Written by rjs, MarketWatch 666
Here are some selected news articles from the week ended 03 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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Oil prices hit new 32 month high, natural gas at a 30 month high, largest 4 week drop in US crude supplies on record
Oil prices hit a new 32 month high again this week, their sixth consecutive week testing the October 2018 highs, as US crude supplies again fell sharply, while OPEC failed to reach an agreement on production cuts for the remainder of this year… after rising 3.9% to $74.05 a barrel last week after negotiations to lift Iranian sanctions broke off and US crude supplies fell more than was expected, the contract price of US light sweet crude for August delivery opened lower on Monday on a decline in the Asian markets, and later tumbled to finish down $1.14 or 1.5% at $72.91 a barrel, as a spike in COVID-19 cases in Asia and Europe cut off a rally heading to new 32 month highs…oil prices steadied on Tuesday, as broad hopes for a demand recovery were fueled by comments from OPEC’s secretary general, and settled 7 cents higher at $72.98 a barrel as traders awaited a Thursday meeting of OPEC and its allies, when fairly modest production increases were expected…oil prices then opened 49 cents higher on Wednesday on a Reuters report that OPEC+ was expected to discuss the extension of the oil supply cuts beyond April 2022 after data from the American Petroleum Institute showed an unexpectedly large draw in US crude inventories, and held those gains to settle at $73.47 a barrel after the EIA confirmed that U.S. crude stockpiles fell for a sixth straight week and an OPEC report foresaw an undersupplied market this year…oil prices drifted sideways early Thursday, as traders awaited a decision from OPEC+ on whether they would maintain or ease supply cuts in the second half of the year, but then rallied to close $1.76 higher at a 32 month high of $75.23 a barrel after talks among the OPEC+ alliance ended with no final agreement on production policy, on the belief that the expected OPEC production hike of 400,000 or 500,000 barrels per day would not be enough to keep prices down….oil prices steadied on Friday, as traders stayed on the sidelines as the OPEC+ talks dragged on, and settled 7 cents lower at $75.16 a barrel after OPEC+ ended Friday’s meeting without a deal, with plans to seek an agreement on oil output policy on Monday…despite that, oil prices still finished the week 1.5% higher, again with the highest weekly close since October 2018..
Natural gas prices rose to a 30 month high as an unprecedented heat wave demolished all time record high temperatures across the Pacific Northwest and Canada…after rising 8.7% to a 29 month high of $3.496 per mmBTU last week as exports rose and domestic gas inventories remained well below normal, the contract price of natural gas for July delivery opened higher on Monday and quickly jumped 4% to a 30 month high as “virtually unheard of” temperatures continued to smother the Pacific Northwest, leading to pipeline issues and amplified demand, before prices settled 12.1 cents higher at $3.617 per mmBTU as trading in the July gas contract expired…at the same time, the more actively traded contract price of natural gas for August delivery, which had been priced at 3.520 per mmBTU going in, rose 7.3 cents to settle at $3.593 per mmBTU…August gas prices rose from that point on Tuesday, climbing 3.7 cents or 1% to $3.630 per mmBTU, as oppressive heat led to more shattered records and rolling blackouts in the Pacific Northwest, while New England also saw temperatures and power demand much above normal...natural gas prices rose to a fresh 30-month high on Wednesday on soaring global gas prices and forecasts for higher U.S. air-conditioning demand over the next two weeks than was previously expected, and then edged up 1.1 cents to another 30 month high on Thursday, as traders brushed off a large miss in the latest government storage report amid uncertainty created by a sharp decline in production…natural gas prices rose for a ninth consecutive day on Friday on curtailment of a pipeline in West Virginia and on natural gas prices exceeding $12 per mmBTU in Asia and Europe, settling up another 3.9 cents at $3.700 per mmBTU and thus finishing 5.1% higher on the week…
The natural gas storage report from the EIA for the week ending June 25th indicated that the amount of natural gas held in underground storage in the US rose by 76 billion cubic feet to 2,558 billion cubic feet by the end of the week, which still left our gas supplies 510 billion cubic feet, or 16.6% below the 3,068 billion cubic feet that were in storage on June 25th of last year, and 143 billion cubic feet, or 5.3% below the five-year average of 2,701 billion cubic feet of natural gas that have been in storage as of the 25th of June in recent years… the 76 billion cubic feet increase in US natural gas in storage this week was well above the average forecast of a 63 billion cubic foot addition from an S&P Global Platts survey of analysts, and was also above the average addition of 65 billion cubic feet of natural gas that have typically been injected into natural gas storage during the same week of June over the past 5 years, as well a bit above the 73 billion cubic feet that were added to natural gas storage during the corresponding week of 2020 …
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending June 25th showed that with a sizeble decrease in our oil imports and a modest increase in our refinery throughput, we needed to withdraw oil from our stored commercial crude supplies for the eighth time in the past nine weeks, and for the 22nd time in the past thirty-three weeks … .our imports of crude oil fell by an average of 536,000 barrels per day to an average of 6,536,000 barrels per day, after rising by an average of 179,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 66,000 barrels per day to an average of 3,717,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 2,689,000 barrels of per day during the week ending June 25th, 602,000 fewer barrels per day than the net of our imports minus our exports during the prior week … over the same period, the production of crude oil from US wells was reportedly unchanged at 11,100,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production appears to total an average of 13,789,000 barrels per day during this reporting week …
Meanwhile, US oil refineries reported they were processing 16,299,000 barrels of crude per day during the week ending June 25th, 178,000 more barrels per day than the amount of oil they used during the prior week, while over the same period the EIA’s surveys indicated that a net of 1,160,000 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 1,350,000 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 (+1,350,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting there must have been a error or errors of that magnitude in this week’s oil supply & demand figures that we have just transcribed … ..furthermore, since last week’s EIA fudge factor was at (+390,000) barrels per day, that means there was a 961,000 barrel per day balance sheet difference in the unaccounted for crude oil figure from a week ago, thus rendering the week over week supply and demand changes that we have just transcribed nonesense … . however, since most everyone treats these weekly EIA reports as gospel and since these figures often drive oil pricing and hence decisions to drill or complete wells, we’ll continue to report them as they’re published, just as they’re watched & believed to be accurate by most everyone in the industry … .(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer) … .
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports rose to an average of 6,683,000 barrels per day last week, which was 2.8% more than the 6,504,000 barrel per day average that we were importing over the same four-week period last year … the 1,160,000 barrel per day net withdrawal from our crude inventories included a 960,000 barrel per day withdrawal from our commercially available stocks of crude oil, and a 200,000 barrel per day withdrawal from our Strategic Petroleum Reserve, space in which has been leased for commercial purposes … over the past four weeks, US crude inventories have been falling at a 1,153,000 barrel per day clip, the largest four-week decline of crude supplies in EIA records going back to 1982….this week’s crude oil production was reported to be unchanged at 11,100,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was unchanged at 10,700,000 barrels per day, while an 3,000 barrel per day increase in Alaska’s oil production to 448,000 barrels per day had no impact on the rounded national total … .US crude oil production had hit a pre-pandemic record high of 13,100,000 barrels per day during the week ending March 13th 2020, so this week’s reported oil production figure was 15.3% below that of our production peak, yet still 31.7% above the interim low of 8,428,000 barrels per day that US oil production had fallen to during the last week of June of 2016 …
US oil refineries were operating at 92.9% of their capacity while using those 16,299,000 barrels of crude per day during the week ending June 25th, up from 92.2% of capacity the prior week, but still a shade below normal for summertime operations … while the 16,299,000 barrels per day of oil that were refined this week were 16.1% higher than the 14,033,000 barrels of crude that were being processed daily during the pandemic impacted week ending June 26th of last year, they were still 5.7% below the 17,290,000 barrels of crude that were being processed daily during the week ending June 28th, 2019, when US refineries were operating at a close to summertime normal 94.2% of capacity …
Even with this week’s increase in the amount of oil being refined, the gasoline output from our refineries was lower, decreasing by 749,000 barrels per day to 9,578,000 barrels per day during the week ending June 25th, after our gasoline output had increased by 401,000 barrels per day over the prior week … while this week’s gasoline production was still 6.6% higher than the 8,905,000 barrels of gasoline that were being produced daily over the same week of last year, it was 3.7% lower than the gasoline production of 9,948,000 barrels per day during the week ending June 28th, 2019 … .meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 83,000 barrels per day to 5,029,000 barrels per day, after our distillates output had increased by 56,000 barrels per day over the prior week … while this week’s distillates output was 8.7% more than the 4,624,000 barrels of distillates that were being produced daily during the week ending June 26th, 2020, it was still 5.8% below the 5,336,000 barrels of distillates that were being produced daily during the week ending June 28th, 2019.., …
Despite the decrease in our gasoline production, our supply of gasoline in storage at the end of the week increased for the tenth time in thirteen weeks, and for the 24th time in thirty-three weeks, rising by 1,522,000 barrels to 241,572,000 barrels during the week ending June 25th, after our gasoline inventories had decreased by 2,930,000 barrels over the prior week...our gasoline supplies increased this week because the amount of gasoline supplied to US users decreased by 267,000 barrels per day to 9,173,000 barrels per day, and because our exports of gasoline fell by 449,000 barrels per day to 446,000 barrels per day, while our imports of gasoline fell by 50,000 barrels per day to 790,000 barrels per day … after this week’s inventory increase, our gasoline supplies were still 5.8% lower than last June 26th’s gasoline inventories of 256,521,000 barrels, but close to 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 ninth time in twelve weeks and for the 15th time in 28 weeks, falling by 859,000 barrels to 137,945,000 barrels during the week ending June 25th, after our distillates supplies had increased by 1,754,000 barrels during the prior week … .our distillates supplies fell this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, rose by 223,000 barrels per day to 4,170,000 barrels per day, even as our imports of distillates fell by 31,000 barrels per day to 245,000 barrels per day while our exports of distillates rose by 38,000 barrels per day to 1,228,000 barrels per day … after nine inventory decreases over the past twelve weeks, our distillate supplies at the end of the week were 21.3% below the 174,127,000 barrels of distillates that we had in storage on June 26th, 2020, and about 5% below the five year average of distillates stocks for this time of the year …
Finally, with the decrease in our oil imports and the pickup in our oil refining, our commercial supplies of crude oil in storage fell for eleventh time in the past nineteen weeks and for the 27th time in the past year, decreasing by 6,718,000 barrels over the week, from 459,060,000 barrels on June 18th to 452,342,000 barrels on June 25th, after our crude supplies had decreased by 7,614,000 barrels the prior week … .with this week’s decrease, our commercial crude oil inventories fell to about 6% below the most recent five-year average of crude oil supplies for this time of year, but were still over 30% above the average of our crude oil stocks as of the the 4th week of June over the 5 years at the beginning of the past decade, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels … .since our crude oil inventories had jumped to record highs during the Covid lockdowns of last spring, our commercial crude oil supplies as of this June 25th were 15.2% less than the 533,527,000 barrels of oil we had in commercial storage on June 26th of 2020, and are now 3.4% less than the 468,491,000 barrels of oil that we had in storage on June 21st of 2019, but are still 8.3% more than the 417,881,000 barrels of oil we had in commercial storage on June 22nd of 2018 …
This Week’s Rig Count
The US rig count was higher during the week ending July 2nd, after being unchanged the prior week, and rising 35 out of 40 weeks before that, but it’s still down by 40.1% from the pre-pandemic rig count … .Baker Hughes reported that the total count of rotary rigs running in the US increased by five to 475 rigs this past week, which was also up by 212 rigs from the pandemic hit 263 rigs that were in use as of the July 2nd report of 2020, but was still 1,454 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began to flood the global oil market in an attempt to put US shale out of business … .
The number of rigs drilling for oil was up by 4 to 376 oil rigs this week, after falling by 1 oil rig the prior week, and that’s also 191 more oil rigs than were running a year ago, while it’s still just 23.3% of the recent high of 1609 rigs that were drilling for oil on October 10th, 2014 … .at the same time, the number of drilling rigs targeting natural gas bearing formations was up by 1 to 99 natural gas rigs, which was also up by 23 natural gas rigs from the 76 natural gas rigs that were drilling during the same week a year ago, but still just 6.2% of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008 … .
The Gulf of Mexico rig count was unchanged at 14 rigs this week, with 13 of those rigs drilling for oil in Louisiana’s offshore waters and one drilling for oil offshore from Texas … .that was two more than the 12 rigs that were drilling in the Gulf a year ago, when 10 Gulf rigs were drilling for oil offshore from Louisiana and two more 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 … however, in addition to those rigs offshore, we continue to have 2 rigs drilling through inland bodies of water in southern Louisiana; with one in Terrebonne Parish, and the other in St Mary parish, Louisiana, whereas there were no such “inland waters” rigs running a year ago …
The count of active horizontal drilling rigs was up by 8 to 429 horizontal rigs this week, which was also up by 203 rigs from the 226 horizontal rigs that were in use in the US on July 2nd of last year, but less than a third of the record of 1372 horizontal rigs that were deployed on November 21st of 2014 … .at the same time, the directional rig count was unchanged at 30 directional rigs this week, but those were up by 10 from the 20 directional rigs that were operating during the same week a year ago … .on the other hand, the vertical rig count was down by 3 to 16 vertical rigs this week, and those were also down by 1 from the 17 vertical rigs that were in use on July 2nd 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 2nd, the second column shows the change in the number of working rigs between last week’s count (June 25th) and this week’s (July 2nd) count, the third column shows last week’s June 25th 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 a Thursday, the 2nd of July, 2020..
With oil prices near 3 year highs, drilling activity continues to pick up outside of the core areas in Texas and nearby states … .checking first for the details on the Permian basin in Texas from the Rigs by State file at Baker Hughes, we find that one oil rig was added in Texas Oil District 8, which is the core Permian Delaware, while the rig counts in all other Texas districts were unchanged, which thus gives us a net increase of one rig in the Texas Permian … elsewhere, we find that three oil rigs were added to the Denver-Julesburg Niobrara chalk in Colorado, which means that the rig that was stacked in Wyoming had been drilling in that same formation…meanwhile, the week’s other oil rig addition was in the Bakken shale of North Dakota’s Williston basin, while this week’s lone natural gas rig change was the addition of a rig in Pennsylvania’s Marcellus…
Oil and gas industry in eastern Ohio weathers pandemic – On a recent Saturday in this small Harrison County community, a steady stream of big rigs passed through Deersville’s main street, headed to a well site owned by Encino Energy on the east edge of town. The site, known as the Deersville HN FRA Unit, will consist of four horizontal wells, which will be extracting oil and natural gas from 95 separate tracts of land in Franklin, Stock and Nottingham townships, according to the Ohio Department of Natural Resources. The drilling in the Deersville area is a sign that the oil and natural gas industry – which has been quiet in eastern Ohio for the past couple of years – hasn’t gone anywhere. The point I really try to make with folks is that the industry is still here. Oil and natural gas is still an important player in Ohio’s economy. “I understand it may have been a little quiet, and that’s not necessarily a bad thing because producers have still been doing what they do every single day, and that is making the essential energy that helps us lead our everyday lives in Ohio.” According to JobsOhio, the state’s economic development agency, about 200,000 Ohioans are employed by the oil and gas industry, more than in the US as a whole. “Direct employment is still very strong in Ohio,” Brown said. The industry continues to be centered in Harrison, Belmont, Jefferson and Carroll counties and surrounding areas. From 2011 to the second quarter of 2020, oil and natural gas companies have invested an estimated $90.6 billion in Ohio and have paid out more than $7.2 billion in royalties to Ohio landowners. The COVID-19 pandemic, which drove down consumer demand for oil and resulted in a slump in commodity prices, proved to be a trying time for the industry. But it didn’t cause a lull for Encino Energy operations in eastern Ohio. “The global pandemic had an impact on the oil and gas industry, but our approach was a steady hand with steadfast development,” said Jackie Stewart, director of external affairs for the company. In October 2018, Encino closed a $2 billion deal to buy Chesapeake Energy’s Utica Shale play assets in Ohio, acquiring about 900 operating and non-operating wells with about 900,000 acres of oil and gas leases. Encino is the second-largest producer of natural gas and oil in Ohio. Since that time, the company has had two rigs running in this part of the state, Stewart said. “The pandemic had an impact on everyone,” she said. “We knew that we had to do it better and be more efficient to be competitive.” She credited Encino’s success to a seasoned, experienced management team and the company’s core values and culture. “What you’re seeing is the result – a sustainable, long-term approach to development of the Utica Shale play,” Stewart said.
OH Legislature Passes Ban on NatGas Bans, Gov. Expected to Sign –The states that produce Marcellus and Utica Shale are ensuring no rogue local municipalities will get it into their heads to ban the use of natural gas like some municipalities in left-leaning states including California and New York. Both Pennsylvania and Ohio have bills that would “ban bans” of natural gas (see OH, PA Bills Prevent Natural Gas Bans by Local Municipalities). While PA’s bill is still making progress, the Ohio legislature has jumped ahead and just passed House Bill (HB) 201 to ban bans. The bill now goes to Gov. Mike DeWine who is sure to sign it into law. Local governments in Ohio would no longer be allowed to ban residents’ use of natural gas, under legislation approved Thursday by the state legislature. House Bill 201, which passed a final Senate vote 24-7, now heads to Gov. Mike DeWine. Proponents of the Republican-sponsored bill say prohibiting local natural gas bans will ensure residents have access to a reliable source of heat in the winter. While no Ohio cities have so far restricted natural gas use, dozens of cities on the East and West Coasts have voted to ban natural-gas hookups for new buildings to reduce emissions that cause global warming. “This would be an incredible problem for people across the Buckeye State if we don’t get out in front of this,” said state Sen. Rob McColley, a Northwest Ohio Republican, during a floor debate Thursday. Such bans, he said, would particularly hurt lower-income Ohioans who would pay more for electric heating. Opponents of HB201, including environmental and local-government groups, say the measure would violate “home-rule” authority granted to local governments by the Ohio Constitution. Similar bills prohibiting such bans have already been passed in Arizona, Tennessee, Oklahoma and Louisiana. Separate GOP-sponsored legislation, House Bill 192, would prohibit local bans on fossil fuels for power generation. However, that bill so far hasn’t advanced in the Ohio House.* *Cleveland (OH) The Plain Dealer (Jun 24, 2021) – Bill prohibiting local bans on natural gas use clears Ohio legislature
Resident shares oil and gas concerns – A local resident brought several concerns about oil and gas activity around Belmont County to the commissioners Wednesday. Jill Hunkler of the Barnesville area, a member of the activist group Concerned Ohio River Residents, has long voiced opposition to the industry and the practice of fracking. Among the issues she brought up Wednesday were concerns about the Austin Masters waste management facility in Martins Ferry. “We’ve been working with a coalition of local, state and national environmental groups to bring attention to this dangerous facility,” Hunkler said. “They are processing fracking waste.”Hunkler said there have been issues since 2017, saying there have been violations, issues related to worker safety, and concerns about its close proximity to a sports field nearby. She also said the Ohio Department of Natural Resources has not written sufficient regulations for such facilities.She asked the commissioners to speak to a fire chief from outside the area who has taken issue with these operations.Stephanie O’Grady, spokeswoman for the Ohio Department of Natural Resources, said via email that all oil and gas waste facilities must conform with the law and the Ohio Revised Code.“The Division has enforced violations of Chief’s Orders and/or violations of laws or statutes on several waste facilities that have included actions consisting of notice of violations, compliance agreements, and Chief’s Orders to suspend operations,” she said in an email. She also mentioned objections to the New Jersey-based Omni Energy Group’s planned saltwater injection well site at the intersection of U.S. 40 and Ohio 331. Since the drilling permit was issued at the end of 2020, work on the facilities have been ongoing despite local objections that the area is highly traveled and numerous government sites, residences and education centers are nearby.Hunkler mentioned an accidental fluid release at the site earlier this month and said the construction has inconvenienced and potentially endangered nearby residents.
DTE Energy Spinning Off Pipeline Business into New Company –Last October MDN told you that DTE Energy, a long-time pipeline builder and operator in the Marcellus/Utica region, was considering either selling or spinning off its pipeline business (see DTE Energy Explores Sale or Spin-Off of Pipeline Business). DTE, based in Detroit, is both a utility company and a midstream/pipeline company. The company’s season of pondering is over and the decision has been made. DTE will spin out the pipeline business into a new/separate company.In 2016, DTE purchased 100% of the Appalachia Gathering System (AGS) located in Pennsylvania and 55% of the Stonewall Gas Gathering (SGG) located in West Virginia (see DTE Energy Buys Marcellus/Utica Pipelines for $1.3B). In 2019 DTE bought another 30% stake in SGG (see DTE Midstream Buys Another 30% of WV Gathering System). The mighty NEXUS natural gas pipeline from Ohio into Michigan is a 50/50 joint venture between DTE and Enbridge. DTE also owns a minority stake in the Millennium Pipeline that runs from Corning, NY to the NYC area. (A section of the Millennium runs within a few miles of MDN HQ – we drive over it multiple times per week.)A map of DTE’s pipeline assets: All of those assets will become DT Midstream. David Slater, chief operating officer of DTE’s midstream business since 2014, will become CEO of the new company. The move to create DT Midstream is focused on creating shareholder value. It’s part of a wider trend in the industry of utilities becoming “pure-play” and, in this case, focused on the 2.2 million electricity customers in southeast Michigan and 1.3 million natural gas customers throughout the state. “For Michigan consumers, there will be no impact,” The spinoff will own 900 miles of interstate pipelines regulated by the Federal Energy Regulatory Commission that connect to multiple pipelines and local distribution companies. It also has 290 miles of pipelines that connect to mainlines, 94 billion cubic feet of gas storage and more than 1,000 miles of gathering pipeline. Most of the pipelines are not in Michigan, but in Louisiana, Ohio, Pennsylvania and other states.The Nexus Gas Transmission and Vector Pipeline L.P. lines do supply some of the natural gas for DTE customers’ heating and electricity.”Every interaction has to be kept at an arms-length,” said David Meador, DTE’s vice chairman and chief administrative officer. “There can’t be any benefit to one business or to the other. There’s very little financial interaction between the midstream side and utility.” DTE faced a slight delay in obtaining regulatory approval for the Nexus pipeline it owns with Enbridge Inc. The pipeline from eastern Ohio to southeast Michigan was supposed to open before the end of 2017, but began operation in 2018. DTE also has made several acquisitions of natural gas gathering systems and pipelines in Louisiana, northeast Ohio, Pennsylvania and West Virginia. It may also be beneficial for a utility to cut a tie-up with a natural gas transporter from an environmental and regulatory perspective, Karp said. – DTE spinning off DT Midstream natural gas pipeline business
Barges put health at risk – Pittsburgh Post-Gazette – Although our rivers are far from pristine, we have come a long way from the days when industrial pollution made these rivers unable to sustain aquatic life. We have the Clean Water Act to thank for that.Now, though, our rivers face a new threat: the barging of toxic wastewater from seven proposed terminals on all three rivers (“Network of companies looking to move fracking wastewater in barges up and down Pittsburgh’s rivers,” May 31).With terminals spanning Pennsylvania, West Virginia and Ohio, the barging of this waste, originating from the shale gas industry, puts at risk our drinking water, recreational opportunities and health.The shale gas industry produces a tremendous amount of toxic waste in liquid, sludge and solid forms. This waste is a public health concern because of its toxicity, radioactivity and lack of government oversight in its handling. Oil and gas waste is not classified or treated as toxic due to exemptions in federal legislation.Barges, although efficient modes of transportation, are not accident-proof. They may leak, spill, sometimes break loose, crash and even sink. Putting barges full of toxic waste into our rivers, which remember is a major source of drinking water for the region, is a surefire recipe for a public health disaster. Putting the health and well-being of our families at risk, just for the expediency of industry, is a practice we can and should avoid.
Pa. lawmakers want stricter regulations on fracking – WKBN.com – Democratic lawmakers introduced a slew of bills meant to tighten up regulations on Pennsylvania’s shale gas industry. The package of legislation came as a response to last summer’s grand jury report on the unconventional oil and gas industry. The report found the Pennsylvania Department of Environmental Protection failed to protect residents from the health impacts of hydraulic fracturing, or fracking. Pennsylvania Attorney General Josh Shapiro said, during a May 25 press conference announcing the bills, that the grand jury report found a gap between the public’s constitutional rights to clean air and water and the reality of the law. The legislation addresses the eight recommendations made by the grand jury, including expanding setbacks from 500 to 2,500 feet, requiring fracking companies to publicly disclose all chemicals used in drilling before they’re used and require safer transport of the fracking wasteIt would give the Pennsylvania Office of Attorney General criminal jurisdiction over environmental crimes. Current the attorney general’s office can only intervene after getting a referral from a local district attorney, the DEP or another agency with jurisdiction.The legislation would also limit the ability of Pennsylvania Department of Environmental Protection employees to work in the oil and gas industry immediately after leaving the department and regulate natural gas gathering lines, which are currently only regulated at the federal level.The grand jury report was released last June with a splashy press conference where Shapiro held up a jar of cloudy brown water. It was well water from a resident who said their water had been contaminated by fracking, he said. Shapiro recounted how residents told the grand jury about the various health issues they they suffered from living near unconventional drilling sites, including sores, ulcers, rashes, breathing issues and stomach ailments. Pets and livestock became ill and some died, he said.”The grand jurors heard repeated testimony of small children waking up with severe nosebleeds. One parent testified that her 4-year-old daughter was waking up crying with blood pouring out of her nose,” Shapiro said, during the press conference.The report was the result of a two-year investigation that included testimony from 70 households. Current and former state employees also testified. The DEP responded to the report, saying it presented an “inaccurate and incomplete picture of Pennsylvania’s regulatory program.” The department defended itself in a 49-page response.
Commonwealth Court judge recuses himself from Murrysville fracking appeal case –A Commonwealth Court of Pennsylvania judge whose previous career included helping craft state fracking legislation has recused himself from a case involving local fracking laws. Judge J. Andrew Crompton issued an order Monday granting the Murrysville Watch Committee’s request that he recuse himself from the panel adjudicating its appeal. The committee is appealing a lower court ruling denying its challenge to the validity of Murrysville’s existing unconventional gas drilling ordinance. During his time as chief of staff for state Sen. Joe Scarnati and as a staff attorney for the General Assembly, Crompton helped craft the 2012 legislation known as Act 13, which addressed oil and gas operations statewide. In 2016, the state’s Supreme Court struck down a number of provisions in Act 13 as unconstitutional. Crompton was also involved in the Act 13 appeals process. “We pointed out that there were two other occasions where the court alerted us that they were recusing themselves,” said John Smith, a Pittsburgh attorney representing the Murrysville Watch Committee. “This is the first time I’ve had to ask a court officer to recuse him- or herself. And we were appreciative that he took our application seriously and made the decision he did.”
New Build/Expansions Coming This Yr & Next for 3 MU NGL Pipelines – The Liquids Pipeline Projects Database complements our natural gas pipeline projects table. We update our Liquids Pipeline Projects Database based on the best available information from pipeline company websites, trade press reports, and government documents, such as U.S. Department of State permits for border crossings. We release updates to the database twice each year: in the late spring and the fall. The data reflect reported plans. We clicked to view the “database” (actually a spreadsheet) maintained by EIA for liquids pipeline projects. We converted the EIA Microsoft Excel file into an online Google Sheets file, which you can view for yourself here.We re-sorted the sheet by year and discovered three projects (two in 2021, one in 2022) that will materially affect sales of M-U NGLs. All three project names are familiar to us and to anyone reading MDN for any length of time. However, we knew nothing of one of the three projects until today, and we had long forgotten about another.First up on the list is one of the projects completely new to us, or rather this aspect of an existing project is completely new. We’ve been telling you for the past two-and-a-half years about Energy Transfer’s Revolution Pipeline, a 24-inch natural gas gathering pipeline that runs through Bulter, Beaver, Allegheny, and Washington counties. It exploded in September 2018 just as it went into service. Although it finally went back into service in March of this year, ET is still trying to finish up final work on the fixed pipeline (seeNeverending Story: More Work to be Done on Revolution Pipe in SWPA). Tucked into EIA’s liquids pipeline spreadsheet is an entry for the Revolution System (i.e. Revolution Pipeline) stating that in Q1 of this year Revolution would build a 12-inch, 15-mile y-grade NGL pipeline from the Revolution Cryogenic plant south to a storage and an injection site – all located within Washington County, PA. The entry says the project is already completed! How did this not generate all sorts of pushback by the radicals on the left? Mariner East 2 Pipeline (Bypass) has one final bit of work to do on the ME2X pipeline before all three ME2 pipelines are fully complete and up and running at full capacity. The final bit is a short bypass around Marsh Creek State Park (see PA Labor/Biz Groups Turn Out to Support ME2 Marsh Creek Plan). According to the EIA spreadsheet, the ME2 Bypass project needs final permits (from the PA Dept. of Environmental Protection) before it can finish work. Tentatively the work should be done in Q3 of this year. This was the one project we were fully aware of.Looking at 2022, we noticed a project that we had forgotten about – an expansion of ATEX to the Gulf Coast. In October 2019, Enterprise Products Partners, the builder and operator of the ATEX ethane pipeline, committed to expanding the capacity along the pipeline (see Enterprise Decides to Expand ATEX Ethane Pipeline to Gulf Coast).ATEX was completed and began to flow 125,000 barrels per day of Marcellus/Utica ethane to the Gulf Coast in 2013. The pipeline starts in Washington County, PA, runs through West Virginia, and then all the way across Ohio. Some 261 miles of new pipeline was laid through Ohio, all the way to Seymour, Indiana where it connects to an existing Enterprise pipeline that runs to the Gulf Coast where the ethane gets used in cracker plants. The entire length of what is now called the ATEX is 1,192 miles long.
The Importance of Pennsylvania’s Natural Gas — Thanks to fracking in the Marcellus shale, Pennsylvania has led a U.S. natural gas revolution since 2007. The state’s production has exploded almost 40-fold, to over 7,300 billion cubic feet, or 20% of the national total. Pennsylvania now ranks second only to Texas on this measure and yields more gas than any other country, except Russia and Iran. The rise of shale has been critical because natural gas is easily America’s main source of electricity, at 40% of all generation. The International Energy Agency credits the use of cleaner gas – and its displacement of much higher-emission coal – for America’s achievement in cutting CO2 emissions the most “in the history of energy.” Experts at Wood Mackenzie and elsewhere conclude that gas demand will remain resilient, even in a policy environment that seeks to keep the human-induced rise in global temperatures to 2 degrees Celsius or less. Pennsylvania’s shale production has helped families economically and given businesses a competitive advantage. With Pittsburgh long eager to replace its fleeing steel industry, Allegheny County Executive Rich Fitzgerald, a Democrat and strong Joe Biden supporter, says that “fracking really saved us.” The University of Pennsylvania’s Kleinman Center for Energy Policy reports on the economic benefits from shale development: it has led to a decline in the state’s gas and electricity prices of 40% and 80%, respectively, over the first decade alone, saving families thousands of dollars a year. Jobs, government revenues, and royalties for landowners are among the many benefits of shale development. Current numbers tell the story: compared to over $10.00 per MMBtu in Asia, gas prices at Marcellus’s Dominion hub in mid-June were below $2.10. Such affordable energy explains why civil rights leaders like Revs. Jesse Jackson and Al Sharpton support natural gas. And there is much more to look forward to. The Marcellus is the largest producing field in the world, appraised at hundreds of trillions of cubic feet of supply. Ongoing coal retirements and the closing of Three Mile Island nuclear plant should extend gas’s current 50 – 55% share of Pennsylvania’s power generation. Data from the Department of Energy indicate that this shift from coal to gas has cut the state’s CO2 emission rate for electricity a staggering 75%, to 720 pounds per megawatt hour. Not particularly sunny or windy, Pennsylvania currently has 23,200 megawatts (MW) of gas capacity versus just 1,500 MW for wind and 90 MW for solar. And with the state’s paltry 30 MW of battery-storage capacity, it’s clear that gas will remain essential to compensate for the inherent intermittency of renewables and ensure grid reliability. Indeed, it’s telling that the most green-leaning states, such as California, New York, and Massachusetts, are all gas-dominant.
The fracking boom is over. Where did all the jobs go? – MIT Technology Review – Shale gas and oil extraction, also known as fracking, is often credited by conservatives with creating hundreds of thousands, if not millions, of US manufacturing jobs. As the “Saudi Arabia of natural gas,” Pennsylvania has been the poster child for the fracking industry. But far fewer jobs were created there and in neighboring states like Ohio than boosters claim, and many have since vanished. Take Williamsport, Pennsylvania. A faded former lumber town between the Susquehanna River and the Appalachian foothills, Williamsport’s population has declined by more than one-third in the past 60 years. Its poverty rate is twice the state’s average, and it now has high rates of drug abuse and violent crime. During the 2016 US presidential primary election, Republican hopeful Ted Cruz made a campaign stop in Billtown, as locals affectionately call it. At the time, the area was quickly becoming a hub of shale gas extraction. After many local landowners leased their mineral estates to petroleum companies, drilling rigs cropped up outside of town. Caravans of water and sand trucks plied the back roads. Oil giant Halliburton opened a massive facility that employed 600 people. And the welding and metalwork company NuWeld – the site of Cruz’s rally – expanded from 60 to 290 workers.”Pennsylvania is an energy state,” Cruz told the crowd. He saw NuWeld as a herald of the “millions of millions of new high-paying jobs” that fracking could bring. But less than two weeks after his visit, the company abruptly shuttered (it has since reopened at a much smaller scale).NuWeld was hardly the only area business affected by an industry-wide “slowdown,” as shale boosters delicately called it. Dan Klingerman, who built Williamsport’s Marcellus Energy Park, insisted to me at the time that the industry wasn’t in retreat, yet he quietly closed his oilfield trucking company. Hotels hastily built for itinerant workers sat half vacant. Halliburton’s local facility whittled its workforce down to about 40. By 2019, it was apparent that “slowdown” was a euphemism for bust. There were only 19 drilling rigs in the entire state by January of that year, down from 114 in the same month of 2012. That’s fewer rigs than Pennsylvania had before the fracking boom began.What happened? As a Bloomberg report put it, “The numbers never added up.” Fracking has always been expensive; extraordinarily generous fossil-fuel subsidies helped hide the true cost. With new wells facing average production declines of 60% in the first year, petroleum companies had to frantically drill more of them. The entire model was premised on high oil and gas prices. But nationwide, the glut of gas (and, to a lesser extent, oil) precipitated by the fracking boom depressed prices to their lowest levels since the 1990s. The result? Frackers pumped the brakes. A wave of consolidations and bankruptcies swept across the sector. The stock prices of premier energy firms like Chesapeake Energy Corporation crashed (it declared bankruptcy in 2020). Some, like Anadarko Petroleum Corporation, liquidated their shale gas holdings. Chevron announced in December 2019 that it would write down up to $11 billion in shale gas assets.The oil and gas industry shed more than 100,000 jobs last year, and areport by Deloitte warned that about 70% of the jobs lost in 2020 may not come back this year – or ever. As of April, the mining sector had the highest rate of unemployment in the country, at 15%. The petroleum industry has also taken a major reputational hit for its role in warming the planet while peddling climate-change denialism. Methane emissions associated with fracking are so pervasive that many scientists now think substituting natural gas for coal won’t reduce greenhouse-gas emissions. Shareholders are revolting; wealth managers are divesting.
US Steel, Equinor team up to examine Appalachia’s potential for hydrogen – Norwegian oil and gas producer Equinor ASA is teaming up with manufacturer U.S. Steel Corp. to explore converting Appalachia’s natural gas to cleaner “blue hydrogen,” the firms said June 29. Blue hydrogen uses steam methane reforming to make hydrogen and uses carbon capture and storage, or CCS, technologies to store the waste carbon, usually underground. Natural gas is typically the feedstock for steam methane reforming. Combined, Pennsylvania, northern West Virginia and eastern Ohio produce more natural gas than Texas. Another source of local demand would be welcomed by Appalachia’s producers. When pipelines out of the region fill up, Appalachia’s shale gas producers often end up selling gas into the glutted local market at a large discount to national prices. Equinor and U.S. Steel said the non-exclusive memorandum of understanding would open the door to studying the potential for producing and selling blue hydrogen in the region, as well as to combining their lobbying efforts with policy makers. Theoretically, just as natural gas replaced coal for many steelmaking processes, hydrogen could replace gas, reducing potent methane and carbon dioxide emissions. “A hydrogen and CO2 hub in the Appalachian Basin, utilizing the region’s natural gas resources while capturing and safely storing the emissions, would be an important tool to meet the future energy demands of domestic industry within the U.S. ambition to achieve net-zero by 2050,” Equinor’s U.S. country manager, Chris Golden, said in a statement. The key to net-zero emissions globally is not to eliminate carbon-intensive industry sectors but instead, make them less intensive, protecting jobs and infrastructure,” Equinor’s executive vice president for exploration and production international, Al Cook, told an audience June 28 at the Washington, D.C.-based Atlantic Council. “We’re leading a project called Zero Carbon Humber, which at the moment is the world’s largest blue hydrogen project, and that’s looking at decarbonizing an industrial cluster, the U.K.’s largest industrial cluster in northeast England,” Cook said. “For all that renewable energy can bring forward green jobs, it’s vitally important that we also protect jobs that have been created around steel, around cement, around heavy industry. And we protect that by decarbonizing those industries, rather than eliminate them.”
U.S. natgas companies put hydrogen to the test (Reuters) – At least two dozen U.S. energy firms, including Dominion Energy Inc and Sempra Energy, have started producing hydrogen or testing its viability in natural gas pipes to take advantage of existing infrastructure as the world prioritizes lower-carbon fuels. Nations worldwide are trying to reach net-zero carbon emissions by 2050, but that will rely heavily on technology – like hydrogen – that is in developmental stages. Utilities have a potential advantage if they find that clean-burning hydrogen can be successfully transported in existing gas pipes and power plants. But governments need legislation and regulation to encourage energy companies to spend billions in order to reduce production costs for green hydrogen, analysts said, before it can displace fossil fuels. Almost all of the world’s hydrogen production is currently through fossil fuels, and large utilities are currently mostly testing blends of natural gas and hydrogen in their pipelines. The companies experimenting with hydrogen are in early stages. Canada’s Enbridge Inc is blending up to 2% hydrogen into its natural gas distribution systems in Ontario, and just received approval to blend hydrogen in Quebec. “We are looking to understand the potential either with the existing system or, as we’re continuing to modernize the gas pipeline system, to ensure that new construction is hydrogen-ready,” said Pete Sheffield, Enbridge’s chief sustainability officer. Sempra’s Southern California Gas (SoCalGas) utility, which supplies gas to 22 million consumers, is working on pilot programs to test the fuel in its pipelines and see how a blend with natural gas affects the company’s pipes, as well as appliances and other equipment. The first project would blend hydrogen in a mostly residential area that SoCalGas can isolate from the rest of its distribution system, said Jawaad Malik, chief environmental officer. Virginia-based Dominion is testing a 5% hydrogen blend in a training facility in Utah and recently proposed a similar pilot in North Carolina, said Dominion spokesperson Aaron Ruby. Hydrogen is only considered clean if it is produced using low- or no-carbon emitting energy sources like biomass, nuclear, renewables or fossil fuels paired with carbon capture technology. “These types of proposals have not yet shown a path to a deeply decarbonized gas system,” said Julie McNamara, senior energy analyst for the Union of Concerned Scientists.
Supreme Court Rules New Jersey Can’t Block Natural-Gas Pipeline – WSJ – The Supreme Court on Tuesday removed a hurdle to the construction of a natural-gas pipeline through Pennsylvania and New Jersey, ruling the pipeline developer could invoke the power of the federal government to take state property needed for the project.The court’s 5-4 opinion, by Chief Justice John Roberts, handed a considerable victory to the natural-gas industry by rejecting New Jersey’s challenge to the actions of the PennEast Pipeline Co., a joint venture of several energy companies that aims to build a 116-mile interstate pipeline.The Federal Energy Regulatory Commission authorized the project and, under the Natural Gas Act, that approval allowed the company to use federal eminent domain power to take possession of the land, if necessary.PennEast said it was able to negotiate rights of way with most property owners, but went to court in its bid to take dozens of parcels of land – with compensation – in which the state of New Jersey holds a property interest. New Jersey objected on sovereign-immunity grounds, arguing that a private party like PennEast, a Delaware company, can’t drag a sovereign state into federal court against that state’s wishes.
U.S. Supreme Court rules PennEast pipeline project can use eminent domain to take N.J. state land | StateImpact Pennsylvania – In a 5-4 decision Tuesday, the U.S. Supreme Court ruled the state of New Jersey cannot block construction of the PennEast natural gas pipeline on state lands. The decision upholds PennEast’s authority – granted by the federal government – to seize the land through eminent domain. New Jersey argued the 11th Amendment, which grants states immunity from private lawsuits, prevented PennEast from condemning the 42 parcels either owned by New Jersey directly or held as conservation easements. Writing for the majority, Chief Justice John Roberts said Congress, through the Natural Gas Act, allows such condemnation in the interest of building a nationwide system of pipelines, as well as other infrastructure. “When the Framers met in Philadelphia in the summer of 1787, they sought to create a cohesive national sovereign in response to the failings of the Articles of Confederation,” he wrote. “Over the course of the Nation’s history, the Federal Government and its delegatees have exercised the eminent domain power to give effect to that vision, connecting our country through turnpikes, bridges, and railroads – and more recently pipelines, telecommunications infrastructure, and electric transmission facilities. And we have repeatedly upheld these exercises of the federal eminent domain power – whether by the Government or a private corporation, whether through an upfront taking or a direct condemnation proceeding, and whether against private property or state-owned land.” Justices Stephen Breyer, Samuel Alito, Sonia Sotomayor and Brett Kavanaugh, representing both conservative and liberal justices, joined Roberts. Writing for the dissent, Justice Amy Coney Barrett said the 11th Amendment guarantee of a state’s sovereign immunity does bar PennEast from suing to seize the land. “If private parties cannot sue nonconsenting States, the Court says, delegatees would have no practical means of taking state property,” she wrote. “And that is inconsistent with the Constitution, the Court tells us, because ‘[a]n eminent domain power that is incapable of being exercised amounts to no eminent domain power at all.’ … The flaw in this logic is glaring: The eminent domain power belongs to the United States, not to PennEast, and the United States is free to take New Jersey’s property through a condemnation suit or some other mechanism.”
Supreme Court Decision Could Revive the Potomac Pipeline Project – Maryland Matters – The U.S. Supreme Court sided with a pipeline company on Tuesday, ruling that pipeline projects with federal approval can seize state-owned land to build natural gas pipelines. Environmentalists say this decision could speed construction of a controversial pipeline proposed to run through a narrow stretch of Maryland near Hancock and under the Potomac River to deliver gas to West Virginia’s panhandle. The matter has been under litigation for the past two years after Maryland refused to grant the pipeline company access. In a 5-4 decision, the Supreme Court ruled that PennEast Pipeline Co. can take land from New Jersey to build a 116-mile natural-gas pipeline through Pennsylvania and New Jersey. The decision in PennEast v. New Jersey is binding and has bearing on a similar lawsuit filed by a pipeline company against the state of Maryland, according to Anne Havemann, general counsel for Chesapeake Climate Action Network. “Today’s ruling goes against a long history of preserving a state’s authority to protect natural resources within its borders from harmful interstate projects, and should be a wake up call to state leaders to find new ways to protect their interests,” Phillip Musegaas, vice president of the Potomac Riverkeeper Network, said in a statement. “In the Potomac pipeline case, an unwanted fracked gas pipeline – that would result in increased emission of harmful greenhouse gases and risk the safety of drinking water for six million downstream residents and the health of the Potomac River – could be built despite strong objection from Maryland’s governor and Maryland residents,” he continued. At issue is a lawsuit that Columbia Gas Transmission filed against the state of Maryland in 2019, after the Board of Public Works voted unanimously not to grant an easement for the company’s “Eastern Panhandle Expansion Project,” a 3.5 mile pipeline that would transport natural gas from Pennsylvania to West Virginia by crossing through Washington County. The pipeline project needed an easement to drill beneath the Western Maryland Rail Trail, which is state-owned land. The company, which is a part of TC Energy and based in Canada, has already built sections of the pipeline in Pennsylvania and West Virginia and needs the right to cross through Maryland to complete the project.
Cambria, Somerset join lawsuit against state renewable energy board – Several local municipalities and advocacy groups are part of a lawsuit filed against the Office of Renewable Energy Siting (ORES) accusing the state agency of violating state law when it failed to comply with the State Environmental Quality Review Act (SEQRA) and not take a “hard look” at the environmental consequences of its regulations, among other allegations. Ben Wisniewski, an attorney with the Zoghlin Group PLLC, that filed the lawsuit in Albany County, Tuesday, represents 13 petitioners, including the Town of Cambria, the Town of Somerset and the Town of Yates, as well as three other towns in New York and seven advocacy and education groups including Cambria Opposition to Industrial Solar (COIS) and Save Ontario Shores (SOS). SEQR violations “The allegation here is when this new ORES siting body was drafting its regulations for power plants, they failed to engage in the environmental review required by SEQRA,” Wisniewski explained. “That’s the violation.” The chain of violations allegedly built by ORES begins by not listing its actions as Type 1, a classification which means there is an impact caused by a governmental action. Instead ORES classified its actions, its insertion of a one-size-fits-all regulations for solar and wind projects, as unlisted, “relieving itself of its duty to prepare a full Environmental Assessment Form,” as written in the lawsuit. And the chain continues. “Even though it was unlisted, they still should’ve done a review,” Wisniewski said. “Because even when you classify an act as unlisted, you still have to determine whether or not the action even may have one adverse environmental impact.”
Public Service Commission taking input on proposed $540M sale of Mountaineer Gas to UGI – West Virginia utility regulators want to hear what you have to say about a half-billion-dollar deal in which the natural gas provider to 215,000 customers across 50 counties will be sold to a Pennsylvania company. The Public Service Commission is holding a public comment hearing July 20 on the proposed $540 million sale of Charleston-based Mountaineer Gas Co. to the King of Prussia, Pennsylvania-based energy holding company UGI. Mountaineer Gas and UGI filed a joint petition in January asking the commission to approve the sale, which includes an assumption of $140 million in debt. UGI reported having $1.5 billion in total liquidity available at the end of its 2020 fiscal year in the January petition. UGI said that month the acquisition would increase the company’s regulated utility rate base and customers served by nearly 14% and 30%, respectively. A rate base is the value of a company’s assets. The parties’ joint filing said employees and local leadership of Mountaineer Gas involved in day-to-day operations would remain, and the company’s “day-to-day operational expertise” would not be adversely affected by the sale. UGI told the commission it will maintain Mountaineer’s headquarters in West Virginia and the use of the “Mountaineer Gas Company” name.
Unplanned Outage at 2 WV MarkWest Plants Knocks 2.4 Bcf/d Offline –It doesn’t happen often, but when it does, it’s disconcerting. We’re talking about an “operational event” (i.e. outage) at not one but two MarkWest Energy natural gas processing plants – both in West Virginia. MarkWest’s Sherwood plant in Doddridge County and Mobley plant in Wetzel County are affected. According to NGI’s Daily Gas Price Index, four pipeline receipt locations affected by the outage are scheduled to go to zero beginning today “until further notice.”
Stream crossings continue to muddy the waters for Mountain Valley Pipeline -Whatever method builders of the Mountain Valley Pipeline use to get from one side of a waterbody to another – either a trench dug along the bottom or a tunnel bored below – it won’t be happening anytime soon.The latest delay came Monday, when the U.S. Army Corps of Engineers said it will extend to Dec. 31 a deadline for state regulators to decide if digging trenches will pose an unacceptable risk to the streams and wetlands of Southwest Virginia.Earlier this year, the Virginia Department of Environmental Quality sought a postponement from July 2, which it said would not allow enough time for a water quality certification that requires detailed analysis and public comment.Mountain Valley is seeking approval for about 150 open-cut crossings in Virginia, which entail temporarily damming a waterway, digging a trench along the exposed bottom, burying the 42-inch diameter pipe and then restoring the water flow.”This extension was absolutely essential – and we hope it will be sufficient – for Virginia regulators to thoroughly review the Mountain Valley Pipeline’s impacts on individual Virginia waters,” said Peter Anderson, Virginia policy director for Appalachian Voices.The joint venture building the natural gas pipeline also “fully supports” the deadline extension, spokeswoman Natalie Cox said Monday. Since it began work on the 303-mile pipeline though West Virginia and the New River and Roanoke valleys, Mountain Valley has encountered repeated problems with erosion and sedimentation. That has led to lawsuits by environmental groups and delays in a construction project that was supposed to be done by late 2018.In a May conference call, executives for the pipeline’s lead partner said they plan to have nearly all of the construction done by September. That will provide time to obtain approvals for water body crossings in order to complete the project by next summer, the company says.Meanwhile, it remained unclear Monday whether Virginia would require a separate water quality certification for boring under the nearly 100 waterbodies that will not crossed using the open-cut method.Final approval for that plan rests with the Federal Energy Regulatory Commission. In May, FERC asked DEQ if it wanted to weigh in on the borings before a decision was made at the federal level.
Photos and video: Invoking ‘Old Hills and Old Folks Resist’ to protest Mountain Valley Pipeline – Protesters opposed to the Mountain Valley Pipeline on Wednesday blocked access to part of the natural gas pipeline construction project in a mountainous section of Roanoke County near the community of Bent Mountain. Roanoke County police said just before 8 p.m. Wednesday that officers had extricated two of the three people and arrested them on charges of obstruction of justice, obstructing free passage of others and unlawful assembly. Bridget Kelley, 63, of Rockbridge County; back left, Deborah Kushner, 66, of Staunton, top center; and Alan Moore, 57, of Blacksburg are pictured locked to Moore’s 1999 Ford Crown Victoria on Wednesday morning, blocking access to a Mountain Valley Pipeline easement and work yard at the top of Poor Mountain. “We are the elder contingent to show you don’t have to be a young whippersnapper to fight a pipeline,” Kushner said. Roanoke County police officials inspect a Mountain Valley Pipeline blockade along Honeysuckle Road on Wednesday morning. Deborah Kushner, 66, of Staunton, sits in a rocking chair atop the 1999 Ford Crown Victoria while Bridget Kelley, 63, of Rockbridge County is locked beside and Alan Moore, 57, of Blacksburg is locked in the back seat. The trio panted the old vehicle with animals and birds and the words “Old Hills & Old Folks RESIST.” Deborah Kushner, 66, of Staunton, sits in a rocking chair atop the 1999 Ford Crown Victoria while Bridget Kelley, 63, of Rockbridge County is locked beside it with her arm in the gas tank and Alan Moore, 57, of Blacksburg is locked in the back seat. Deborah Kushner, 66, of Staunton was part of the trio blocking a Mountain Valley Pipeline easement and work yard on Poor Mountain on Wednesday. “We are the elder contingent to show you don’t have to be a young whippersnapper to fight a pipeline,” she said. Bridget Kelley, 63, of Rockbridge County went to high school in Roanoke County. Kelley and her fellow “Old Folks” know each other from their activism over the years, including ground support work for Theresa “Red” Terry and her daughter, Minor Terry, who stayed in tree stands for 34 days in 2018 to stop pipeline workers. “I really do believe she [Red] did inspire many to take action and at least listen,” Kelley said.
Pittsylvania County NAACP calls on DEQ to facilitate public participation in MVP hearing – In a letter dated June 27, 2021, the Pittsylvania County NAACP objected to the Air Pollution Control Board hearing on an air permit for the Mountain Valley Pipeline Lambert Compressor Station. The hearing will be held as a one-day, in-person-only meeting at a private hotel in Richmond, 150 miles from the proposed site in Pittsylvania County. As Virginia boards and agencies wrestle with how to execute Virginia’s fledgling Environmental Justice Act, Pittsylvania NAACP President Anita Royston told DEQ Director David Paylor that, “Thus far, DEQ and the Air Board have not performed due diligence in outreach, identifying environmental justice communities, and determining the potential health impacts on those of us living near the project. Local residents are at risk of falling through the large crevice between good intentions and genuine progress in Virginia’s efforts to ensure environmental justice throughout the commonwealth.” The NAACP request is to make it possible for everyone who is eligible to address the air board directly in person, by telephone or over the internet; to provide access so that everyone can see or hear the proceedings and learn from the full range of voices; and to consider holding the meeting closer to Pittsylvania County.
Energy Transfer Sues To Keep Pipeline Risk Info Private – Law 360 (paywalled)
Natural gas pipeline planned in Bullitt County – The state’s largest utility company is planning a new natural gas pipeline in Bullitt County. Louisville Gas and Electric wants to build 12 miles of pipeline near Bernheim Forest. LG&E spokeswoman Natasha Collins says it’s needed for a couple of big reasons, the primary one being to prepare for potential problems with the existing lines. “So if there was something that happened to that existing line, there is the potential for service interruption for those customers,” Collins said. The growth of Bullitt County is another factor: Census data shows the county grew about 10% over the last decade. “And so we want to continue to support that growth and expansion within our community,” Collins said. “And that’s serving our customers, supporting the Commonwealth and Bullitt County, and it’s growth and expansion. We take all of those commitments seriously.” The project has opponents, though. Landowners near Bernheim Forest refused to sell land for the project, and LG&E eventually condemned the land and took it through eminent domain. A Bullitt County judge ruled in LG&E’s favor in May, but the ruling could be appealed. Bernheim Forest is involved in a separate lawsuit because the pipeline would cross land they own.
Rome queries AGL on repaving roads damaged by pipeline construction –Rome officials are waiting to hear from Atlanta Gas Light regarding repaving asphalt roads around the city that have been damaged as a result of pipeline construction. City Manager Sammy Rich said they’re unsure which roads will be paved by the gas company. Once plans are confirmed with AGL, the city will assess the rest of the damage and move from there. The 9.3-mile pipeline will provide a 300 psi system feeding roughly 494,000 cubic feet of natural gas per hour to the International Paper plant in Coosa. The average residential home uses about 168 cubic feet a day. Over 80% of the pipeline work is finished, according to the latest weekly progress report published on June 23. At this point the company estimates the pipeline will be complete and functional by Sept. 8.
Democrats in Oil Country Worried by Party’s Natural-Gas Agenda – – Democratic Party progressives are pushing President Biden to include in his infrastructure agenda stringent measures to address climate change, including policies designed to end the nation’s reliance on natural gas as a fuel source.The more the progressives succeed, the more moderate Democrats in energy-producing states become vulnerable to losing seats that are crucial to the party’s hold on Congress, current and former House members say.The White House announced a deal last week with centrist lawmakers in the Senate on a roughly $1 trillion package focused on traditional infrastructure such as roads and bridges. On a separate track, Democrats are advancing a second bill – without Republican input – that among other goals aims to eliminate greenhouse-gas emissions from electric power generation by 2035.The Democrats have a similar target of 2050 for other emissions sources, including factories, trucks, automobiles and homes. That is a political headache for moderates such as Rep. Lizzie Fletcher (D., Texas), who in 2018 flipped a Republican-held House seat. Ms. Fletcher’s Houston-area House district ranks second in the nation for employment tied to the oil and gas industries, according to the American Petroleum Institute. “Gas is a part of our energy mix, ” said Ms. Fletcher. She has overcome Republican attack ads portraying her as a problem for the natural-gas industry with a message that contrasts with that of the rest of her party: “I think it will be a part of our energy mix well into the future.” Energy policy is high on the list of issues creating strife among Democrats, along with other themes such as universal healthcare and police reform. Energy would be at the center of the second, all-Democrat infrastructure bill, which would require support from centrists – including Sen. Joe Manchin, who hails from West Virginia, a fracking state – given the Democrats’ narrow 220-211 majority in the House and the evenly divided Senate.Some moderates are distancing themselves from the progressive push to increase regulation of natural gas extraction. In January, four Texas House Democrats wrote to Mr. Biden asking him to abandon an executive order suspending new oil and gas leases on federal public lands and waters.Along with Ms. Fletcher, the letter was signed by Reps. Vicente Gonzalez, Henry Cuellar, and Marc Veasey, who said Mr. Biden’s policy “would have far-reaching negative consequences,” including the “near-term loss of potentially one million jobs.”
FERC repeats it cannot assess gas project’s climate impact in expanded review – The US Federal Energy Regulatory Commission has released the draft version of an additional climate review of a pending Columbia Gulf Transmission pipeline project in Louisiana, finding once more that agency staff could not draw conclusions about the significance of natural gas projects’ contributions to climate change. The pipeline developer’s eight-mile, 725 MMcf/d East Lateral XPress Project is one of five pending gas projects that received a May 27 notice from FERC, saying the regulator planned to perform additional environmental assessments of their potential contributions to climate change. The draft environmental impact statement issued by FERC on June 25 marked the third draft review issued for projects on track to receive the additional consideration of climate change impacts (CP20-527). The conclusions reached by FERC staff are similar in the three draft reviews released so far, underscoring the uncertainty for developers of gas projects as the regulator develops its approach to assessing climate change impacts. “Commission staff conclude that construction and operation of the project would not result in significant environmental impacts, with the exception of climate change impacts, where FERC staff is unable to determine significance,” the draft review for the East Lateral XPress Project said. FERC Chairman Richard Glick has defended the added climate reviews, saying they will strengthen the legal durability of permitting decisions and that it remains up to commissioners to work out how to determine the significance of projects’ contributions to global warming. Glick has also said the commission would analyze climate impacts of pipeline projects on a case-by-case basis while it prepared a potential update to the agency’s decades-old policy for permitting pipelines. “From my perspective, I do see the analyses that are going to come down from the environmental impact statements as potentially helping the commissioners, including myself, determine whether the emissions associated with those projects are significant,” Glick told reporters June 17. “In my opinion, we can make that analysis, we should make that analysis, and the courts have told us we have to do that analysis.” Each of the five projects being subjected to the expanded reviews already received less-extensive environmental assessments from FERC. Each of the projects had also been protested. The recommendations on assessing climate could evolve by the time final environmental impacts for the projects are finished, and Glick said he would be “comfortable going forward” with decisions on certificate applications once they are. FERC has said it plans to release final environmental impact statements in the fall and that the expanded reviews would build off the environmental assessments that had already been completed.
‘Virtually Unheard Of’ Temperatures Spark More Gains for Expiring July Natural Gas Contract; Cash Surges — July natural gas futures charged like a lion Monday, surging 12.1 cents from Friday’s levels as a historic heat wave continued to smother the Pacific Northwest, leading to pipeline issues and amplified demand. Notable heat also blanketed the East Coast, and with forecasts pointing to more hot weather ahead, the July Nymex contract extended its streak of gains to five days, expiring at $3.617. August, which takes over the prompt-month position on Tuesday, jumped 7.3 cents to $3.593. Spot gas prices also continued to strengthen, with prices nearing $7.00 in California and $4.00 in the Rockies. NGI’s Spot Gas National Avg. rose 40.0 cents to $3.775. The scorching temperatures in the normally mild Pacific Northwest soared to “unheard of” heights beginning over the weekend, with Portland, OR, setting back-to-back records, according to AccuWeather. On Saturday, daytime temperatures climbed to 108 degrees and on Sunday, they hit a “staggering” 112 degrees. Before this weekend, the highest temperature ever recorded in the city was 107, set once in July 1965 and twice in August 1981, the forecaster said. “Temperatures of 110 degrees or greater are virtually unheard of west of the Cascades,” AccuWeather senior meteorologist Randy Adkins said. Records also were broken in Seattle, which shot up to 104 on Sunday. It was the second day in a row that temperatures crested the century mark, a record in itself. The blistering conditions in the region combined with impressive heat on the East Coast to send futures prices higher early in the session. Although the prompt month opened the session slightly in the red, the July contract had climbed nearly 6.0 cents higher before 9 a.m. ET. The moderate gains occurred in the face of a slightly cooler outlook for the eastern United States beginning late this week. However, traders quickly brushed off the near-term data since weather models indicated that hot weather could return as soon as next week. NatGasWeather said an upper high pressure is set to expand toward the eastern United States by July 6, resulting in highs in the mid-80s to 100s over most U.S. regions. The forecaster expects national demand to strengthen at that time and remain elevated through at least July 12. “What helps make the coming pattern bullish is the likelihood of a hot pattern for the 11- to 15-day period (July 7-12) carrying over to the 16- to 20-day period (July 13-17),” NatGasWeather said.
Natural Gas Futures, Cash Prices Extend Rallies Amid Brutal Heat, Robust Demand — August natural gas prices started to show signs of slowing down Tuesday. But as oppressive heat led to more shattered records and rolling blackouts in the Pacific Northwest, the new prompt month edged up another 3.7 cents to $3.630 in its debut at the front of the Nymex futures. September climbed 3.4 cents to $3.606. Natural gas cash prices also continued to swell amid the intense heat and high humidity. Next-day gas surged past $7.00 in California and to $12.00 in the Northeast, helping to lift NGI’s Spot Gas National Avg. 30.5 cents to $4.080. In one of the more volatile nonwinter trading sessions in years, the August futures contract soared early to an intraday high above $3.80-, more than 20 cents above Monday’s settle. But it sold off almost as quickly. “There is definitely nothing in either weather or fundamentals data that can explain such crazy price action, as it had the feel of a couple of larger players being forced to stop out, leading to the massive spike higher,” said Bespoke Weather Services. With Tuesday being so chaotic, “we feel being neutral is prudent.” At the forefront of the early rally is the intense heat baking much of the United States. The hot, dry summer playing out in the Pacific Northwest has resulted in “temperatures that would make a Texan blush,” according to The Schork Group. More than three-quarters of the West is in “severe” drought, and “exceptional” dry conditions are in more than a quarter of the region, the firm noted. That “spells trouble” for California, Oregon and Washington, where 42% of the total U.S. generation comes from hydroelectric power. There appears to be little reprieve from the sweltering heat for at least another several days. Although some coastal areas may start to cool off a bit, AccuWeather said the unusually high temperatures would likely persist east of the Cascades and throughout Western Canada into the early days of July.
U.S. natgas edges up to fresh 30-month high on rising demand forecasts –(Reuters) – U.S. natural gas futures edged up to a fresh 30-month high on Wednesday on soaring global gas prices and forecasts for higher U.S. air-conditioning and export demand over the next two weeks than previously expected. Front-month gas futures NGc1 rose 2.0 cents, or 0.6%, to settle at $3.650 per million British thermal units (mmBtu), their highest close since December 2018 for a third day in a row. That also kept the front-month in overbought territory with a relative strength index (RSI) over 70 for a fifth day in a row and put the contract up for a seventh day in a row for the first time since November 2017. For the month, the contract gained about 22%, putting it up for a third month in a row for the first time since October 2019. For the quarter, the contract gained about 40%, putting it up for a record fifth quarter in a row. In the power market, prices for Wednesday soared to $126 per megawatt hour in New England E-NEPLMHP-IDX, their highest since November 2018, as a heat wave started to bake the region. Data provider Refinitiv said gas output in the Lower 48 U.S. states averaged 91.6 billion cubic feet per day (bcfd) so far in June, up from 91.0 bcfd in May but well below the monthly record high of 95.4 bcfd in November 2019. Refinitiv projected average gas demand, including exports, would slide from 94.5 bcfd this week to 92.0 bcfd next week as the weather turns slightly milder. Those forecasts were higher than Refinitiv projected on Tuesday. The amount of gas flowing to U.S. liquefied natural gas (LNG) export plants slipped to an average of 10.1 bcfd so far in June due mostly to short-term maintenance at Gulf Coast facilities and the pipelines that supply them with fuel. That compares with averages of 10.8 bcfd in May and a record 11.5 bcfd in April. But with European TRNLTTFMc1 and Asian JKMc1 gas both trading over $12 per mmBtu, analysts said buyers around the world should keep purchasing all the LNG the United States can produce. The Title Transfer Facility (TTF) in the Netherlands, the European gas benchmark, was at its highest since November 2008. U.S. pipeline exports to Mexico averaged 6.7 bcfd so far in June, on track to top May’s 6.2-bcfd record.
Natural Gas Futures Mark Eighth Straight Gain as Market Has ‘No Clue’ on Duration of TCO Issues — The uncertainty created by a sharp decline in production proved too much to bear (no pun intended) for the natural gas market on Thursday. Traders eventually brushed off a large miss in the latest government storage report, sending the August Nymex gas futures up another 1.1 cents to $3.661. The September contract tacked on eighth-tenths of a cent to $3.632. Spot gas prices continued to tumble from recent highs. NGI’s Spot Gas National Avg. plunged 19.5 cents to $3.415. With temperatures starting to retreat from historic highs in the Pacific Northwest, and the East Coast expected to be downright cool in parts of the region over the Independence Day weekend, all attention was on the Nymex futures market Thursday. After seven straight days in the green, market observers were eager to see whether news of a major production drop in the Northeast could fuel another rally. The August Nymex contract indeed spiked, rising above $3.750 early in the session. However, futures began to soften ahead of the latest round of storage data, likely because cash trading was underway and decreases were widespread. The Energy Information Administration (EIA) launched a “bear bomb” on the natural gas market, reporting a much larger-than-expected 76 Bcf injection into storage for the week ending June 25. The EIA figure was slightly outside the range of expectations in major surveys and 3 Bcf above last year’s build for the similar period. The five-year average stood at 65 Bcf. August futures, which had softened to around $3.640 in the minutes leading up to the EIA report, sank to $3.629 as the print crossed trading desks. It then briefly slipped below $3.600. Bespoke Weather Services said the 76 Bcf injection was roughly 3 Bcf/d looser than last week’s 55 Bcf build, “which is a lot.” Still, considering how strong last week’s number was, the firm did not view the EIA report as “inherently bearish.” In pipeline notices issued Wednesday, TCO and EQM Midstream Partners LP said a MarkWest operational event was affecting the Sherwood and Mobley processing plants in West Virginia. That is limiting receipts onto TCO and EQM Midstream by up to 2.4 Bcf/d.
Natural gas prices remain firm after US storage fields add 76 Bcf to inventories | S&P Global Platts – US natural gas storage fields posted an above-average storage build for the week ended June 25, but high demand stemming from a heat wave might prompt a net withdrawal from some regions for the week in progress keeping prices elevated. Working gas storage inventories increased 76 Bcf to 2.558 Tcf, the US Energy Information Administration reported June 24. The build was stronger than the 63 Bcf addition expected by an S&P Global Platts survey of analysts, as well as the five-year average build of 65 Bcf, according to EIA data. Both the Henry Hub balance-of-summer and next-winter contract strips are trading lower on the day following a storage inventory report that showed inventories rising much more than expected. Immediately following the EIA storage report, Henry Hub futures prices traded as much as 7 cents/MMBtu lower on the day. The selloff largely subsided by afternoon, with prices through October trading around 2 cents/MMBtu lower on the day to average $3.61/MMBtu. Slightly heavier selling pressure was seen on the November-March strip, which traded down roughly 6 cents/MMBtu on the day. Still, prices are up nearly 20 cents from a week ago. Already meager summer-to-winter spreads have narrowed to 5 cents as of July 1, down from an average spread of 13 cents/MMBtu in June. Total US supply for the week ended June 25 added 600 MMcf/d week on week after a 1 Bcf/d surge in onshore production was diminished partly by a roughly 500 MMcf/d drop in net Canadian imports, according to S&P Global Platts Analytics. Downstream, a healthy uptick in LNG feedgas demand along the US Gulf Coast was overshadowed by a roughly 2 Bcf/d drop in gas-fired generation demand, resulting in average daily demand falling by 800 MMcf/d on the week. These divergent trends left US balances looser by 1.4 Bcf/d, resulting in a much larger storage build week on week. Platts Analytics supply and demand model currently forecasts a 22 Bcf injection for the week ending July 2, which would measure 41 Bcf below the five-year average. Power generation demand gains overshadowed most movements among fundamentals for the week in progress. Total supply retracted by roughly 200 MMcf/d on the week, after a sharp drop in production was partially offset by a recovery in net Canadian imports. Total demand has surged due to a massive increase in cooling loads, which propelled power demand 5.5 Bcf/d higher on the week. It was accompanied by a nearly 1 Bcf/d increase in LNG feedgas demand. Overall, the gains in demand were slightly pared by a sizable drop in exports to Mexico, alongside smaller declines in both residential and commercial and industrial demand. All three major demand regions, Midwest, East and South Central, reported a significant retraction in storage injections for the week ending July 2 in order to meet the record-breaking demand seen during the ongoing heat wave. The South Central region led the way with a 14 Bcf reduction, actually flipping to a net withdrawal for the week.
U.S. natgas edges up to fresh 30-month high on rising demand forecasts (Reuters) – U.S. natural gas futures on Friday rose to a fresh 30-month high ahead of the July Fourth holiday weekend with a drop in output due to a problem with a natural gas liquids pipeline in West Virginia and on soaring global gas prices. Traders said the U.S. price increase came despite forecasts for less hot weather and lower demand over the next two weeks than previously expected. Front-month gas futures NGc1 rose 3.9 cents, or 1.1%, to settle at $3.700 per million British thermal units (mmBtu), their highest close since December 2018 for a fifth day in a row. That kept the front-month in overbought territory with a relative strength index (RSI) over 70 for a seventh straight day, and put the contract up for a ninth day in a row for the first time since March 2017. For the week, the contract gained about 6% after rising about 9% last week. Data provider Refinitiv said output in the Lower 48 U.S. states dropped to an average of 87.5 billion cubic feet per day (bcfd) so far in July due mostly to the pipeline problem in West Virginia. 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 slide from 93.3 bcfd this week to 89.9 bcfd next week as the U.S. July Fourth holiday and milder weather cuts air conditioning use, before rising to 93.8 bcfd in two weeks when the weather is forecast to turn seasonally hotter. The outlook for next week was a little lower than Refinitiv projected on Thursday. The amount of gas flowing to U.S. liquefied natural gas (LNG) export plants averaged 10.9 bcfd so far in July, up from 10.1 bcfd in June but still below the record 11.5 bcfd in April. With European TRNLTTFMc1 and Asian JKMc1 gas both trading over $12 per mmBtu, analysts said buyers around the world would keep purchasing all the LNG the United States can produce. The Title Transfer Facility (TTF) in the Netherlands, the European gas benchmark, was near its highest since October 2008. U.S. pipeline exports to Mexico averaged 6.4 bcfd so far in July, down from a record 6.7 bcfd in June.
U.S. natgas producers hope customers will pay more for ‘green gas’ (Reuters) – U.S. natural gas producers hope climate-conscious electric utilities and gas exporters will pay a premium for what they say is “greener gas” that has been certified as coming from low-emission operations or from renewable sources such as landfills. EQT Corp, Chesapeake Energy and liquefied natural gas firms Cheniere Energy and NextDecade Corp are among the companies considering low-carbon certifications from groups such as Denver-based Project Canary. Gas certified as “responsibly produced” and contributing less emissions could get up to 5% above market prices, or up to 15-cents per thousand cubic feet (mcf), proponents say.So far, not many customers have been willing to pay the premium — a problem for firms trying to sell lower-carbon versions of fossil fuels. Some European buyers have shunned U.S. shale gas and several U.S. cities including New York and San Francisco have sought to ban new residential gas connections over environmental concerns.In 2020, the pandemic rocked the economy and U.S. gas prices fell to a 25-year low average of $2.11 per mcf. Idle drillers pushed U.S. gas output down 2%, the first annual drop in four years. While power plants consumed a record amount of gas in 2020, wind and solar have been gaining market share as preferred alternatives to dirtier coal for electric generation.With the economy recovering, U.S. benchmark gas prices are up over 40% this year to about $3.70 per mcf.”When you’re talking about trillions of cubic feet of global gas production, mere pennies in price movement can make all the difference between profitability and losses,” said Kentaro Kawamori, chief executive of Persefoni, which develops tools to measure a company’s carbon footprint.
Tellurian weighs ‘business combination’ to aid upstream plan tied to Driftwood LNG – Tellurian will consider a “business combination” to ensure it has sufficient natural gas reserves to support its proposed Driftwood LNG export facility in Louisiana, Executive Chairman Charif Souki said June 29 in a podcast message to employees and investors. The plan follows the company’s announcement in March, during an interview with S&P Global Platts, that it wants to produce all the gas it will need to feed Driftwood and would not sanction the project until it had secured sufficient upstream reserves for the first phase of the terminal project. To realize that goal, Tellurian needs to get bigger in the upstream, and faster, even as it drills more wells in the Haynesville Shale on its own acreage and in partnership with other producers. Those efforts alone are expected to almost triple Tellurian’s production by the end of 2021 — to 80 MMcf/d — compared with the end of 2020, Souki said. “Clearly, this is not sufficient for integrating the full picture of what we will need five years from today,” Souki said. “We are in a position now to start looking seriously at a business combination that will make sense for our integrated business model.” Souki did not say whether such a combination would be limited to the production side of the company, or also include the LNG side of the company. He also did not say whether any M&A talks were underway or, if they were, with whom. A spokeswoman did not immediately respond to a request for comment. The up to 27.6 million mt/year export facility is to be built in phases, with the first phase covering about 16 million mt/year of capacity. Tellurian is targeting to give Bechtel a notice to proceed with full construction of the terminal by the end of the first quarter of next year.
U.S. ethane exports surge with additional export capacity and expanded tanker fleet –U.S. ethane exports reached an all-time high in March 2021 after a new export facility started operations and the tanker fleet that carries liquefied ethane overseas expanded.Ethane exports surpassed 370,000 barrels per day (b/d) in March, including more than 280,000 b/d of waterborne exports. We expect growth in U.S. ethane exports to accelerate this year and next from an annual average of 281,000 b/d in 2020 to annual averages of 374,000 b/d in 2021 and 447,000 b/d in 2022, according to our JuneShort-Term Energy Outlook.U.S. exports of ethane began in 2014. The first U.S. export pipelines for ethane were completed in 2014 to transport ethane to petrochemical plants in Canada. U.S. waterborne ethane exports began in 2016, when two waterborne export terminals (one in Marcus Hook, Pennsylvania, and one in Morgan’s Point, Texas) began operations. Capacity at the waterborne export terminals expanded from 275,000 b/d in 2016 to 305,000 b/d in 2019. In January 2021, athird export terminal began operations at Nederland, Texas, which increased U.S. capacity for waterborne exports by more than 170,000 b/d.In addition to new export capacity, the capacity to ship ethane has also grown rapidly. Specially built tankers carry ethane that is cryogenically cooled to -128 degF so it can be transported as a liquid. The tankers range from coasters that carry ethane or ethylene over short distances to very large ethane carriers (VLECs) designed to carry up to 1 million barrels on intercontinental routes. Until late 2020, eight VLECs were operating, all serving U.S. terminals. Near the end of 2020 and beginning of 2021, six new VLECs entered service, and another six VLECs are expected to be delivered and begin shipping ethane near the end of 2021. Exports account for an increasing share of total U.S. ethane demand. In 2020, the United States exported about 16% of domestic ethane production, which rose from none in 2013. By 2018, the United States exported to six countries that had infrastructure to import cryogenically cooled ethane at coastal terminals connected to ethylene crackers. Now eight countries – Canada, China, India, the United Kingdom, Norway, Sweden, Mexico, and Brazil – can accept U.S. ethane exports. Ethane is used primarily as a petrochemical feedstock, which means it is fed into ethylene crackers and heated to temperatures between 1,450 degF to 1,600 degF to break the ethane molecule down into ethylene. Ethylene is further processed to create derivatives such as polyvinyl chloride (PVC) and ethylene glycol (EG), but the most common process is polymerization to make polyethylene (PE), a common base component of plastics.
Oil and gas exports give the US a strategic geopolitical tool – Earlier this month, Judge Terry Doughty of the Western District of Louisiana lifted the Biden administration’s attempt to halt lease sales for oil and gas production on federal lands and waters. Doughty issued a preliminary injunction on the administration’s plan after 13 states sued. The lease of federal lands for oil and gas production provides millions of dollars of revenue for the states and local governments and economies. Beyond the legal arguments, though, the resumption of federal land leases is critical to pursuing America’s geopolitical goals. The United States is blessed with an abundance of natural resources, among them plentiful reserves of oil and natural gas. We can either use these resources to our own advantage, both domestically and as exports, or we can cripple our own energy production, limiting our potential. In this decision, we must consider that exported fuel is not only a source of wealth; it is also a powerful tool of geopolitical influence. It can be tempting to dream of a world that uses less fossil fuel, but the Biden administration’s plan to halt lease sales would do nothing to further this aspiration. Rather, the Biden administration’s plan would curb only domestic oil and gas production, not consumption. In other words, it would cut supply while demand keeps rising. The immediate result would be two-fold: higher prices and increased imports, often from countries that don’t align with our interests. Supply would stagnate or drop if domestic oil and gas production is not allowed to prosper. When supply is lower and demand continues to rise, as it inevitably will, prices rise. Under the Biden plan, we would pay more for our oil and gas. Energy exports aren’t just about trade and growing the U.S. economy. In oil and gas exports, the U.S. holds a critical strategic geopolitical tool. For example, the Trump administration, in its Phase 1 trade deal with China, negotiated a requirement for China, the world’s largest oil importer, to purchase large amounts of American oil and petroleum products. In another part of the world, America’s abundance of natural gas can be used to counteract Russia’s influence on Europe. Through deals like the one recently concluded between the U.S. and Poland, we can halt Russian geopolitical encroachment on a Europe desperate for fuel.
CITGO agrees to $19.7 million settlement to mitigate 2006 oil spill in Calcasieu River – CITGO Petroleum Corp. has agreed to pay $19.7 million to restore natural resources damaged during a 2006 spill of more than 2 million gallons of waste oil and millions of gallons of wastewater into the Calcasieu River estuary from its Westlake refinery, in a consent decree entered into with the U.S. Justice Department and federal and Louisiana state trustees and filed in federal court in Lake Charles.Taken together with earlier settlements, the deal means the company will have paid nearly $115 million in fines over the damage the spill caused. Plans call for using $19.2 million of the new settlement in Calcasieu Parish to restore parts of the 150-mile stretch of the estuary damaged by the spill, said Louisiana Oil Spill Coordinator Sam Jones. Jones said the state Coastal Protection and Restoration Authority will be the lead state agency in determining how the money will be used. The remaining settlement money will be used to reimburse federal and state agencies for unpaid damage assessment costs.A draft damage assessment and restoration plan, required by the federal Oil Pollution Act, is being developed by state and federal trustees representing the oil spill coordinator’s office, CPRA, the Louisiana Departments of Environmental Quality, Natural Resources, and Wildlife & Fisheries, and the National Oceanic and Atmospheric Administration and U.S. Fish & Wildlife Service. No date has been set for its completion. The settlement is the latest multi-million dollar payment made by the company for environmental violations involving the 2006 spill and other spills or federal or state environmental law violations at the Lake Charles area plant. “At least 54,000 barrels (2,268,000 gallons) of waste (or ‘slop’) oil and untold millions of gallons of oily wastewater flowed into the waterways during the incident,” said the U.S. Justice Departmentcomplaint against the company, which was filed June 17 along with the consent decree in U.S. District Court in Lake Charles.
How bankruptcy lets oil and gas companies evade cleanup rules “It’s basically bankruptcy for profit.” – A battle over who is responsible for cleaning up hundreds of oil and gas rigs in the Gulf of Mexico is quietly playing out in a bankruptcy court in southern Texas. The contestants in this game of fossil fuel infrastructure hot potato: Fieldwood Energy, an offshore drilling company attempting to offload more than $7 billion in environmental cleanup responsibilities; a group of oil majors including Chevron, Marathon Oil, and BP; and the Department of the Interior.*Fieldwood has declared bankruptcy, and a court is considering the company’s plan to split its assets, moving older legacy wells and drilling rigs that are expensive to clean up into two entities while creating a new company – appropriately named NewCo – to purchase the more profitable assets. The company proposes outright abandoning a fourth bucket of assets consisting of more than 1,170 wells, 280 pipelines, and 270 drilling platforms. Aging wells and drilling platforms pose multiple risks to the environment and human safety, including oil and gas leaks and explosions. A quirk in the regulations that govern offshore drilling allows the Interior Department to hold companies that previously operated on Fieldwood leases accountable for the cleanup. The department is charged with protecting public lands – both on land and offshore – and issues leases to more than 12 million acres of seabed, including in the Gulf. A single lease can contain multiple wells, and many of the leases that Fieldwood is proposing to abandon or “return” to predecessor companies could end up the responsibility of oil majors, such as Chevron and BP. Unsurprisingly, both companies have zealously objected to the company’s bankruptcy plan. While the oil companies attempt to dodge responsibility for cleanup, the Interior Department, has been filing objections to Fieldwood’s plan to transfer leases to other companies and abandon wells, stating that its environmental obligations are “nondischargeable” and that leases cannot be sold or transferred without sign-off from the federal government. Fieldwood is one of more than 260 oil and gas companies that has filed for bankruptcy in the last six years. With low prices and suppressed demand for oil and gas over the last year, operators have struggled to stay afloat. Many have been turning to bankruptcy in an attempt to shed their debts, reorganize their assets, and, in some cases, offload their environmental obligations. Utilizing limitations and loopholes in bankruptcy law, these companies are employing a playbook perfected by coal companies to shed their environmental and labor liabilities.
U.S. Supreme Court backs refineries in biofuel waiver dispute — The U.S. Supreme Court on Friday bolstered a bid by small oil refineries to win exemptions from a federal law requiring increasing levels of ethanol and other renewable fuels to be blended into their products, a major setback for biofuel producers. The 6-3 ruling overturned a lower court decision that had faulted the U.S. Environmental Protection Agency for giving refineries in Wyoming, Utah and Oklahoma extensions on waivers from renewable fuel standard (RFS) requirements under a law called the Clean Air Act even though the companies’ prior exemptions had expired. The case involved exemptions given to units of HollyFrontier and CVR Energy. In ruling in favor of the refineries, conservative Justice Neil Gorsuch, writing for the court, compared the extensions at issue in this case to those granted in everyday life, such as to a student who needs more time for a term paper even though the deadline had passed, or a contract whose terms had expired. “It is entirely natural – and consistent with ordinary usage – to seek an ‘extension’ of time even after some time lapse,” Gorsuch said. In a dissent, conservative Justice Amy Coney Barrett, joined by liberal justices Sonia Sotomayor and Elena Kagan, faulted the majority’s interpretation of the word “extend.” The “EPA cannot ‘extend’ an exemption that a refinery no longer has,” Barrett wrote. President Joe Biden’s administration has been considering ways to provide relief to U.S. oil refiners from biofuel blending mandates. The case reflected a long-running dispute between the oil and corn industries. The legal battle focused on changes made in 2005 and 2007 to the Clean Air Act to require biofuel quotas in U.S. gasoline and diesel products – intended to reduce dependence on foreign oil and support fossil fuel alternatives. Under program, refiners must blend billions of gallons of biofuels such as ethanol into their fuel or buy compliance credits, known as RINs, from those that do. U.S. renewable fuel credits fell on the news, trading at $1.55 cents each, down from $1.65 each on Thursday. U.S. gasoline and diesel futures plunged about 3% immediately following the news, but have since eased losses. States backing the refineries included Wyoming. Those backing biofuels included Iowa. Both sides cited economic threats to their rural economies posed by the litigation. HollyFrontier Corp said in a statement, “We are pleased that our longstanding arguments were today validated by the Supreme Court.” HollyFrontier urged the EPA to “immediately take action to make the RFS a workable program for U.S. refiners and consumers.” American Fuel & Petrochemical Manufacturers President Chet Thompson said the renewable fuel standard “is hurting consumers and jeopardizing the viability of refineries across the country, as well as the jobs and communities they support.” Iowa Renewable Fuels Association Executive Director Monte Shaw said his group is “extremely disappointed” with the ruling but noted that the lower court had faulted the EPA’s decisions on other grounds as well. “We fully expect the Biden EPA … to deny the vast majority of RFS exemption extension requests that are pending or that will be submitted in the future,” Shaw said. Renewable fuel groups said that an increase in waivers during Republican former President Donald Trump’s administration had undercut the demand for their products by billions of dollars.
EIA’s updated liquids pipeline database shows 19 projects moving toward completion in 2021 – So far in 2021, 2 petroleum liquids pipeline projects have been completed, and 17 more projects have been announced or are currently under construction, according to updated data in our Liquids Pipeline Projects Database. That total includes 12 crude oil projects, 6 hydrocarbon gas liquids (HGLs) projects, and 1 petroleum product project. Of the 19 projects, 10 projects are new pipelines, 7 projects are expansions or extensions of existing systems, and 2 projects are conversions of the commodity carried on the pipeline.In 2020, 24 petroleum liquids pipeline projects were completed. That total includes 11 crude oil projects, 12 HGL projects, and 1 petroleum product project. Of the 24 projects, 11 projects were new pipelines, 11 projects were expansions of existing systems, 1 project was a conversion of the commodity carried on the pipeline, and 1 project was a combination of new and existing pipelines.Our Liquids Pipeline Projects Database documents more than 250 current, future, and past liquids pipeline projects in the United States. These pipelines carry crude oil, HGLs, and petroleum products – which include gasoline, diesel, jet fuel, and other refinery products. This database includes projects that date back to 2010. Our database contains project types, start dates, capacity, mileage, geographic information, and project status. We track expanded, reversed, converted, and new pipeline projects. Not all pipelines are independent projects. Some projects are connected to each other and carry the same liquid to its final destination. As a result, simply adding together the capacity of all projects would result in overestimating or double-counting the ability to deliver to customers. The Liquids Pipeline Projects Database complements our natural gas pipeline projects table. We update our Liquids Pipeline Projects Database based on the best available information from pipeline company websites, trade press reports, and government documents, such as U.S. Department of State permits for border crossings. We release updates to the database twice each year: in the late spring and the fall. The data reflect reported plans. They are not a forecast and do not reflect our assumptions on the likelihood or timing of project completion.
Army Corps decision could tack years onto Enbridge Line 5 tunnel timeline -Tack another delay onto the Line 5 tunnel construction timeline. Federal regulators this week announced they will thoroughly examine the potential environmental impacts of Enbridge Energy’s plan to encase the petroleum pipeline inside of a tunnel beneath the Straits of Mackinac, a review that could take years. The decision by the U.S. Army Corps of Engineers all-but-guarantees something that had become increasingly evident over the past year: Enbridge Energy’s plan to begin building the tunnel this year and complete it by 2024 is not realistic. Instead, tunnel construction may not begin for years, if it happens at all.One study found that such federal reviews, known as environmental impact statements, take an average of nearly 3-and-a-half years to complete. They also require the Corps to closely study alternatives to the tunnel project.In an email to Bridge Michigan on Thursday, Enbridge spokesman Ryan Duffy said the company is “taking a look at the timeline” but has not yet identified a new timeline.In a statement Wednesday, Acting Assistant Secretary of the Army for Civil Works Jamie Pinkham said the agency received thousands of public comments and tribal input on the controversial tunnel project, which is supported by Republican lawmakers but opposed by Gov. Gretchen Whitmer and many legislative Democrats as well as environmental groups.”I have concluded that an EIS is the most appropriate level of review because of the potential for impacts significantly affecting the quality of the human environment,” Pinkham said.The decision was met with disappointment from Canada-based Enbridge, and cheers from environmentalists who have long argued the company’s construction timeline was unrealistically aggressive.”Enbridge remains intensely focused on project permitting and the sustained and safe operation of Line 5 until the tunnel is completed,” a company statement said.Its opponents, meanwhile, said the Corps’ decision will bring needed scrutiny to a project whose environmental impacts, they argue, are too great to accept.
Canada: Line 5 lawsuit should pause until treaty talks with U.S. are complete ⋆ The Canadian government is asking again that the litigation between Michigan and Canadian oil company Enbridge pause as officials from both countries hold talks about the potential of a Line 5 shutdown. Michigan and Enbridge are currently awaiting a decision from a federal judge on which court – state or federal – will preside over the state’s lawsuit to enforce Gov. Gretchen Whitmer’s Line 5 shutdown order. That order took effect on May 12, but Enbridge has refused to comply without the backing of a court order. Oil continues to flow through the 68-year-old pipelines under the Straits of Mackinac despite Whitmer’s continued warnings. On June 1, the government of Canada submitted a brief of amicus curiae on behalf of Enbridge. It argued that the court should take into account the 1977 Treaty between Canada and the United States, consider the treaty issues presented by a Line 5 shutdown and ultimately prevent the “premature” enforcement of Whitmer’s shutdown order. The 1977 Treaty, signed by former President Jimmy Carter, set forth agreements between the parties as related to transit pipelines that travel through both countries. On June 21, the Canadian government’s counsel submitted a filing to update the court on those treaty talks and again ask that the litigation be held in abeyance. State panel doesn’t have to consider climate change in Line 5 tunnel permit decision, judge rules “The international implications of the proposed shutdown have been raised by the Prime Minister of Canada with the President of the United States,” writes attorney Gordon Davies Giffin on behalf of the Canadian government. “They have also been the subject of discussions between the Foreign Minister of Canada and the United States Secretary of State, the Justice Minister of Canada and the United States Attorney General, the Natural Resources Minister of Canada and the United States Secretary of Energy as well as the Transport Minister of Canada and the United States Secretary of Transportation. “These discussions, along with interventions to the Department of State and the White House by the Ambassador of Canada have resulted in the establishment of a bi-lateral process in which representatives of the two countries are meeting biweekly to address the potential shutdown, including in the context of the 1977 Treaty,” Giffin continued. He noted that the state of Michigan previously argued against Canada’s request for abeyance. In its June 2 reply brief, the state said “there is no evidence that negotiations under the Treaty itself are in progress.”
PIPELINES: Biden backing of Maine oil ban fuels Line 5 battle — Thursday, July 1, 2021 — The Justice Department is defending a town’s effort to block shipments of Canadian crude oil from its port in Maine, boosting confidence among supporters of an effort in Michigan to shut down Enbridge Inc.’s Line 5 pipeline along the U.S.-Canada border.
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