmBTU early Tuesday, natural gas prices tumbled over 3% and settled 13.1 cents lower at $3.971 per mmBTU, on forecasts for less hot weather and a drop in demand for air conditioning next week..natural gas price rebounded on the last day of trading for the August contract on Wednesday, and closed 7.3 cents higher at $4.044 per mmBTU, as traders refocused on expectations for strong weather-driven demand in August and continued steady export activity…with natural gas contracts for September delivery trading as the front month on Thursday, that natural gas contract rose 9.2 cents to $4.059 per mmBTU, bolstered by strong fundamentals and a bullish government inventory report that reinforced concerns about supply/demand imbalance and the specter of anemic storage levels ahead of winter.…but natural gas prices were back in the tank on Friday, falling 14.5 cents to $3.914 per mmBTU, as traders took profits and focused on a near-term shift in weather that was expected to usher in a reprieve from the oppressive heat over much of the Lower 48…natural gas price quotes thus ended the week 3.6% lower, while the contract price of natural gas for Septemer delivery, which had closed last week at $4.042 per mmBTU, was down 3.2% on the week..
The natural gas storage report from the EIA for the week ending July 23rd indicated that the amount of natural gas held in underground storage in the US rose by 36 billion cubic feet to 2,714 billion cubic feet by the end of the week, which still left our gas supplies 523 billion cubic feet, or 16.2% below the 3,237 billion cubic feet that were in storage on July 23rd of last year, and 166 billion cubic feet, or 5.8% below the five-year average of 2,882 billion cubic feet of natural gas that have been in storage as of the 23rd of July in recent years…the 36 billion cubic feet increase in US natural gas in storage this week was below the median forecast for a 40 billion cubic foot addition from a S&P Global Platts survey of analysts, but above the average addition of 28 billion cubic feet of natural gas that have typically been injected into natural gas storage during the same week over the past 5 years, and also above the 27 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 July 23rd indicated that after a sizable decrease in our oil imports and a modest decrease in our oil production, we needed to withdraw oil from our stored commercial crude supplies for the ninth time in ten weeks, and for the 25th time in the past thirty-seven weeks … .our imports of crude oil fell by an average of 590,000 barrels per day to an average of 7,097,000 barrels per day, after rising by an average of 875,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 26,000 barrels per day to an average of 2,489,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 4,018,000 barrels of per day during the week ending July 23rd, 616,000 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 200,000 barrels per day lower at 11,200,000 barrels per day, and hence our daily supply of oil from the net of our international trade in oil and from domestic well production appears to total an average of 15,218,000 barrels per day during this reporting week …
US oil refineries reported they were processing 15,875,000 barrels of crude per day during the week ending July 23rd, 132,000 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 average of 584,000 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 73,000 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 (+73,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting there must have been a error or omission of that magnitude in this week’s oil supply & demand figures that we have just transcribed … .(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 6,425,000 barrels per day last week, which was 6.9% more than the 6,012,000 barrel per day average that we were importing over the same four-week period last year … the 564,000 barrel per day withdrawal from our crude inventories was all pulled from our commercially available stocks of crude oil, while the quantity of oil stored in our Strategic Petroleum Reserve remained unchanged … ..this week’s crude oil production was reported to be 200,000 barrels per day lower at 11,200,000 barrels per day because the EIA”s rounded estimate of the output from wells in the lower 48 states was 100,000 barrels per day lower at 10.900,000 barrels per day, while a 36,000 barrel per day decrease in Alaska’s oil production to 342,000 barrels per day caused another 100,000 barrels per day to be subtracted from the rounded national production total (the EIA’s math, not mine) … .US crude oil production had hit a pre-pandemic record high of 13,100,000 barrels per day during the week ending March 13th 2020, so this week’s reported oil production figure was 14.5% below that of our production peak, but 32.9% above the interim low of 8,428,000 barrels per day that US oil production had fallen to during the last week of June of 2016 …
Meanwhile, US oil refineries were operating at 91.1% of their capacity while using those 15,875,000 barrels of crude per day during the week ending July 23rd, down from 91.4% of capacity the prior week, and somewhat below normal for summertime operations … while the 15,875,000 barrels per day of oil that were refined this week were 8.8% higher than the 14,595,000 barrels of crude that were being processed daily during the pandemic impacted week ending July 24th of last year, they were still 6.6% below the 16,991,000 barrels of crude that were being processed daily during the week ending July 26th, 2019, when US refineries were operating at what was a seasonally low 93.0% of capacity …
Even with this week’s decrease in the amount of oil being refined, the gasoline output from our refineries was much higher, increasing by 649,000 barrels per day to 9,779,000 barrels per day during the week ending July 23rd, after our gasoline output had decreased by 728,000 barrels per day over the prior week … while this week’s gasoline production was 6.8% higher than the 9,158,000 barrels of gasoline that were being produced daily over the same week of last year, it was 6.1% lower than the gasoline production of 10,416,000 barrels per day during the week ending July 26th, 2019 … .meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 163,000 barrels per day to 4,739,000 barrels per day, after our distillates output had decreased by 24,000 barrels per day over the prior week … as a result of 5 straight decreases, this week’s distillates output was 0.9% less than the 4,783,000 barrels of distillates that were being produced daily during the week ending July 24th, 2020, and 8.2% below the 5,219,000 barrels of distillates that were being produced daily during the week ending July 26th, 2019..
Despite the increase in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the sixth time in seventeen weeks, and for the 16th time in thirty-seven weeks, falling by 2,253,000 barrels to 234,161,000 barrels during the week ending July 23rd, after our gasoline inventories had decreased by 121,000 barrels over the prior week...our gasoline supplies decreased by more this week because our imports of gasoline fell by 465,000 barrels per day to 909,000 barrels per day while our exports of gasoline fell by 148,000 barrels per day to 716,000 barrels per day, and because the amount of gasoline supplied to US users increased by 30,000 barrels per day to 9,325,000 barrels per day … after this week’s inventory decrease, our gasoline supplies were 5.3% lower than last July 24th’s gasoline inventories of 247,387,000 barrels, but still near the five year average of our gasoline supplies for this time of the year …
Meanwhile, with the decrease in our distillates production, our supplies of distillate fuels decreased for the eleventh time in sixteen weeks and for the 17th time in 32 weeks, falling by 3,088,000 barrels to 137,912,000 barrels during the week ending July 23rd, after our distillates supplies had decreased by 1,349,000 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 431,000 barrels per day to 4,356,000 barrels per day, even while our exports of distillates fell by 245,000 barrels per day to 1,012,000 barrels per day, and while our imports of distillates rose by 101,000 barrels per day to 188,000 barrels per day … after eleven inventory decreases over the past sixteen weeks, our distillate supplies at the end of the week were 22.8% below the 178,386,000 barrels of distillates that we had in storage on July 24th, 2020, and about 7% below the five year average of distillates stocks for this time of the year …
Finally, with the decreases in both our oil imports and our oil production, our commercial supplies of crude oil in storage fell for fourteeth time in the past twenty-three weeks and for the 28th time in the past year, decreasing by 4,089,000 barrels over the week, from 439,687,000 barrels on July 16th to an 18 month low of 435,598,000 barrels on July 23rd, after our commercial crude supplies had increased by 2,107,000 barrels the prior week … . with this week’s decrease, our commercial crude oil inventories remained about 7% below the most recent five-year average of crude oil supplies for this time of year, but were about 28% above the average of our crude oil stocks as of the last weekend of July over the 5 years at the beginning of the past decade, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels … .since our crude oil inventories had jumped to record highs during the Covid lockdowns of last spring and remained elevated thereafter, our commercial crude oil supplies as of this July 23rd were 17.2% less than the 525,969,000 barrels of oil we had in commercial storage on July 24th of 2020, and 0.2% less than the 436,545,000 barrels of oil that we had in storage on July 26th of 2019, but were still 6.6% more than the 408,740,000 barrels of oil we had in commercial storage on July 27th of 2018 …
This Week’s Rig Count
The number of drilling rigs active in the US decreased for just the 5th time out of the past 45 weeks during the week ending July 30th, but it was still down by 38.5% from the pre-pandemic rig count … .Baker Hughes reported that the total count of rotary rigs running in the US decreased by three to 488 rigs this past week, which was still up by 237 rigs from the pandemic hit 251 rigs that were in use as of the July 31st report of 2020, but was still 1,441 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, a week before OPEC began to flood the global oil market in an attempt to put US shale out of business … .
The number of rigs drilling for oil was down by 2 to 385 oil rigs this week, after rising by 7 oil rigs the prior week, but it’s still 205 more oil rigs than were running a year ago, while it’s just 23.9% of the recent high of 1609 rigs that were drilling for oil on October 10th, 2014 … .at the same time, the number of drilling rigs targeting natural gas bearing formations was down by one to 103 natural gas rigs, which was still up by 34 natural gas rigs from the 69 natural gas rigs that were drilling during the same week a year ago, but still just 6.4% of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008 … .
The Gulf of Mexico rig count was down by 3 to 14 rigs this week, with 13 of those rigs drilling for oil in Louisiana’s offshore waters and one still drilling for oil offshore from Texas … .that was still two more rigs than the 12 rigs that were drilling in the Gulf a year ago, when 9 Gulf rigs were drilling for oil offshore from Louisiana and three were deployed for oil in Texas waters … .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 … in addition to those rigs offshore, we continue to have a rig drilling through an inland body of water in Terrebonne Parish of southern Louisiana, whereas there were no such “inland waters” rigs running a year ago …
The count of active horizontal drilling rigs was up by 3 to 442 horizontal rigs this week, which was more than double the 216 horizontal rigs that were in use in the US on July 31st 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 4 to 29 directional rigs this week, but those were still up by 7 from the 22 directional rigs that were operating during the same week a year ago … .in addition, the vertical rig count was down by 1 to 17 vertical rigs this week, but those were also up by 4 from the 13 vertical rigs that were in use on July 31st 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 July 30th, the second column shows the change in the number of working rigs between last week’s count (July 23rd) and this week’s (July 30th) count, the third column shows last week’s July 23rd 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 31st of July, 2020..
With the removal of three oil rigs from the Louisiana’s offshore waters and a natural gas rig from the Haynesville shale, the state’s rig count was down by four, more than accounting for the somewhat anomalous drop in this week’s rig count…the other major decrease was the removal of two rigs from the Uintah basin of Utah, one of which had also been targeting natural gas…checking 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 8A, which encompasses the northern counties of the Permian Midland, and that another oil rig was added in Texas Oil District 7C, which includes the southern counties of the Permian Midland, which means that Texas saw a two rig increase in the Permian this week…since the national Permian count was only up by one, that means that the rig that was shut down in New Mexico had to have been drilling in the far west reaches of the Permian Delaware in that state…meanwhile, since there was no change in the rig deployment in Texas Oil District 10, that means that the rig that was added in the Granite Wash basin almost had to have been added in nearby Oklahoma….elsewhere, there was also a rig added in the Williston basin of North Dakota, while a rig was pulled out of a basin in Colorado that Baker Hughes doesn’t track…for natural gas rigs, there was a rig addition in Ohio’s Utica shale and another in Pennsylvania’s Marcellus, which we offset by the rig removals from Louisiana’s Haynesville, from Utah’s Uintah, and from one other basin that Baker Hughes doesn’t track separately..
Union Co. farmer sues ODA over pipeline on preserved farmland –A Union County farmer is suing the Ohio Department of Agriculture and Columbia Gas of Ohio over a natural gas pipeline that is set to go through preserved farmland. Attorneys for the Bailey family filed two lawsuits July 12 to force the department of agriculture to defend its land from the pipeline and to stop Columbia Gas of Ohio from moving forward with eminent domain proceedings. The first lawsuit claims the Ohio Department of Agriculture is not enforcing the terms of the agriculture easement, which prohibits any industrial activity from taking place on the farm, like installing a utility line, unless it is strictly for the benefit of the farm. Don Bailey is the successor trustee for the Arno Renner Trust. Renner was Bailey’s uncle, and he donated the agricultural easement to his 231-acre farm in 2003 to the department of agriculture, through its farmland preservation program. Columbia Gas of Ohio announced plans in late 2019 to put a 12-inch gas distribution line through the Baileys’ fields. The Marysville Connector Pipeline Project would stretch nearly 5 miles to feed the industrial park near the farm, as well as a nearby residential development. Instead of defending the terms of the easement, the Ohio Department of Agriculture recused itself from the Ohio Power Siting Board decision on the pipeline in order to prevent the “perception of impropriety.” The pipeline was approved in August 2020. In two prior cases, the state went to bat for the Bailey farm when it faced the threat of utility development. In 2005, the city of Marysville wanted to put a 72-inch sanitary sewer line through the farm. The state director of agriculture at the time, Fred Dailey, wrote a letter to the mayor of Marysville asking if the line could be rerouted, and it was. The second time was in 2008, when a private developer wanted to put a 36-inch water line through the farm. In that case, then Ohio Attorney General Nancy Rogers issued an opinion that the easement language prevented the construction of such a line because the “proposed water line would not solely serve the Bailey property.” The Ohio Department of Agriculture has taken a different approach to the easement in the case of the Marysville Connector Pipeline. It focused on how the pipeline would impact the agricultural use of the property, and it found that the agricultural use of the farm would not be irreparably harmed by the pipeline.M
Feds and states not taking radioactivity from fracking seriously, environmental group says – Ohio Capital Journal — Fracking might be an economic boon to some landowners in depressed sections of Eastern Ohio, Western Pennsylvania and much of West Virginia. But federal and state officials are doing little to protect citizens from the radiation hazards posed by the process, a new report says. For example, a solution containing substances such as Radium-226 in concentrations 300 times federal drinking water standards is spread on Ohio roads and there are no federal or state regulations to stop the practice, the report by the Natural Resources Defence Council says. After their application to icy roads, it’s not hard to see how toxic substances can run off into streams. From there, who knows?Titled “A Hot Fracking Mess: How the Lack of Regulation of Oil and Gas Production Leads to Radioactive Waste in Our Water, Air, and Communities,” the report details the many ways that fracking, or “hydraulic fracturing,” produces toxins.The practice of using water and chemicals to blast through rock formations to get to previously inaccessible fossil fuels is not completely negative from an environmental standpoint. It’s made cleaner-burning natural gas a cheaper energy source than coal and some environmentalists have praised it as a bridge fuel while cleaner alternatives are developed in the race against global warming. But, the NRDC report notes, state and federal regulators have taken a pass on protecting against fracking’s potential ill-effects – particularly for people living near fracking pads.”Unfortunately, without adequate regulations, there is scant industry monitoring data or information about violations, so the full scope of health impacts facing nearby residents or workers from (toxic substance) exposure remains unclear,” it says.A number of radioactive elements are naturally present in the Earth, often locked far down where they don’t threaten human health. But fracking can blast known toxins such as radium, lead and polonium out of rock formations. Then they can be brought back to the surface in drill cuttings, wastewater and contaminated pipes.It also can produce toxic air, Inside Climate News reported in 2014.But regulators have seemed to go out of their way to avoid tracking toxic waste – even from conventional drilling long before the fracking revolution, the NRDC report says.
Under “Chief’s Orders” Ohio Operates a Radioactive Industry Off The Record – Everyone knows that oil and gas wells produce oil and natural gas. But few people understand that these wells also produce radioactive material that is being disposed of in communities alongside household trash and making its way into rivers used for drinking water and recreation. The oil and gas industry consistently claims that the levels of radioactivity in its waste and byproducts are safe – but a growing body of data proves otherwise. The Environmental Protection Agency (EPA) defines the radioactive portion of this waste as TENORM (technologically enhanced naturally occurring radioactive material), and in communities across shale plays like Ohio, TENORM is piling up in watersheds. While Ohio has strict regulations governing radioactive waste that come across its borders – the O.R.C. 3734.02 – the rules are not actually enforced. The state code doesn’t require the kind of extensive testing necessary to adequately measure radioactivity in TENORM waste.Next door in Pennsylvania, which exports massive volumes of oil and gas waste to Ohio, the same shale basins – i.e., the Marcellus and Utica Shales – are also being exploited. But unlike Ohio, Pennsylvania is at least gathering some data. In 2016, the commonwealth released a TENORM study on fracking’s oil and gas waste that has begun to shed light on the dangerous game being played with radioactive material in Ohio. In fact, one attorney interviewed for this series stated – “The state is acting illegally.”After 15 months of reporting and research, this three-part series on radioactive material from the oil and gas industry is Public Herald’s latest state-wide investigation of regulatory failure in and around the fracking industry, this time focusing on Ohio: Welcome to Part One.
Investigation Uncovers Ohio Is “Illegally” Building Radioactive Mountains, Affecting 26 Waterways – Part 2 of Ohio TENORM Mountains 3-part series. Read Part 1. Get the story in print through one of seven Ohio Ogden papers, starting front-page at Sandusky Register. Never before in the history of America has the country undertaken an experiment like what’s happening with radioactive material from oil and gas fracking.Everyone knows that oil and gas wells produce oil and natural gas. But few people understand that these wells also produce radioactive waste, or that it’s being disposed of in communities alongside household trash.The Environmental Protection Agency (EPA) defines the radioactive portion of this waste as TENORM (technologically enhanced naturally occurring radioactive material), and in communities across shale plays like Ohio, TENORM is piling up alongside watersheds. TENORM Mountains MAP: Who’s Storing & Treating Radioactive Waste From FrackingRepublic Services Carbon Limestone Landfill is one of the eight landfills in Ohiocurrently receiving waste from unconventional oil and gas operations, according to information acquired by Public Herald from the Ohio Environmental Protection Agency (OEPA).In Ohio, TENORM disposal at landfills falls under O.R.C. 3734.02, which states that a solid waste facility can not accept or transfer TENORM if it contains radium-226, radium-228, or any combination of the two at more than 5 picocuries per gram (pCi/g) over the natural background.It’s worth repeating that this code puts the limit of TENORM coming into or out of landfills at 5 pCi/g. Not much testing has been done on TENORM waste in Ohio, but much of the TENORM waste arriving at Ohio landfills is from the Marcellus Shale – the same shale waste that has been tested in a 2016 Pennsylvania TENORM study. In that study, radium levels from fracking waste in the Marcellus were detected as high as 13 pCi/g, more than 2.5 times greater than the Ohio code permits. The average load for combined radium reported in the study from 18 samples was 5.847 pCi/g, again exceeding the Ohio code of 5 pCi/g.But even though Ohio’s TENORM code places a strict standard on radioactive waste disposal, the state hasn’t produced documentation to Public Herald of measurement and enforcement for radium at landfills.”It is an extremely, overwhelmingly strong bet that the waste and disposal practices in Ohio are seeing a great deal of material that exceeds the limits,” said Ohio attorney Terry Lodge. “The state is acting illegally.”
Debrosse Memorial Report: Steep Decline in 2020 Ohio O&G Production —In June the Ohio Oil & Gas Association (OOGA) held its 74th Annual Winter Meeting in Columbus. Yeah, you read that right. The Winter Meeting was moved to June this year due to COVID. As with previous annual OOGA meetings, one of the speakers was Martin Shumway, technical director at Locus Bio-Energy Solutions. Shumway shared details from the latest DeBrosse Memorial Report (full copy below). What does the report show for 2020? Ohio oil and natural gas production both experienced steep declines last year. Oil production was down 16% from 2019, and natural gas production was down 10% from 2019. Even though the production news for 2020 is negative, this report is jam-packed with terrific, very useful information about Ohio’s shale industry.For example, there were 266 oil and gas wells completed last year in Ohio, of which 216 (81%) were Utica wells. Jefferson County dethroned Belmont County in 2020 for the most wells drilled (61). And once again, for the second year in a row, Ascent Resources (formerly American Energy Partners) drilled the most wells in Ohio last year (116 wells), which is more than the 104 it drilled in 2019.The DeBrosse Memorial Report (embedded below) is full of Top 10 this and Top 12 that, sliced and diced in multiple ways. You’ll love it if you want to know more about the Utica and O&G in general in Ohio.A few insights into the numbers from our friends at NGI: Completion activity also fell as operators deferred activity during the virus-induced slump. OOGA’s report said there were 267 completions in 2020, down 34% from 2019. Roughly 80% of all completions were for horizontal wells Jefferson, Belmont, Monroe, Harrison and Guernsey counties accounted for 80% of all completions and wells drilled in the state last year.Meanwhile, Ascent Resources Corp., Encino Energy LLC and an affiliate of Southwestern Energy Co. were the top three most active operators. They accounted for nearly 70% of all wells drilled in the state during 2020.The number of producers operating in Ohio has continued to decline, going from 41 in 2019 to 31 in 2020, according to the report. Before the Utica land rush got underway in 2008, there were more than 180 exploration and production companies working in the state, but that number has declined every year since as assets in the basin have been consolidated by dominant operators.* The full 2020 DeBrosse Memorial Report:
PennEnergy to install well on Ekastown Road in Buffalo Township –PennEnergy will be installing a well site in Buffalo Township after gaining approval from township officials. Construction at the site, located at 765 Ekastown Road, is slated to begin later this summer, said Amanda Peterson, a stakeholder relations manager with PennEnergy. Some township residents have voiced concerns on social media about the well site. One resident urged people living nearby to voice concerns about the site’s potential impact on the community to local officials, though the project has already been approved. Though residents on social media have claimed that the township and the energy company failed to provide the public with information on the potential project or a forum to voice their questions and concerns, Buffalo Township Secretary and Treasurer Janice Zubrin said officials did go through proper process before approving the well. PennEnergy submitted a conditional use request for oil and gas development in late April 2020, she said. The proposal was then reviewed by the township engineer, planning commission and board of supervisors. Advertising for a public hearing on the topic ran in the Butler Eagle newspaper on two separate dates prior to the public hearing on June 9. The board of supervisors approved the conditional use application on the same date, Zubrin said.
Lawmaker asks state to turn down energy company’s request to draw water from Big Sewickley Creek for fracking –A lawmaker has asked Pennsylvania’s top environmental official to turn down a plan by PennEnergy Resources to draw as much as 3 million gallons of water a day from Big Sewickley Creek and one of its tributaries for natural gas drilling. Members of the Big Sewickley Creek Watershed Association also have raised concerns that drawing so much water from the creek could be harmful to wildlife because the creek regularly experiences low levels during dry periods. “One of these locations where water will be pulled includes the famous swimming hole on Cooney Hollow Road,” the association wrote in social media posts asking residents to contact public officials to voice their opinions on the proposal. “Any water withdrawals from the creek will permanently affect the existing habitat due to low flow during summer drought, leading to a need for stream restoration actions. If the flow is altered much more, it may affect the trout stocking and recreation permanently.” Penn Energy sent letters to officials in Economy Borough in Beaver County on June 28, informing them of the plan to draw 2 million gallons of water from Big Sewickley Creek each day and 1 million gallons a day from its North Fork tributary. The water is used for hydraulic fracturing, or “fracking,” a technique used to extract oil and gas from bedrock by injecting a high-pressure mixture of water, sand or gravel and chemicals. In response to Penn Energy’s notification to the borough, state Rep. Rob Matzie, D-16th, asked state DEP Secretary Patrick McDonnell not to approve the plan. Matzie wrote that while he supports natural gas drilling, he can’t back PennEnergy’s proposal. “Let me be clear. I am on record as supporting natural gas extraction. I do not support a ban,” Matzie wrote. “But I have also fought for and voted against measures that weaken regulations and remove local input and control on these permit requests. “In most cases, I believe we can have energy extraction and maintain a clean, healthy environment. I do not believe this is one of those cases.
DEP to require landfills to test for radioactivity from fracking waste –The Pennsylvania Department of Environmental Protection said it will now require all landfills that take solid fracking waste to test their leachate, or liquid waste, for radioactive materials common in oil and gas waste. Landfills often send leachate, a liquid waste formed from rainwater that seeps through piles of waste, to treatment plants. They test it for dozens of potential pollutants. But they’ve never had to test it for radium, a radioactive material common in oil and gas waste. “We take seriously our responsibility and duty as an environmental steward,” Gov. Tom Wolf said in a statement. “This additional requirement will improve public confidence that public drinking water and our precious natural resources are being appropriately protected. The issue of radioactivity in landfill leachate garnered public attention in 2019. At the time, a Fayette County waste treatment plant sued to have a nearby landfill stop sending it leachate after the treatment plant found high amounts of oil and gas contaminants in the liquid waste. The DEP said in the tests it ran on the leachate at that landfill and others, radium levels were below federal action levels. The tests “did not identify significant differences in radium levels between landfills that accept oil and gas waste compared to those that do not,” the DEP said in a statement Monday. “Testing results in all cases were lower than effluent limits for (radium) established by the U.S. Nuclear Regulatory Commission (NRC) for facilities under its jurisdiction.”But environmental groups and some scientists have worried the liquid waste could expose drinking water supplies to contamination. According to the EPA, “chronic exposure to high levels of radium can result in an increased incidence of bone, liver or breast cancer.”In 2020, state records show oil and gas drillers sent 244,000 tons of drill cuttings to landfills. Pennsylvania Attorney General Josh Shapiro, who issued a grand jury report last year slamming the DEP for failing to protect the public from the health effects of fracking, hailed the decision. “Pennsylvanians living next to landfills and in the shadow of fracking wells have a constitutional right to clean air and pure water, and the improved monitoring and promised analysis by DEP is a step in the right direction,” Shapiro said. Amy Mall, a senior advocate with the Natural Resources Defense Council, which recently released a report calling for more regulation of radioactive waste from the fracking industry, also praised the decision. But in an email she also called on the state to do more “to protect workers and nearby residents from radioactive waste generated by oil and gas production.”
PA DEP to Require Radium Tests at Landfills Accepting Drill Cuttings – Yesterday PA Gov. Tom Wolf grabbed some headlines by having his Dept. of Environmental Protection (DEP) announce they will “soon” begin to require *all* landfills in the state to test leachate (water with nasty stuff in it that comes from landfills) for radioactivity. The Wolf DEP press release takes great pains to point out the new testing includes landfills “that accept unconventional oil and gas waste.” Which is the purpose of the announcement. To plant the seed that maybe, just maybe, drill cuttings are causing folks to glow in the dark. Radiation poisoning. Yet buried in the press release is this statement about a previous study of leachate from PA landfills with and without drill cuttings … “The study did not identify significant differences in radium levels between landfills that accept oil and gas waste compared to those that do not. Testing results in all cases were lower than effluent limits for radium-226 and radium-228 established by the U.S. Nuclear Regulatory Commission (NRC) for facilities under its jurisdiction.” So even though there’s no proof of any problems, the state will now require quarterly testing for radioactivity from landfills anyway. Fine. Whatever floats the DEP’s boat. If they want extra testing each quarter, let them have it. We (as an industry) have nothing to hide. We want to know if there are issues so we can address them. Here’s the DEP announcement from yesterday: In an effort to further protect Pennsylvania’s waterways and drinking water, the Wolf Administration announced today that it will soon require all Pennsylvania landfills – including those that accept unconventional oil and gas waste – to conduct quarterly testing of leachate for radiological contaminants.Landfills are currently required to test leachate – or liquid generated during waste decomposition – for various contaminants before this liquid is either treated by an on-site leachate treatment facility or sent to wastewater treatment facilities. This additional step of including radium in the list of contaminants to be measured will allow the Department of Environmental Protection (DEP) to evaluate the presence of radium in landfills.“We take seriously our responsibility and duty as an environmental steward,” said Gov. Tom Wolf. “This additional requirement will improve public confidence that public drinking water and our precious natural resources are being appropriately protected.” DEP currently identifies contaminants in leachate through reports sent from landfills on a quarterly basis. DEP has begun the process of updating its reporting document to include radium-226 and radium-228, which will be implemented later this year. All landfills, including those that accept oil and gas wastes, will be required to test for these radiological contaminants.
Pa. Supreme Court: Money from state-forest drilling cannot prop up state budget –The Pennsylvania Supreme Court ruled that state officials cannot transfer money from the Department of Conservation and Natural Resources’ Oil and Gas Fund – derived from natural gas drilling on state forest land – to the state’s general fund to help balance the annual budget.The PA Environmental Defense Foundation brought the lawsuit, and was appealing a 2020 Commonwealth Court decision, which paved the way for the diversion of more than $110 million from the Oil and Gas Fund between 2017 and 2019, to pay operating expenses rather than using it for conservation purposes.John Childe, attorney for the foundation, said the court’s opinion “affirms our belief that all funds from the oil and gas leases, including the royalties, bonus and rental payments, are part of the public trust, and must be used to conserve and maintain the public natural resources, including our state forest.”The foundation has pushed back against the transfers for the past dozen years.The Supreme Court’s opinion does not mean the money must be paid back; only that it must be used for conservation purposes going forward.Supreme Court justices found the Commonwealth Court’s 2020 ruling was at odds with its own 2017 ruling on the same issue, when foundation members challenged the transfer of $594 million from the fund between 2008-16. Foundation officials argued that the state’s Environmental Rights Amendment does not permit money from the Oil and Gas Fund to be used for general budgetary matters. Unconstitutional appropriations from the fund between 2017-19 total more than $234 million.
Cabot, Southwestern See Natural Gas Prices Impacted by Appalachian Pipeline Constraints – Cabot Oil & Gas Corp. and Southwestern Energy Co. were the latest Appalachian operators to report weak price realizations in the second quarter, when pipeline constraints widened basis differentials in the Northeast. U.S. benchmark prices climbed during the period and have continued to move higher since, creating an even bigger gap with local prices in Appalachia, where pipeline maintenance and outages have suppressed returns. Cabot increased its differential guidance for the year, but sees an improving outlook. “We are optimistic about a strong improvement in local pricing in the second half of the year, driven by our expectations for continued strength in regional gas demand, flat production profiles across the Appalachian Basin and a significant reduction in storage levels, which are currently 17% below 2020 levels and 8% below the five-year average,” said Cabot CEO Dan Dinges. Southwestern reported a steep loss on unsettled derivatives. Other Appalachian operators, such as EQT Corp. and Range Resources Corp. have also been dented this earnings season by questions over their hedging strategies. EQT reported a loss on its hedge position, while both Range and EQT have locked in prices below current market levels to protect against volatility in the Northeast. Roughly 2 Bcf/d of excess transportation capacity currently exists in the Appalachian Basin, according to East Daley Capital Inc. That leaves little wiggle room when pipelines are squeezed by unplanned events.Appalachian takeaway did get a lift Thursday, when Texas Eastern Transmission Co. said it received approval to restart operations on a portion of its 30-inch system, which has been offline since May. Southwestern CEO Bill Way said the company’s acquisition of Haynesville Shale pure-play Indigo Natural Resources LLC is on track to close by year’s end, with a shareholder vote scheduled for Aug. 27. The deal would give the company access to the Gulf Coast and get it closer to booming liquefied natural gas export demand. It would also limit its price exposure in the Northeast.
EQT Reshaping Strategy for Era of ‘Sustainable Shale’ –EQT Corp. CEO Toby Rice said Thursday the largest natural gas producer in the United States is positioning itself for a “new era of sustainable shale,” further shaping its strategy to evolve into a lower carbon future. “As the largest producer of natural gas in the U.S., we’re able to forge new paths and open new markets to achieve sustainable growth,” Rice said. “This affords us the ability to pursue meaningful opportunities that smaller peers cannot.” The board has approved $75 million to explore new venture opportunities, Rice told analysts during a call to discuss second quarter results. “This seed capital allows us to initiate several pilot programs over the next few years” aimed at further cutting emissions. The company is aiming for net-zero Scope 1 and 2 greenhouse gas emissions by 2025. It has announced partnerships with Equitable Origin, MiQ and Project Canary to certify that about 4 Bcf/d from more than 200 wells in Pennsylvania is being responsibly produced under third-party environmental standards. CFO David Khani said EQT continues to see demand from both domestic and international buyers for responsibly sourced gas (RSG) as the desire to reduce carbon footprints grows. “We’ve already entered into a couple of RSG contracts with premium pricing,” Khani said. EQT’s position across the Appalachian Basin continues to grow. Rice said that can help to further reduce emissions in the Marcellus and Utica shales as the scale allows it to better execute its operational strategy. EQT completed the acquisition of Alta Resources Development LLC last week, giving it another 300,000 net Marcellus Shale acres and entry to a dry gas stronghold in Northeast Pennsylvania.The company plans to run a maintenance program on the assets. However, it expects total sales volumes to increase by up to 175 Bcfe this year as a result of the acquisition. The company is now guiding for up to 1.875 Tcfe of production this year. It also increased its capital expenditure guidance for the year to an estimated $1.100-1.175 billion from $1.025-1.125 billion.
Cleanup continues after oil spills in waters of New Rochelle Harbor (WABC) — Cleanup continued Saturday following an oil spill in Westchester County that leaked into a nearby harbor. A Con Edison spokesman says dielectric fluid leaked from a transmission feeder into a manhole on Nautilus Place on Saturday, July 17. Some of the fluid then entered a nearby catch basin on Drake Avenue and then leaked into the waters of New Rochelle Harbor. Members of the U.S. Coast Guard responded to the scene along with the New York City Fire Department and Con Edison. The spokesman says Con Edison clamped the feeder, stopping the leak, and immediately began working to contain and remove the fluid. Video showed crews still working to clean up the spill this weekend. Con Edison says they are using protective booming, absorbent materials and oil skimming equipment to contain and recover the fluid in the harbor.
ConEd Long Island Sound Oil Spill Spoils Glen Island’s Return – Earlier this month, elected officials were celebrating Glen Island Park’s release back to the community after being taken over by the state as a testing site in the earliest days of the coronavirus pandemic, but the symbolic victory was short-lived. “I am thrilled that Glen Island will be open for the summer. I’m thrilled that families will once again enjoy the cool breeze off the sound and that kids will splash in the water,” Westchester County Executive George Latimer said in a July 1 statement announcing the reopening of the county-owned park. A few short days later, neighbors cheered as the last testing tents were finally removed from the park’s parking lots and the beach opened to swimmers, but the park was soon pressed into service in response to another crisis. The space has become a staging area for tanks, pumper trucks and cleanup crews. Long stretches of the island park’s shoreline are ringed with floating booms and oil absorbing pads. On Sunday, beachgoers were being told not to go in the water. Work crews and boats cleaning the Glen Island waterfront on Sunday (Jeff Edwards | Patch) On July 17, a failure of equipment used by Con Edison caused the release of dielectric fluid, which is used to cool the transmission lines that cross the Long Island Sound. The oil flowed down the street and into the New Rochelle Harbor near Wright Marina across the water from Glen Island. A portion of the spilled oil reached the Long Island Sound at the harbor. Con Edison immediately reported the spill to the New York State Department of Conservation, repaired the line and hired several contractors to clean up the harbor area and land adjacent to the spill, according to state officials. The cleanup includes the use of skimmer boats, vacuum trucks and application of absorbent materials. Glen Island is the staging ground for some of this equipment, including tractor trailers containing booms and supplies, boat trailers and waste roll-off containers for the cleanup effort. Thousands of feet of booms have been deployed on the lower harbor stretch of Glen Island while workers spray down the bulkheads and loose stones used to form the island’s shoreline and collect the oil released during this operation, officials say.
Activists sue National Grid and NYC over gas facility in Greenpoint Brooklyn Paper -Environmental activists have filed a lawsuit to halt construction of a National Grid’s natural gas facility in Greenpoint, claiming the project, which is still undergoing environmental review, is in violation of state environmental law. The suit, filed in Kings County Supreme Court on July 23 by the Sane Energy Project and the Cooper Park Resident Council, claims that the city and state failed to follow their own environmental review process by neglecting to conduct a proper review of the construction project. Specifically, the activists say the city of New York violated the State Environmental Quality Review Act, and name the city, the FDNY, and National Grid as defendants.Because the proper review never took place, the environmentalists allege, the city should have stopped the construction, and the FDNY should never have granted variances for storing highly explosive Liquid Natural Gas trucks on city streets. “This is something that must be stopped and must be stopped immediately,” said Elisha Fye, Vice President of the Cooper Park Residents Council. “I’ve been living in this community since 1953. We’re already impacted in this community with the oil spill that happened. We were stricken with asthma, a pandemic of asthma flooded this community, illnesses, deformities in pregnancies, not to mention the soil is still contaminated to this day.”
TETCO Pipeline Ready to Restore Full Pressure Any Time – In June MDN brought you the news that Enbridge’s Texas Eastern Transmission (TETCO) pipeline is being flow-restricted by the Pipeline and Hazardous Material Safety Administration (PHMSA). Some 40% of the Marcellus/Utica molecules that flow through TETCO’s pipeline to destinations in the southeastern U.S. have disappeared and were predicted to stay that way until the end of September (see TETCO Pipe Throttling 40% of M-U Southbound Gas to Last All Summer). Good news: TETCO is telling customers it’s ready to increase pressure and flows the second PHMSA gives the OK, and there’s no remaining issues to be resolved. A ramp-up to full pressure could come soon-in July or August instead of September.PHMSA ordered the reduction in pressure after TETCO found “an anomaly” during a recent inspection that the agency wants to investigate. Since TETCO has had three explosions in various locations since 2016, it’s probably a good idea to back off on the pressure for now. However, reduced flows mean higher prices at the Henry Hub and (gulp) lower spot prices in the M-U region. We can’t get our gas out to other markets willing to pay more.Earlier this month we told you that some of those flow-restricted molecules are finding their way to Midwestern markets (see M-U Molecules Head to Midwest with TETCO Throttling to Southeast). Still, it will be good to have TETCO operating at full capacity once again, flowing more molecules to the southeastern part of the country. Reuters has the good news that Enbridge is ready to dial up the pressure on TETCO as soon as PHMSA gives the all-clear signal: Enbridge Inc’s Texas Eastern Transmission (TETCO) unit said it provided all the information federal safety regulators requested and is preparing to increase pressure in its Pennsylvania to Mississippi pipeline as soon regulators approve.TETCO declared a force majeure on May 28 after the U.S. Pipeline and Hazardous Material Safety Administration (PHMSA) required the company to reinstate a 20% pressure restriction on two of three lines (Lines 10 and 15) that make up its 30-inch system between its Kosciusko, Mississippi, and Uniontown, Pennsylvania, compressor stations effective June 1.That reduction cut flows from Appalachia to the Gulf Coast on the 30-inch system at the Owningsville compressor station in Kentucky to an average of 1.1 billion cubic feet per day (bcfd) in June and 1.3 bcfd so far in July from an average of 1.9 bcfd in May, according to Refinitiv data.In a notice to customers late Friday, TETCO said: “In order to expeditiously recommence operations at full operating pressure once PHMSA approval is granted, (TETCO) is proactively preparing its … process to allow the system to operate at full operating pressure.”Previously, TETCO said it anticipated the earliest the 30-inch system could return to full pressure was late in the third quarter of 2021.
Pipeline’s carbon offsets don’t come close to adding up – The Mountain Valley Pipeline continues to try to divert attention from the destructive effects of its project. In a July 12 news release, MVP announced that it would purchase more than $150 million in carbon offsets to make MVP operational emissions carbon neutral for the first 10 years of operation through a methane abatement project at a Southwest Virginia coal mine. A closer look behind the smoke and mirrors reveals the true nature of the carbon offset plan. MVP boasts that methane mitigation projects like their offset plan are cited in the 2021 UN Global Methane Assessment. But the MVP fails to mention that the report states that we shouldn’t be building any new fossil fuel infrastructure – like the MVP. There are many other negative issues the plan would not address. The MVP plan would not offset any operational emissions beyond 10 years. The MVP could be in operation for 50 years. The plan would not offset the downstream combustion of 2 billion cubic feet per day of methane that the MVP would carry. Unless questionable carbon capture practices are employed, those greenhouse gases would still discharge unabated into our atmosphere. Neither would the plan offset the upstream greenhouse gas leaks and emissions from fracking required to obtain the gas. It would not offset the pain, suffering and negative health impacts to our fellow citizens living in the fracking fields of West Virginia and Pennsylvania where MVP gas would be sourced. Studies show significant negative health impacts to families living near fracking sites. It would not offset the seizure of land, loss of property value and loss of home business income for thousands of hard-working low- and middle-income Americans along the MVP route. It would not offset the threat to their drinking water wells and springs, pollution to their streams, rivers and air, or destruction of their farmland. It would not offset the documented mental health anguish that many of them have suffered from the MVP’s attack on their peace of mind. It would not offset the miles of forest that the MVP has destroyed. These forests cleaned the air, sequestered carbon, provided clean water, wildlife habitat and a beautiful cathedral of peace and tranquility. They have been replaced by the permanent scar of the MVP, an ongoing nightmare for those who are now forced to look at it every day, much like looking at a scar across the face of a loved one. It would not offset the leakage and intentional discharge of numerous toxins, including radioactive substances, that are carried in the gas stream. It would not offset the negative health impacts to all of us from fossil fuels, as the UN report clearly points out. The MVP project would not offset the downstream greenhouse gas emissions. MVP operational greenhouse gas emissions are about one third of one percent of the greenhouse gas emissions that would be discharged from burning the gas. Using the same cost-to-offset ratio as the MVP plan, the cost to offset 50 years of combustion from the MVP is $225 billion.
Virginia Air Pollution Control Board to Rule on New Pipeline – The Lambert compressor station, a natural gas facility in rural Virginia, if approved, would extend the 303-mile Mountain Valley pipeline project by 75 miles into North Carolina. Opponents of the project argue that the proposed expansion would adversely impact the health of low-income and majority African-American residents of Banister District in Pittsylvania County, Virginia. These arguments are being made in front of the Virginia Air Pollution Control Board in an effort to obtain a denial of a key approval being sought by the developers of the project. Analysts believe that a denial would be a big step in the fight for environmental justice. This begs the question: what is environmental justice? According to the U.S. Environmental Protection Agency, environmental justice is the fair treatment and meaningful involvement of all people regardless of race, color, national origin, or income with respect to the development, implementation and enforcement of environmental laws, regulations and policies.[1] Political, legal and societal pressures are creating debates around pipeline projects throughout the country, the most notable of them being the Keystone XL oil conduit to the Atlantic Coast. Developers are revising or, in some cases, abandoning mature natural gas projects due to these pressures and strong advocacy and activism in favor of environmental justice. Recently, for example, the developers of the Byhalia Connection crude oil pipeline in Memphis walked away from the project due to upheaval over the proposed project’s disparagingly adverse impact on African-American neighborhoods.[2] Grassroots activism, voices as powerful as the President’s[3] and as well-respected as George Thurston’s, a New York University expert on the health effects caused by air pollution, have made clear to natural gas pipeline developers that environmental justice is to be taken seriously. These efforts have not only spurred cancellations or terminations of significant energy projects. They have also led to the creation of projects, ventures and initiatives that further environmental justice, especially in the renewable energy sector. Virginia’s Air Pollution Control Board has a big decision to make. Last year, the 4th U.S. Circuit Court of Appeals ruled that a different project, the Atlantic Coast pipeline project, could not go ahead[5]. The Court held that this same Board had failed to carefully account for the disproportionate harm of the project to surrounding residents.[6] The Board now has to decide: will the Lambert project live or will the possibly emerging trend in favor of environmental justice see the project suffer the same fate of some other pipeline projects of recent times? This case could prove to be a bellwether in the larger national environmental justice debate.
Federal review recommends leaving cancelled Atlantic Coast Pipeline pipe, felled trees in place – A federal review of a plan to restore land disturbed by construction of the Atlantic Coast Pipeline prior to its cancellation in July 2020 recommends that some 31 miles of installed pipeline and 83 miles of trees felled for the project be left in place to minimize further disturbance to wildlife and vegetation. “Overall, we believe removing the installed pipe would destabilize currently stable and restored lands; impact affected lands, property owners, and area residents a second time … and impact anew and prolong (by years) the impacts on the environment,” concluded the Federal Energy Regulatory Commission’s Office of Energy Projects. The conclusions, which require commission approval and are not a formal decision, were issued Friday as part of a mammoth 727-page document known as a draft supplemental environmental impact statement. The review evaluates restoration plans submitted by Atlantic Coast Pipeline for the closeout of that project, as well as for the related Supply Header project that would have shipped gas through Pennsylvania and West Virginia but has also since been cancelled. Those plans, developed by pipeline owners Dominion Energy and Duke Energy, called for leaving already installed pipe in place, removing 83 miles of trees that had been felled but not cleared, restoring another 83 miles of cleared and graded land and backfilling and reclaiming sites where facilities were being constructed. FERC staff concurred with many of the proposals except for the plan for removing felled trees, which it said should be left in place unless landowners object. “Several years have passed since the trees were felled; vegetation has grown up around the felled trees and wildlife now occupies this vegetation/habitat. As they exist today, we generally believe that conditions in these areas can be considered akin to natural succession and a benefit to restoration/stabilization,” the draft supplemental EIS says. Staff concede, however, that leaving the trees in place “can also be considered as an impediment to land use and potentially inhibit landowner access to parts of their property.””Where landowners prefer removal of felled trees that were not previously cleared … Atlantic should remove the felled trees from the landowner tract,” they write. Dominion spokesperson Aaron Ruby said Atlantic Coast is still “carefully reviewing” the document.What FERC’s draft review doesn’t settle is the thorny question of what will happen to the more than 2,600 permanent easements covering 4,290 acres that Atlantic Coast obtained from landowners over the course of its years-long work on the project.
FERC Approves Plan to Restore Aborted Atlantic Coast Pipe ROW – Atlantic Coast Pipeline (ACP) had laid 31 miles of pipeline and had cut trees for 222 miles along the 600-mile route before Dominion Energy, the builder, decided last summer it no longer wanted to be in the interstate pipeline business, canceling ACP (seeDominion Cancels Atlantic Coast Pipe, Sells Pipe Biz for $9.7B). In January of this year, Dominion filed a plan with the Federal Energy Regulatory Commission (FERC) to clean up and “undo” the project (see Dominion Files Plan with FERC to “Undo” Atlantic Coast Pipe Work). Yesterday FERC pretty much endorsed Dominion’s clean-up plan, with one exception … In a Draft Supplemental Environmental Impact Statement issued yesterday, FERC concurred with Dominion’s plan to leave the 31 miles of pipeline already in the ground, buried, and covered over long ago. However, some 83 miles (out of 222 miles) of downed trees still remain in the right-of-way (ROW). Dominion planned to clear away those trees, which have been sitting rotting in the ROW for several years now. FERC says wildlife and vegetation have taken up residence in those downed trees and it’s best to leave them alone-unless a particular landowner wants them removed.What about the easements themselves (see What Happens to Leased Land for Now-Canceled Atlantic Coast Pipe?)? Will landowners get control back over their property? Will Dominion sell the easements to another company?There’s still no clear answer to that question. Dominion says it will NOT give back ownership of the easements to landowners-Dominion will retain ownership of those easements. When asked if the company will sell the easements to another company for another project, Dominion said they “have no plans to do so at this time,” which we take as double-speak for yes they will sell the easements to another interested company, they just don’t have anyone lined up right now. Here’s a summary of FERC’s mammoth 727-page Draft Supplemental EIS for Atlantic Coast Pipeline and the related Supply Header Restoration Project (full copy embedded below):A federal review of a plan to restore land disturbed by construction of the Atlantic Coast Pipeline prior to its cancellation in July 2020 recommends that some 31 miles of installed pipeline and 83 miles of trees felled f or the project be left in place to minimize further disturbance to wildlife and vegetation.“Overall, we believe removing the installed pipe would destabilize currently stable and restored lands; impact affected lands, property owners, and area residents a second time … and impact anew and prolong (by years) the impacts on the environment,” concluded the Federal Energy Regulatory Commission’s Office of Energy Projects.The conclusions, which require commission approval and are not a formal decision, were issued Friday as part of a mammoth 727-page document known as a draft supplemental environmental impact statement.The review evaluates restoration plans submitted by Atlantic Coast Pipeline for the closeout of that project, as well as for the related Supply Header project that would have shipped gas through Pennsylvania and West Virginia but has also since been cancelled.Those plans, developed by pipeline owners Dominion Energy and Duke Energy, called for leaving already installed pipe in place, removing 83 miles of trees that had been felled but not cleared, restoring another 83 miles of cleared and graded land and backfilling and reclaiming sites where facilities were being constructed.
Fiscal Court discusses Pike gas shut-off –During the July 20 meeting of the Pike County Fiscal Court, Judge-Executive Ray Jones addressed the recent actions taken by a local company which resulted in 100 residences losing natural gas service, perhaps permanently. Kinzer Drilling, according to a statement from the company, shut down its line due to ‘numerous leaks and imminent threat’ without warning to either the customers or to Kentucky Frontier Gas that sold the gas to the customers. In a statement, Kinzer Drilling said the lines had deteriorated to the point that repairs wouldn’t be possible. “The fiscal court has no ability to regulate natural gas utilities,” Jones said during the meeting. “Even the Kentucky Public Service Commission could not regulate the line that was abandoned.” “Mr. Steve Shute with Kentucky Frontier has informed me that they have offered to assume responsibility for the line and they would take steps to do some triage on the line to detect any serious leaks and to repair,” Jones said. “Then, they would undertake replacing any section of the line that would need to be replaced.” However, Jones said, he has learned that Kinzer has not been willing to do that. “Unfortunately, I have learned that Kinzer Drilling has told Kentucky Frontier that they would not agree to convey the line under those terms and that the line be abandoned and they would not turn the gas back on,” Jones said.
GOP members press FERC on whether it will deny gas projects over climate impact | S&P Global Platts –US Federal Energy Regulatory Commission Chairman Richard Glick faced questioning from Republican House members July 27 on whether his increased attention to greenhouse gas emissions would prompt the commission to reject applications for interstate natural gas projects. Their questioning and concerns over whether FERC was cooling on natural gas and other fossil fuels came during an oversight hearing on the commission’s role in the changing energy landscape held by the House Energy and Commerce Committee’s energy subcommittee. Since becoming chairman in January, Glick has worked to increase consideration of climate impacts in FERC’s gas pipeline project reviews, an area that continues to divide the commission. Representative David McKinley, Republican-West Virginia, asked Glick what level of GHG emissions would be acceptable to allow FERC to approve a pipeline, since the commission has not yet laid out metrics for determining the significance of emissions. And he highlighted the views in a dissent by Republican FERC Commissioner James Danly suggesting FERC lacks expertise and regulatory authority to make such a determination. Glick frequently pointed to appeals court rulings to explain the shifts in FERC’s approach. The DC Circuit Court of Appeals has “twice told US that we actually have to assess these reasonably foreseeable greenhouse gas emissions,” Glick said. He avoided identifying a threshold of acceptable GHG gas emissions for a project, saying, “I don’t want to prejudge the matter because it’s currently being litigated at FERC.” Representative Tim Walberg, Republican-Michigan, worried that FERC may be “vastly overstepping its jurisdiction by viewing all decisions through an environmental lens, instead of putting reliability and affordability for the customer first.” He asked Glick whether he believed FERC has statutory authority to deny a permit “solely because of climate change concerns.” Again leaning on appeals court findings, Glick said the courts on “numerous occasions” have told FERC that if environmental concerns are significant enough to outweigh benefits and those impacts could not be mitigated, then FERC could technically reject a certificate, though Glick noted FERC had not yet done so. FERC could, however, require a pipeline to mitigate such impacts and would not necessarily have to deny a project, Glick added. Representative Bill Johnson, Republican-Ohio, sought to pin Glick down on whether he broadly supports LNG export expansions, and on whether FERC would consider downstream climate benefits of LNG. “On a case-by-case basis,” Glick said he thought there were LNG exports that serve the public interest. But, he told Johnson that FERC cannot look at the emissions impacts of LNG projects downstream. “Courts have told us that’s for the Department of Energy, not FERC,” he noted.
FERC climate reviews: CO2 solution or chaos? – The Federal Energy Regulatory Commission took an unprecedented step earlier this year by assessing a proposed natural gas pipeline’s contribution to climate change for the first time ever.But some FERC experts and environmental advocates say they’re concerned that the agency lacks clear criteria for analyzing the greenhouse gas emissions of other gas projects – a gap they say raises legal questions and weakens a process critical to determining whether large amounts of U.S. fossil fuel infrastructure are approved and built.In March, FERC released an order detailing its new process for greenhouse gas reviews, before ultimately approving the gas project undergoing the first-of-a-kind climate analysis (Energywire, March 19). Under FERC’s framework, greenhouse gas assessments will be done for energy projects when a proposal could have “arguably significant” impacts, according to the agency.”In future proceedings, the evidence on which the Commission relies to assess significance may evolve as the Commission becomes more familiar with the exercise,” the majority of commissioners wrote in the order, issued March 22.However, FERC hasn’t yet established a methodology for analyzing a project’s climate-warming emissions, according to environmental impact statements put out by the independent agency this month and last. In the six draft environmental impact statements FERC issued for pending natural gas projects this year, agency staff concluded that it could not determine whether their emissions would be unacceptably high, citing the lack of an agreed-upon standard.They also could not “find an established threshold” for determining the importance of the projects’ emissions relative to state and federal greenhouse gas emissions reduction targets, according to the draft statements.”We are unable to come to a significance determination regarding the Project’s impacts on climate change. However, we acknowledge the Project would increase the atmospheric concentration of GHGs, in combination with past and future emissions from all other sources and would contribute to climate change,” the agency wrote in a draft statement issued this month for Kinder Morgan Inc.’s Evangeline Pass Expansion Project.
McKinley: Criteria for Federal Pipeline Environmental Review Don’t Add Up – U.S. Rep. David McKinley was not satisfied Tuesday with answers from the chairman of the federal agency that approves new natural gas pipeline construction over criteria for approvals, including climate change concerns. The U.S. House of Representatives’ Energy and Commerce Subcommittee met Tuesday for a hearing, titled “The Changing Energy Landscape: Oversight of FERC.” FERC, the Federal Energy Regulatory Commission, regulates the transmission of electric and natural gas utilities across state lines. Part of that role involves regulating the transportation of oil and natural gas through pipelines. The agency recently started assessing the potential climate change effects of new pipeline construction. According to E and E News, FERC released an order laying out its new criteria for greenhouse gas reviews. The new rule was first used to assess the climate change effects of Northern Natural Gas Company’s project to build and replace more than 87 miles of pipeline between South Dakota and Nebraska. “Going forward, we are committed to treating greenhouse gas emissions and their contribution to climate change the same as all other environmental impacts we consider,” said FERC Chairman Rich Glick in a March statement. “A proposed pipeline’s contribution to climate change is one of its most consequential environmental impacts and we must consider all evidence in the record – both qualitative and quantitative – to assess the significance of that impact,” Glick continued. “I look forward to continuing to work with my colleagues as we refine our methods for doing so.” The final order came about after years of disagreements between FERC commissioners. It’s also unclear what the methodology behind the climate change assessments is. McKinley, West Virginia’s Republican 1st District congressman, questioned Glick about the methodology Tuesday. “I’m curious. If by taking this unprecedented action, I’m assuming, by extension, you could deny a pipeline to be constructed,” McKinley said. “If that’s true, what level of (carbon dioxide) emissions are going to be acceptable from a natural gas power plant? “What’s the level? Because you can determine that it makes a significant increase in emissions, so therefore you’re going to deny the pipeline,” McKinley continued. “Everything I’ve read so far, you don’t have a determination. You don’t have metrics on that. What is it that you think would be the appropriate level of CO2 emissions out of a gas-fired power plant that would allow you to approve the pipeline?” Glick told McKinley that according to a 2017 ruling by the U.S. Court of Appeals for the District of Columbia, FERC must consider greenhouse emissions impacts of power plants being served by pipelines undergoing a review through the National Environmental Policy Act. “The D.C. Circuit twice told us that we actually have to assess these easily foreseeable greenhouse gas emissions, so we’re trying to do that,” Glick said. “Obviously, we have disagreements among the commissioners to what level might be significant from my perspective.”
How the FERC sets oil and gas pipeline rates – Oil and gas pipeline regulation have two things in common: They’re both regulated by the Federal Energy Regulatory Commission (FERC), and they were both brought under regulatory oversight in the first place by a Roosevelt – oil pipelines by Teddy Roosevelt and gas pipelines by Franklin Roosevelt. However, that’s where the similarities end. They’re regulated under different statutes, with wildly different histories that have led to very different types of oversight and rate structures. These rules tend to offer oil pipelines a higher degree of flexibility, but in doing so, they also make their rate structures less predictable. Today, we wrap up our review of oil and gas pipelines, and how their separate histories led to the current differences in pipeline rate structures, this time with a focus on oil pipeline ratemaking.In Part 1, we discussed how crude oil and natural gas pipeline regulation in the U.S. developed. Both sectors have been under the purview of FERC since the 1970s. Oil pipeline oversight by the federal government started with the enactment of the Hepburn Act of 1906, which modified the Interstate Commerce Act, adding oil pipelines to the list of the Interstate Commerce Commission’s (ICC) concerns. The ICC’s primary focus was on providing producers with common-carrier access to crude oil pipelines. Federal regulation of natural gas pipelines didn’t kick in until 1938 with the enactment of the Natural Gas Act (NGA), which put regulation of gas pipelines in the hands of the Federal Power Commission (FPC), an entity that was created in the 1920s to regulate interstate electricity transactions. The Energy Organization Act of 1977 transformed the FPC into the FERC, which also became responsible for the regulation of oil pipelines. That’s pretty much how it’s been ever since, though the Energy Policy Act of 1992 made some revisions to how FERC regulates oil pipelines (see timeline for oil and gas pipelines regulation in Figure 1).In Part 2, we delved further into how the evolution of natural gas pipeline regulation has shaped transportation ratemaking and service structures – from the days when pipelines were the buyers and sellers of natural gas and prices for gas sold to interstate pipelines were regulated by the feds, to the early 1990s, when FERC Order No. 636 restructured the industry, taking pipelines out of the gas buying-and-selling business and joining with the Wellhead Decontrol Act of 1989 to deregulate gas commodity prices (see timeline in Figure 1). The mess that led to restructuring and deregulation started in 1954, when major dislocations grew between prices for gas on interstate pipelines, which were federally regulated, and intrastate pipelines, which fell outside federal jurisdiction. For the next 45 years, the gas industry had every kind of dysfunction, from severe shortages to massive rate increases, wild statutory swings in the legal prices for wellhead gas, and an industry drowning in overpriced gas. With wellhead deregulation in 1989, Order No. 636 restructuring in 1993, and the advent of shale gas abundance in the early 2000s, the natural gas industry climbed out of its 45-year pit. Today, the gas industry is healthy and transparent.
North American Pipeline Project Roundup: July/August 2021 – North American Oil & Gas Pipelines – Project Roundup is a monthly feature that summarizes the contracts awarded for pipeline projects in North America. The following oil and gas pipeline projects have been announced. Projects are in order of most recent approximate starting date. All projects are for 2021 unless noted. (details on 25 projects)
Activists Have Shut Down a Memphis-Area Pipeline — But Their Fight Isn’t Over – As the dust settles on their victory, the coalition of activists and community members that opposed the Byhalia Connection oil pipeline in greater Memphis, Tennessee – which developers officially canceled on July 2 – are continuing to mobilize, because they say a risk to the land, water, climate and community remains.In step with the cancellation, Plains All American Pipeline has requested state and federal agencies to revoke necessary permits for the Byhalia Connection – what would have been a 49-mile route connecting a refinery in Memphis to an oil terminal in northern Mississippi, running through a series of majority-Black neighborhoods in Tennessee. The pipeline was a joint venture between Plains and Valero Energy Corporation.As MLK50reported shortly after the announcement, developers have said that community members who received compensation can keep it. But as with the canceled Keystone XL and Atlantic Coast pipelines, developers still retain indefinite rights to access parts of privately owned land along the canceled route. Justin J. Pearson, co-founder of Memphis Community Against the Pipeline (MCAP), told Truthout that having an out-of-state company continue to own land access is exploitative. “That’s another injustice on top of the injustice of having someone knock on your door and tell you, if you don’t sell your land we’re going to sue you,” he said, referring to developers’ use of eminent domain in obtaining easements in low-wealth communities. “It’s violence upon people’s bodies and people’s souls having to be treated this way.”Anti-pipeline organizers around the country concur, noting that the retaining of indefinite rights leaves the possibility of future disenfranchisement wide open.”It’s a one-time payment for a lifetime of risk,” Nebraska organizer Jane Kleeb told Truthout. Kleeb is the founding director of Bold Nebraska, which helped lead opposition to the Keystone XL Pipeline. “There’s no reason why a pipeline company needs a forever-agreement,” she said.George Nolan, a lawyer with the Southern Environmental Law Center who has represented MCAP and other community partners, told Truthouta lawyer representing the cancelled project said they would consider requests to return easements to Memphis landowners who pay the company back on a “case-by-case” basis, noting that it remained to be seen how the company planned to handle their control of easements in Mississippi. “A problem with that approach by the pipeline company is that this happened during a pandemic and I’m presuming that many folks just may no longer have the money,” Nolan said, adding that in some cases, compensation from the company may have gone to paying back taxes.
Spire Missouri chief says STL pipeline closure would create winter service risk — With this past winter’s severe weather still top of mind, Spire Inc.’s Missouri gas utility is already looking to the next major cold snap. If the region experiences a deep chill without access to the Spire STL Pipeline, Spire utility executives warn, hundreds of thousands of customers could lose service. Spire STL delivers Rocky Mountain and Appalachian natural gas to the St. Louis area, including to its affiliate gas utility, Spire Missouri Inc. A recent court decision found that federal regulators had not sufficiently scrutinized whether Spire STL demonstrated a valid market need for the project. The court sided with the Environmental Defense Fund, finding the group had “identified plausible evidence of self-dealing” in Spire STL’s reliance on affiliate contracts to show the pipe was necessary. The court’s decision could lead to a shutdown of the pipeline, which went into service in November 2019. But Spire Missouri President Scott Carter, also Spire’s COO of distribution operations, said that the pipe had played a crucial role in maintaining service in eastern Missouri during February’s extreme cold snap, and that shutting it down could leave Spire Missouri unable to meet peak winter demand. “This is reality for me. I don’t sit on extra capacity just in case some court two years later shuts down the operation of a pipeline,” Carter said told S&P Global news reporters. “I’m hoping that as we move through the process, we can put the facts on the table that support the benefits of the pipeline, the criticality of the pipeline.” When the U.S. Court of Appeals for the District of Columbia Circuit panel vacated the Federal Energy Regulatory Commission’s 2018 certificate authorizing the pipeline project, the panel found that FERC did not adequately consider arguments that Spire STL’s sole precedent agreement to deliver gas to affiliate Spire Missouri was not enough to establish public need. While it is not uncommon for pipelines to use contracts with affiliates to pass the public need test or for project opponents to challenge that need, limited demand growth and Spire STL’s reliance on a single contract stands out, especially in a climate-conscious era of heightened scrutiny around pipeline development. Natural gas pipeline opponents have already seized on the Spire STL ruling to bolster arguments for more analysis in other pipeline cases.FERC and Spire, however, have maintained that affiliate contracts should be treated the same as unaffiliated contracts.
Kinder Morgan’s Elba Liquefaction receives highest gas deliveries since July 1 – Feedgas demand at Kinder Morgan’s Elba Liquefaction terminal in Georgia reached its highest level in three weeks July 23, as strong international prices spur high utilization at US export terminals. The smallest of the six major US liquefaction facilities has yet to have all 10 of its trains operating at the same time, as one remains offline since a 2020 fire.Persistent Chinese import strength, strong power-sector driven LNG demand in South Korea and flat Asian LNG supply year on year means that Asia’s pull on Atlantic Basin supply is expected to grow nearly 100 million cu m/d through the balance of summer, S&P Global Platts Analytics estimates. Together with the strong pricing environment, that should continue to incentivize US export activity.Gas deliveries to Elba, near Savannah, registered approximately 312 MMcf/d during the morning cycle July 23. That was the highest level since July 1, Platts Analytics data show.Total US LNG feedgas demand was re-approaching 11 Bcf/d — a level it last surpassed July 14 — as Northeast Asian spot prices remained comfortably above $14/MMBtu.Two major US exporters, Cheniere and Sempra, are preparing to release their second-quarter financial results, and their outlooks will be closely watched by the market. Kinder Morgan said in its recent earnings report that the strength in LNG feedgas demand was a key reason why total gas volumes on its pipelines rose quarter over quarter. In May 2020, a fire occurred in a mixed refrigerant compressor of Elba’s Unit 2. Two adjacent units that were shut down as a precaution were later brought back online, though Unit 2 has remained offline since then.Earlier this year, Kinder Morgan said it may be able to restore service to Unit 2 in the fourth quarter.Elba, with a capacity of 2.5 million mt/year, is supported by a 20-year contract with sole offtaker Shell. It shipped its first cargo in December 2019.The terminal — originally built to import LNG and later converted to handle exports after the US shale revolution — utilizes Shell’s Movable Modular Liquefaction System design. Kinder Morgan is the majority owner in a joint venture that holds the terminal, while investment funds managed by EIG Global Energy Partners have a 49% stake.
US weekly LNG exports increase another week – LNG exports from the U.S. increased this week, followed by Henry Hub prices, according to weekly data from the Energy Information Administration (EIA). EIA: US weekly LNG exports increase another week Courtesy of Cheniere For the period between 15 July to 21 July, in its latest Short-Term Energy Outlook, EIA reports that 21 LNG vessels departed the United States. Six ships departed from Sabine Pass, five from Freeport, four from Corpus Christi, three from Cameron, two from Cove Point, and one from Elba Island. They held a combined LNG-carrying capacity of 76 billion cubic feet. The Henry Hub spot price rose from $3.75 per million British thermal units (MMBtu) last Wednesday to $3.91/MMBtu this week. Natural gas deliveries to U.S. liquefied natural gas (LNG) export facilities averaged 10.4 Bcf/d, or 0.33 Bcf/d lower than last week.
Tellurian Executive Chairman Charif Souki on LNG, going green and the nuclear option –Charif Souki was faced with taking a company whose future seemed uncertain last year and positioning it to begin building a multibillion dollar liquefied natural gas terminal. It was a daunting, but not intimidating, task. Souki founded and led Houston-based Cheniere Energy, which became the nation’s first LNG exporter in early 2016. Forced out by investor Carl Icahn, who’d grown weary of his greater ambitions to keep expanding, Souki regrouped. With Martin Houston, he co-founded Tellurian Inc., another Houston-based liquefied natural gas company, only to see it flounder at the start of the pandemic. Tellurian laid off more than 40 percent of its 176 employees and slashed expenses in an attempt to save the Driftwood LNG project it was developing in Lake Charles, La. The proposed $16.8 billion facility lacked the contracts or financing to support construction, even though it held a federal permit to make and export more than 27.6 million metric tons of LNG per year. Now, as demand rises and supplies shrink, LNG prices have rebounded to the point that the timing is good for Driftwood to get underway. The facility would have the capacity to process and export a total of 27.6 million metric tons of LNG per year. The terminal would have 20 processing units, or trains, with a capacity of about 1.4 million metric tons per year each. The project, build over four phases, is expected to be completed in 2026. Global construction and engineering firm Bechtel has been tapped to work on Driftwood. Souki, the company’s executive chairman, addressed its projects, climate change and electric generation with the Houston Chronicle in late June. M
Cleaner burn: LNG producers make case for energy transition role — While liquified natural gas’ reputation has been sullied because of flaring in the Permian Basin and methane leaks into the environment, global demand for the super-chilled fuel shows it can still play a role in the transition to a cleaner energy future.LNG produces about half the carbon dioxide emissions of black coal when burned to generate electricity, and demand for the cleaner-burning fuel has been on the rise.”The use of natural gas in the power sector has helped the U.S. reduce its greenhouse gas emissions,” Kinder Morgan CEO Steven Kean said. “That’s a largely result of natural gas replacing coal in the power grid.”U.S. liquefied natural gas exports grew to record highs in the first half of 2021, according to the Energy Department, averaging 9.6 billion cubic feet per day, a 42 percent increase compared to an average of 2.8 billion cubic feet per day in the same period of 2020, according to the Energy Information Agency.A number of factors contributed to rising global demand, including the easing of COVID-19 restrictions and unplanned outages at export facilities in several countries, including Australia, Malaysia, Nigeria, Algeria and Norway.Also feeding the increase was new export capacity. Last year saw the final liquefaction units commissioned by Houston-based companies, including Freeport LNG’s facility on Quintana Island near Freeport; Cameron LNG’s project in Hackberry, La.; and Cheniere Energy’s Corpus Christi LNG. Other small-scale units were placed in service at Elba Island LNG, a joint venture between Kinder Morgan and EIG Global Energy Partners.The increase comes as producers make the case that LNG is a viable transition fuel, in part by seeking to lower their carbon footprint.Venture Global, a Virginia-based company, in May said it is investing in carbon capture and storage at the liquefied natural gas facilities Calcasieu Pass in Cameron Parish, La., and Plaquemines in Plaquemines Parish, La. Both plants are under development. That carbon sequestration project would store in underground saline aquifers the ground carbon dioxide that would otherwise flow to the surface, reducing greenhouse gas emissions.
August Natural Gas Futures, Cash Prices Surge Again – Natural gas futures on Monday advanced for a seventh consecutive session as robust domestic cooling demand and strong liquefied natural gas (LNG) export levels continued to drive up prices that are at their highest levels since 2018. The August Nymex contract advanced 4.2 cents day/day and settled at $4.102/MMBtu. The prompt month gained nearly 11% last week. September rose 4.0 cents on Monday to $4.082. NGI’s Spot Gas National Avg. gained 16.0 cents to $3.965 on Monday – after advancing four out of five sessions last week. “With the hottest weather of the summer expected to extend nationwide” on Tuesday “and the potential for record electricity demand” in Texas, cash prices and futures were poised for another strong week, EBW Analytics Group said. Estimates Monday showed production around 91 Bcf, below recent highs, while weather-driven gas consumption kicked off the week at elevated levels, NatGasWeather said. “National demand will be strong this week as hot upper high pressure rules most of the U.S. with highs of 90s to 100s,” the firm noted. “Slightly cooler exceptions will occur over the Upper Great Lakes and New England, as weak systems produce highs of 80s, while very warm to hot with heavy monsoon showers over the Southwest.” NatGasWeather also noted that, with supplies tight in both Asia and Europe, global gas prices are lofty this summer, creating added demand for U.S. LNG exports and providing support for futures. LNG feed gas volumes on Monday hovered near 11 Bcf, near record levels.
U.S. natgas futures fall from 31-month high on less hot forecasts (Reuters) – U.S. natural gas futures fell over 3% on Tuesday from a 31-month high in the prior session on forecasts for less hot weather and a drop in demand for air conditioning next week. On its second to last day as the front-month, gas futures NGc1 for August delivery fell 13.1 cents, or 3.2%, to settle at $3.971 per million British thermal units (mmBtu). On Monday, the contract closed at its highest since December 2018 for a sixth day in a row. The September NGU21 contract, which will soon be the front-month, dropped 15 cents to around $3.93 per mmBtu. In the power market, next-day prices for Wednesday soared into the triple digits at several Western hubs, including the Mid Columbia EL-PK-MIDC-SNL in central Washington State and Palo Verde EL-PK-PLVD-SNL in Arizona as a heatwave settles over the region. In Texas, meanwhile, the Electric Reliability Council of Texas (ERCOT), the grid operator for most of the state, passed the first of what could be many tests over the next week by meeting very high demand on Monday without problem as homes and businesses crank up their air conditioners to escape the latest heatwave. Data provider Refinitiv said U.S. gas output in the Lower 48 states slipped to 91.5 billion cubic feet per day (bcfd) so far in July, due mostly to pipeline problems in West Virginia earlier in the month. That compares with an average of 92.2 bcfd in June and an all-time high of 95.4 bcfd in November 2019. Refinitiv projected average gas demand, including exports, would drop from 95.4 bcfd this week to 92.8 next week. The forecast for next week was lower than Refinitiv’s projections on Monday on expectations for less heat and air conditioning demand. The amount of gas flowing to U.S. liquefied natural gas (LNG) export plants averaged 10.8 bcfd so far in July, up from 10.1 bcfd in June but still below April’s 11.5-bcfd record. With European and Asian JKMc1 gas trading over $12 and $14 per mmBtu, respectively, analysts said buyers around the world would keep purchasing all the LNG the United States can produce. U.S. pipeline exports to Mexico have averaged 6.5 bcfd so far in July, down from a record 6.8 bcfd in June.
US working natural gas volumes in underground storage increase 36 Bcf: EIA – US natural gas storage fields added volumes above the five-year average for the third consecutive time for the week ended July 23, while the Henry Hub September contract, now the prompt month, surpassed $4/MMBtu. Working gas in storage increased by 36 Bcf to 2.714 Tcf for the week ended July 23, US Energy Information Administration data showed July 29. It was less than the 40 Bcf addition expected by an S&P Global Platts survey of analysts. It outgained the five-year average build of 28 Bcf and last year’s 27 Bcf injection in the corresponding week. Although it marked the third-consecutive above-average injection, the weekly builds have not registered strong enough to make a serious dent in the lingering deficit. Storage volumes now stand at 523 Bcf, or 16%, less than the year-ago level of 3.237 Tcf, and 168 Bcf, or 6%, less than the five-year average of 2.882 Tcf. Total supplies fell by 200 MMcf/d from the week prior to average 95.6 Bcf/d. Small gains in onshore production were canceled out by an equal decline in offshore receipts, leaving only a dip in net Canadian imports to drive supplies slightly downward on the week. Downstream, total demand was seen rising by about 500 MMcf/d, with much of that stemming from higher gas-fired power demand. Small net withdrawals were recorded in the Pacific and South Central regions for the second week in a row. Prices were up sharply by midday during the July 29 session, lifted by an inventory report that was generally lower than the consensus view, indicating markets were tighter than anticipated last week. With September now taking over the prompt-month position, balance-of-summer NYMEX Henry Hub prices were trading 8 cents higher on the day, building upon the 4 cents of gains from the July 28 session. This effectively unwound the sharp losses from July 27, when the summer contract strip fell by nearly 14 cents. Platts Analytics’ supply and demand model currently forecast a 16 Bcf injection for the week ending July 30, which would measure 14 Bcf less than the five-year average. The following week shows an injection matching the five-year average build of 42 Bcf.
Natural Gas Futures Spike as September Kicks Off Run as Prompt Month – Natural gas futures flew higher on Thursday, bolstered by strong fundamentals and a bullish government inventory report that reinforced concerns about supply/demand imbalance and the specter of anemic storage levels ahead of winter. The September Nymex contract, which took over as the prompt month on Thursday, jumped 9.2 cents day/day and settled at $4.059/MMBtu. A day earlier, August rolled off the board with a final settlement of $4.044. October gained 9.1 cents to $4.060 on Thursday. Meanwhile, NGI’s Spot Gas National Avg. on Thursday shed 6.0 cents to $3.870. Lofty temperatures permeated much of the Lower 48, but rain and cooler highs in the 70s waded into major markets in the East, including New York City and Boston, curbing demand and prices. Gas traded Thursday closed out July and will flow for Friday and Saturday, the final two calendar days of the month. Trading Friday will flow for Sunday and Monday. Importantly, the U.S. Energy Information Administration (EIA) on Thursday reported an injection of 36 Bcf natural gas into storage for the week ended July 23. The result proved bullish relative to market expectations and helped fuel a surge in futures. Prior to the report, major polls coalesced around a build of 42 Bcf. NGI modeled a 49 Bcf injection for the period. Steamy summer conditions defined the covered week. “It was hotter than normal over the West and portions of the East Coast, while warm, showery and humid over much of the rest of the U.S.,” NatGasWeather said. It had expected a build around 42 Bcf. Bespoke Weather Services, which had modeled a 41 Bcf build, said the EIA print amplified already pressing worries about supplies. “This is another very tight number, supply/demand balance-wise, reinforcing our view that we simply do not have enough supply here and now to alleviate storage concerns as we head toward the winter season,” Bespoke said. The firm noted that production has held close to 91 Bcf most days in July, below the 92 Bcf/d average in June. It has been even further below the roughly 93 Bcf/d level Bespoke said may be necessary to keep pace with seasonally strong power demand and exports of liquefied natural gas (LNG) levels. LNG feed gas volumes have come in shy of 11 Bcf most days over the past two weeks and are widely expected to exceed that level – and approach record volumes – once summer maintenance work at export facilities wraps up. Demand from both Asia and Europe, where gas stocks are light, is running high and shows no sign of abating.
September Natural Gas Futures Flounder Despite Bullish Setup for Balance of Summer; Spot Prices Sag – Natural gas futures faltered on Friday as traders took profits and markets focused on a near-term shift in weather that is expected to usher in a reprieve from the oppressive heat that has defined the summer to date over much of the Lower 48. The September Nymex contract dropped 14.5 cents day/day and settled at $3.914/MMBtu. A day earlier, in its debut as the prompt month, September rallied 9.2 cents. Futures had advanced more than 11% to that point in July. October shed 14.0 cents to $3.920 on Friday. NGI’s Spot Gas National Avg. retreated 12.5 cents to $3.745. “National demand will ease to much lighter levels” over the coming week “as weather systems sweep across much of the eastern half of the U.S. with highs of upper 60s to lower 80s,” NatGasWeather said. The firm projected the coolest conditions across the Great Lakes and Northeast. “It will still be hot next week over the West and Plains, including much of Texas, but not enough to counter” the comfortable conditions in the East. Meanwhile, Texas Eastern Transmission Co. (Tetco) notified shippers ahead of trading Friday that it had received approval from federal regulators to return its 30-inch diameter system to full operating pressure, with capacity expected to increase by roughly 0.5 Bcf/d starting in the coming week. Bespoke Weather Services said this would “have some impact on Henry Hub pricing specifically.” However, the firm doesn’t see the restored capacity “significantly affecting the supply/demand balance,” and it anticipates a return of upward pressure on prices in August.
Natural Gas Rig Count Drops to 103 as GOM Activity Slows – The U.S. natural gas rig count slipped one unit to 103 for the week ended Friday (July 30) as a pullback in the Gulf of Mexico (GOM) dragged the overall domestic tally lower, the latest data from Baker Hughes Co. (BKR) show. Declines in the United States also included two oil-directed rigs, leaving the combined count at 488 active rigs as of Friday. That’s nearly double the 251 rigs running in the year-ago period, according to the BKR numbers, which are based partly on data from Enverus.The GOM saw three rigs exit during the period, lowering its total to 14 versus 12 a year ago. Land rigs remained unchanged at 473, while one rig continued to operate in inland waters. Four directional units and two vertical units exited overall for the week, partially offset by the addition of three horizontal units.The Canadian rig count, meanwhile, added four rigs – all natural gas-directed – to raise its total for the week to 153, up from 45 a year ago.In terms of changes by major basin, BKR recorded a one-rig decrease in the Haynesville Shale for the week. The Granite Wash, Marcellus Shale, Permian Basin, Utica Shale and Williston Basin each saw a net increase of one rig week/week.Broken down by state, Louisiana posted the largest net loss for the week, dropping four units from its total to fall to 48, versus 29 a year ago. Utah saw a net loss of two rigs week/week, while Colorado and New Mexico each dropped one unit from their respective totals.Meanwhile, Texas added two rigs during the period, while North Dakota, Ohio and Pennsylvania each added one rig, the BKR data show.The upstream oil and natural gas economy in Texas is finally signaling a new cycle of expansion in activity following the double-barrel contraction in 2019 and 2020, according to economic indicators.The Texas Petro Index (TPI), created and overseen by petroleum economist Karr Ingham of the Texas Alliance of Energy Producers, through June had increased for three straight months and four of the last five months. The index improved to 147.2 in June from 143.1 in May. Still, the state remains in recovery mode, as the index was down by 7.2% from the June 2020 score of 158.6.
Shell greenlights development of US Gulf of Mexico Whale field – Shell made July 26 a final investment decision on Whale, a deepwater discovery in the US Gulf of Mexico, amid an offshore operating environment that appears to be one of the oil and natural gas industry’s brighter operating arenas as recovery ticks up from 18 months of a coronavirus pandemic. Whale, located in the remote Alaminos Canyon area of the Gulf of Mexico about 200 miles southwest of Houston, will feature a semi-submersible production host in more than 8,600 feet of water with 15 producing oil wells, Shell said in a statement. The field was discovered in early 2018. Whale is expected to produce a gross 100,000 barrels of oil equivalent a day at peak production and currently has estimated gross recoverable resources of 490 million boe. The development reflects Shell’s ongoing focus on “simplification, replication and capital projects with shorter cycle times” that drive greater value from advantaged positions, Wael Sawan, Shell Upstream Director, said. “We are building on more than 40 years of deepwater expertise to deliver competitive projects that yield high-margin barrels [to] meet the energy demands of today” while also generating cash required to fund the development of energy of the future, Sawan said. The development will also sport a hull that is 99% replicated from Vito that is currently under development, as well as an 80% replication of Vito’s topsides.
Local chemical services business to consolidate, relocate to outskirts of Lafayette-area | Coastal Chemical Co. LLC plans to spend $11.4 million consolidating several sites in Louisiana and Texas into one location in Maurice, outside of Lafayette, in Vermilion Parish. Coastal Chemical was founded in 1958 and is a service business for major oil and gas operators both on land and offshore. Coastal Chemical works with companies in North and South America, primarily with pipeline businesses selling products to maintain infrastructure. The company sells natural gas, engine oils, specialty lubricants, industrial coolants and specialty additives. The company touts itself as one of the largest resellers of ExxonMobil lubrications in the U.S. Coastal’s plans include retrofitting its Maurice facility near the intersection of La. 92 and Winfred Road. That will require expanding its tank farm, warehouse, laboratory and office. The company plans to consolidate operations from two Louisiana sites: a business office and distribution center in Abbeville and distribution and sales office in Broussard into its Maurice facility. It also will consolidate its Pasadena, Texas, operation, according to an advance notification on file with the state for tax incentives.
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