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..
meanwhile, 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…
meanwhile, 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..,…
even with 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...
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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°F 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°F to 1,600°F 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.
EIA estimates drilled but uncompleted wells for key oil and natural gas basins – EIA - We release an updated inventory of what we consider drilled but uncompleted wells (DUCs) each month in ourDrilling Productivity Report (DPR). We publish updates to DUC estimates by region in a publicly accessible spreadsheet. In May 2021, the most recent month available, we estimated that the United States has about 6,521 DUCs in seven major tight oil and shale natural gas basins, up from about 4,425 DUCs in 2013, the earliest year in the data series. Nearly 40% of DUCs (or 2,616 DUCs) are in the Permian Basin, located in western Texas and eastern New Mexico.We estimate that the U.S. DUC inventory peaked at 8,874 DUCs in June 2020. From June 2020 through May 2021, we estimate that DUCs declined by 27%, or by 2,353 DUCs. Since the COVID-19 pandemic began, exploration and production (E&P) companies have cut capital expenditures, deployed fewer rigs, and reduced oil and natural gas production in response to lower demand and lower prices. DUCs help operators produce oil and natural gas at a lower cost.We estimate DUCs by examining the difference between records of drilled wells and completed wells each month; the difference equals the net change in the DUC inventory, or well count. Our DUC inventory estimates depend on assumptions about the wells reported to FracFocus.We estimate that most DUC wells are completed and begin producing hydrocarbons within one year after they are drilled. However, the timeline for completing wells can vary based on a variety of factors, including the prices of crude oil, petroleum products, and natural gas. E&P companies maintain DUC well inventories to ensure the well completion rate remains flexible. For instance, E&P companies coordinate the drilling and completion of wells to minimize operational delays. Generally, E&P companies maintain a DUC backlog that can sustain oil or natural gas production for several months so that they always have wells they can complete quickly. Because new oil and natural gas wells have decline rates that can be as high as 60%–70%, E&P operators need a constant supply of new wells that are ready to be completed to maintain steady production levels.
Officials: 2 killed in natural gas line explosion in Texas - Two people were killed and three injured in a natural gas pipeline explosion in Texas, officials said. The deadly blast happened around 4 p.m. Monday at an Atmos Energy facility in Collin County near Farmersville, about 35 miles (56 kilometers) northeast of Dallas. Collin County Sheriff Jim Skinner said the explosion appeared to be an accident but he invited the FBI to assist in the investigation. It was not immediately known what caused the blast. Those involved in the explosion were contractors for Atmos Energy, and the Collin County Sheriff's Office said Monday night the contractors were employees of Bobcat Contracting and Fesco Petroleum Engineering. Two of the injured were taken to a hospital. The workers were servicing a gas line when the explosion happened, Farmersville police Chief Mike Sullivan told WFAA-TV. The Princeton and Farmersville fire departments, Collin County EMS and multiple other local law enforcement agencies responded to the blast. 'œOur prayers are with those who were affected by the events in Farmersville, Texas, today,' Atmos Energy said in statement. 'œOut of respect for their privacy, we are not releasing any names or additional details at this stage,' the statement added.
Collin County explosion: What we know - Officials have released the identities of the two men killed Monday in a gas line explosion. Three others were injured in the explosion that happened in an unincorporated area of Collin County near Farmersville, officials said. The men were identified as 22-year-old Ethan Knight of Mesquite and 35-year-old Deric Tarver of El Campo. Princeton and Farmersville fire departments, Collin County EMS and multiple other local law enforcement agencies responded to the explosion, which was reported around 4 p.m. in the area of Farm to Market Road 2756 near Highway 78. According to the Farmersville police chief, the people involved in the explosion were contractors for Atmos Energy, not actual Atmos employees, who were servicing a gas line in the area when the explosion happened. The Collin County Sheriff's Office said Monday night the contractors were employees of Bobcat Contracting and Fesco Petroleum Engineering. Two of the people injured were taken to the hospital. Sheriff Jim Skinner said while the explosion appears to be an accident, he has invited the FBI to assist in the investigation. The National Transportation Safety Board is also investigating. It's unclear at this time what caused the explosion.
Study: EPA underestimated methane emissions from oil and gas development - The Environmental Protection Agency (EPA) has underestimated methane emissions caused by oil and gas production by as much as 76 percent, according to research published Tuesday in the Journal of Geophysical Research: Atmospheres. Researchers from Pennsylvania State University collected data in the mid-Atlantic, mid-South and central Midwest of the U.S. from 2017 to 2019, tracking the movement of carbon dioxide, methane and ethane within weather systems. They then studied ethane-to-methane ratios from oil and gas production basins and compared to them an EPA inventory of those emissions. The assessment found emissions at levels between 48 percent and 76 percent higher than the EPA's estimates. The researchers said they specifically analyzed ethane because it is only produced alongside certain methane emissions, whereas methane can be produced naturally and by landfills. Ethane also only lingers in the atmosphere for months at a time and offers a clearer picture of how recent the methane emissions occurred. In a statement to The Hill, the EPA said its greenhouse gas emissions inventory methods are continually updated based on stakeholder feedback. "Given the variability of practices and technologies across oil and gas systems and the occurrence of episodic events, it is possible that the EPA’s estimates do not include all methane emissions from abnormal events," an agency spokesperson said. "For many equipment types and activities, the EPA’s emission estimates include the full range of conditions, including 'super-emitters.' For other situations, where data are available, emissions estimates for abnormal events are calculated separately and included in the GHG Inventory," the spokesperson added. "The EPA continues to work through its stakeholder process to review new data from the EPA’s Greenhouse Gas Reporting Program (GHGRP) and research studies to assess how emissions estimates can be improved."
INTERIOR: Watchdog: Agencies use outdated systems to track oil and gas -- Monday, June 28, 2021 -- The Interior Department's use of outdated, aging data systems to track information like oil and gas permit approvals compromises its oversight responsibilities, according to a Government Accountability Office report released today.
Satellite images reveal where large amounts of methane are being released in Permian Basin –(videos) An international team of researchers has found a way to isolate individual methane contributors in the Permian Basin. In their paper published in the journal Science Advances, the group describes using satellite images to isolate sites that are releasing large amounts of methane into the atmosphere in the Permian Basin.The Permian Basin is a large sedimentary basin situated in the southwest United States. It includes parts of Texas and New Mexico, and has become a major source of shale oil and natural gas extraction. Prior research has shown that as part of shale oil and natural gas extraction, gases are released into the atmosphere. To prevent these releases, most extraction operations burn the gas as it is released. But, as the researchers with this new effort have found, these operations in the Permian Basin are missing a lot of themethane emissions, which are winding up in the atmosphere as a greenhouse gas. Prior research has suggested that as much as 20% of all methane emissions in the U.S. come from the Permian Basin.Prior efforts to measure and monitor gas emissions at individual shale oil and natural gas extraction and processing sites have involved the use of ground-based sensors. But these efforts have met with limited success due to the size of the areas being studied. In this new effort, the researchers turned to satellites equipped with hyperspectral capabilities, which image bands of the electromagnetic spectrum. Analysis of imagery from these sources allowed for measuring the amounts of gases emitted from relatively small sources on the ground.Compilation of infrared video footage for several large methane emission sources in the US Permian Basin. In some cases, simultaneous visible light footage is also shown. Credit: PermianMAP, Environmental Defense Fund, 2021 In studying the imagery from China's Gaofen-5 and ZY1 satellites and Italy's PRISMA mission, the researchers were able to isolate individual sources of methane emissions in the Permian Basin. They pinpointed 37 methane plumes from individual sources that had emissions higher than 500 kilograms per hour. They estimate that the sources they found contribute between 31 and 53% of all emissions in the parts of the basin they studied. They also suggest that current methods to prevent methane emissions in the shale oil and natural gas extraction industry in the Permian Basin are not sufficient—the actual emissions represent a major contributor to global warming.
Big Oil and Gas Kept a Dirty Secret for Decades. Now They May Pay the Price -After a century of wielding extraordinary economic and political power, America's petroleum giants face a reckoning for driving the greatest existential threat of our lifetimes.An unprecedented wave of lawsuits, filed by cities and states across the US, aim to hold the oil and gas industry to account for the environmental devastation caused by fossil fuels – and covering up what they knew along the way.Coastal cities struggling to keep rising sea levels at bay, midwestern states watching "mega-rains" destroy crops and homes, and fishing communities losing catches to warming waters, are now demanding the oil conglomerates pay damages and take urgent action to reduce further harm from burning fossil fuels.But, even more strikingly, the nearly two dozen lawsuits are underpinned by accusations that the industry severely aggravated the environmental crisis with a decades-long campaign of lies and deceit to suppress warnings from their own scientists about the impact of fossil fuels on the climate and dupe the American public. The environmentalist Bill McKibben once characterized the fossil fuel industry's behavior as "the most consequential cover-up in US history". And now for the first time in decades, the lawsuits chart a path toward public accountability that climate activists say has the potential to rival big tobacco's downfall after it concealed the real dangers of smoking..
How Last Century’s Oil Wells Are Messing With Texas -Ashley Watt is nothing if not a friend of fracking. She’s invested in mines that supply the sand frackers blast into the ground. Her family owns a ranch larger than Manhattan that’s home to hundreds of oil and natural gas wells. Her Twitter handle is “Frac Sand Baroness.”That’s what made it all the more jarring almost three weeks ago when Watt began publicly railing against one particular oil driller for leaks on her land. Noxious wastewater from oil drilling began leaching across the ground, endangering people and livestock. By her count, the pollution has killed four cows and two calves so far. Chevron Corp., which drilled the 1960s-era wells that polluted Watt’s land, brought in earth-moving equipment and a well-control crew, even though it had sold most of its interests there years ago. It took 10 days to halt the first leak. Given the hundreds of other aging wells dotting the land, it’s done little to put Watt’s mind at ease.“I am not anti-oil industry,” Watt said in an interview. “That is the economy here. It’s a good business.” At the same the same time, she said, “We have to be responsible stewards. If we can’t do it right here in the Permian Basin, then how can we do it right anywhere? Nobody should let us in if we’re going to act like this.”And just like that, Watt — whether she liked it or not — became an ally to scores of environmentalists and activists who’ve been warning for years that America is on the verge of an environmental disaster. Long before the advent of shale drilling techniques that fueled the greatest move toward energy independence the nation’s ever seen, conventional oil explorers left the country pierced with millions of defunct wells that are aging by the day and increasingly springing leaks.“There’s this enormous backlog” of abandoned wells, “and we don’t have financing in place to clean them up,” said Daniel Raimi, a fellow at the non-profit research group Resources for the Future. “We’ve seen very clearly that existing regulatory structures, particularly at the state level, have not properly incentivized companies to clean up their infrastructure.”
How California’s Drought Puts Pressure On Natural Gas Prices In Texas -A drought in California is stressing the power grid, forcing that state to use more natural gas. So, is this demand driving up natural gas prices in Texas?Matt Smith, director of commodity research at ClipperData told Texas Standard that the drought means hydropower generation in California is down significantly. Hoover Dam, which supplies hydroelectric power for California, Nevada and Arizona, has cut capacity by one-quarter, for example.“California is relying more on other sources, on fossil fuels, as summer heats up,” Smith said.The state imports more than 90% of the natural gas it uses from out of state, and the need to bring in more has affected prices.“The southwest gas is ultimately coming from Texas,” Smith said.Natural gas prices behave somewhat like oil prices, he says.“After all, a lot of natural gas production in Texas is from what’s known as ‘associated gas,’ which is essentially natural gas which is coming out of the ground as a byproduct as producers go after the more valuable product of crude oil,” he said.Even though commodity prices are up, Smith says production is down right now as drillers cut back on costs.
Far From Texas, Huge Gas Bills Stoke Anger After February Freeze – WSJ - An angry backlash is building across the middle of the U.S. as states step in to help their constituents pay billions of dollars in natural-gas bills racked up during February’s freeze.While most escaped the blackouts that occurred in Texas, states from Minnesota to Kansas are having to help local utilities, businesses and homeowners cover February bills after natural-gas prices surged from around $2 per million British thermal units to as much as $1,200 in parts of the country.Lawmakers and regulators in Minnesota, Oklahoma, Missouri, Arkansas and Kansas have called for investigations into market manipulation and are exploring regulatory changes. Republican and Democratic leaders in some of the states said it may be time to reconsider whether interstate gas markets, deregulated since the 1980s, need greater federal oversight to prevent a similar economic calamity from happening again. The February storm caused wellheads and pipelines to freeze in Texas and other gas-producing states, crimping supplies just as millions of customers cranked up the heat. The effects were felt far from the Lone Star State, leaving many homeowners and businesses with monthly bills hundreds or even thousands of times as large as usual.In Oklahoma City, the Villagio senior living center received a February gas bill of $44,527—about 50 times more than the month before—from its gas marketer, Constellation, a subsidiary of Chicago-based Exelon Corp. EXC -0.69%“It was shocking, and it has an impact on residents, on things we were going to do,” said Tyler Gable, a representative of the assisted-living facility’s owner, Blackwood, which is contesting the bill. Oklahoma regulators said the weeklong freeze generated as much as $5 billion in gas bills there. That has left some lawmakers in the reliably Republican state to call for further regulation of natural-gas producers, one of the most influential industries in Oklahoma. “I cannot for the life of me understand how we saw it go from $2 to $1,200 and back down to $2 in the span of the week; that’s not real,” said Garry Mize, a Republican who is chairman of the utilities committee in Oklahoma’s House of Representatives. referring to natural-gas prices. “It’s hard on a political level because you’d like to believe that free markets work all the time.” Mr. Mize helped draft legislation signed into law in April that will allow utility companies to stretch the impact to customers over 10 years by securitizing rate payments and selling them as bonds. Without the measure, he estimated that ratepayers who normally pay an average bill of $100 a month would have seen bills for February reach around $1,900.
Wastewater Problem Could Cap U.S. Shale Growth - Hydraulic fracturing, the technology that made the United States the world’s top oil and gas producer, has earned a really bad rap. Much of this ill reputation has had to do with increased seismic activity in shale oil and gas regions. But research cited by the U.S. Geological Survey showed a few years ago that it’s not fracking itself that is the problem. The problem is the disposal of wastewater, and it is not going away.Earlier this month, Rystad Energy warned in a report that the number of seismic events in key oil-producing regions has been on the rise. Since 2017, quakes of a magnitude above 2.0 had quadrupled. Seismic activity will increase further this year, Rystad analysts added, if the U.S. oil and gas industry continued to produce hydrocarbons the same way.The amount of water that is used in the drilling and fracking of shale oil and gas wells varies widely. It can be anywhere from 1.5 million gallons to 16 million gallons, according to the U.S. Geological Survey. But that was several years ago. Since then, water use has only grown as fracking activity has increased. After drilling and fracking, the used water—typically called produced water—is disposed of in underground injection wells. The more water is injected, the more likely seismic events become because, put simply, millions upon millions of gallons of water injected into rock formation change the pressures in this formation, triggering increased seismic activity.Now, the USGS makes a point of noting that not all wastewater injection wells will lead to an increased likelihood of quakes. Still, the data cited by Rystad Energy indicates that even if some wells lead to more quakes, it’s bad enough. Since the start of this year, the consultancy noted, there have been 11 earthquakes in Oklahoma, Texas, Louisiana, and New Mexico with a magnitude of above 3.5. This compares with 14 such events for the whole of 2020 and six in 2018 and 2019 each. Now, someone with a grim sense of humor might say quakes are a good indication of the recovery of oil and gas drilling after the worst of the pandemic, but the 2020 number is worrying because it was recorded in a year when drilling activity was severely depressed because of the pandemic. Indeed, the Rystad data showed that last year oil and gas drillers disposed of 11.3 billion barrels of produced water, down from 12.4 billion barrels a year earlier and 11.5 billion barrels in 2018. Yet seismic activity increased even further last year.Drilling activity is also increasing now that oil prices have recovered faster than many expected. The increase is still cautious as upstream companies still remember the devastating blow their industry suffered last year. Yet demand is growing. This could lead to not only higher prices still but more drilling and, consequently, more wastewater disposal. Alternatively, it could lead to more water recycling and reuse.
House passes resolution that would repeal a Trump-era EPA rule on methane emissions - The House voted Friday to repeal a Trump-era rule that rolled back regulations of methane emissions from oil and gas industries, sending a resolution to President Joe Biden's desk for his signature as his administration looks to combat climate change. The final vote was 229-191. All Democrats supported the resolution, and 12 Republicans broke ranks and supported it as well. The resolution would restore an Obama-era rule that controlled leaks of methane from oil and gas operations. In September, the Trump administration rolled back the 2016 regulation limiting methane leaks by requiring companies to monitor and repair new natural gas equipment. The Senate passed the resolution at the end of April under the Congressional Review Act, which allows Congress to roll back regulations imposed by the executive branch. The CRA allows Congress to rescind within 60 legislative days a regulation put in place by an administration without having to clear the 60-vote threshold in the Senate that is necessary for most legislation. The Republicans who voted for the resolution were Reps. Fred Upton of Michigan, Jeff Van Drew of New Jersey, Peter Meijer of Michigan, Pete Sessions of Texas, Brian Mast of Florida, Andrew Garbarino of New York, Brian Fitzpatrick of Pennsylvania, John Katko of New York, Young Kim of California, Nancy Mace of South Carolina, Tom Reed of New York and Maria Elvira Salazar of Florida. A spokesperson for the Environmental Protection Agency called Friday's vote "an important step" for protecting public health and combating the climate crisis. "Today's Congressional action is an important step toward restoring crucial measures to protect public health from methane and other harmful air pollutants from new and modified oil and gas facilities, a critical move in tackling the climate crisis and protecting our communities," the EPA spokesperson said in a statement.
U.S. crude inventories depleting at record pace on surging oil demand --Crude inventories in the U.S. are falling at the fastest rate in decades as demand continues to rebound, prompting a rally in the oil futures market. Over the last four weeks total stockpiles, including the Strategic Petroleum Reserve, have fallen at a rate of 1.15 million barrels a day, marking the largest four-week decline on a rolling basis in Energy Information Administration Data going back to 1982. Meanwhile, Nymex calendar spreads rallied Wednesday, with the September West Texas Intermediate futures contract rising to $1 a barrel premium over October for the second time this month, pointing to expectations for ongoing supply tightness through the summer. The record rate of drawdowns underscore the strength of the U.S. oil demand recovery just ahead of a critical meeting between OPEC and its allies on Thursday to debate a potential output increase. Americans are taking to the roads and skies at increasing numbers as the country emerges from months of lockdowns. To meet demand, oil refiners boosted crude processing to levels only seen before the pandemic. At the same time U.S. drillers have been slow to respond to the oil prices, which are up more than 50% so far this year. Domestic crude production is holding at roughly 15% below peak levels seen early last year. Further supporting the so-called timespreads are stockpile levels in Cushing, Oklahoma, the delivery point for WTI futures. Inventories in the hub are at the lowest levels in over a year. Analysts are estimating and traders are betting that supplies will drop to multi-year lows by the end of the summer. Prior to this month, the spread between the second month and third month WTI contracts hadn’t exceeded $1 a barrel since 2018. Overseas interest in American crude has also been climbing despite a bumpy recovery from the health crisis in Asia and Europe. Exports of U.S. crude remain strong even as rallies in WTI have narrowed its spread to less than $2 a barrel relative to global benchmark Brent. The global supply situation looks set to remain tight as OPEC and its allies have yet to come to a consensus on how much shut-in oil to return to the market at a time when there is much demand uncertainty. That has delayed preliminary talks between ministers by a day to allow more time for a compromise before Thursday’s discussion. The International Energy Agency has warned of supply deficits in the second half of this year unless the group acts fast to add more crude.
Fish, propane, cash: Not everyone loves Enbridge generosity in the Straits — Barbara Brown was visiting a friend when she heard about Enbridge’s latest act of generosity in town. “She asked me if I had gotten my whitefish,” Brown said, and showed a bag of “beautiful, big fillets” bearing the company’s logo. The Canadian petroleum giant, whose Line 5 pipeline crosses the Straits of Mackinac just outside town, had co-sponsored a giveaway at the local community action agency, working with St. Ignace-based Massey Fish Company to distribute 2,000 pounds of whitefish to 400 seniors. The friend, like Brown, is not a fan of Enbridge. But for the friend, about 40 bucks worth of free whitefish was reason enough to set differences aside, if only momentarily. Brown felt differently, viewing the whitefish as an effort to woo residents to Enbridge's side. “I thought it was an aggressive influence campaign,” said Brown, a former state judge who serves on the board of For Love of Water, a northern Michigan nonprofit that opposes Line 5. Since the company’s oil pipelines became a hot-button political topic in Michigan, Enbridge has steadily ramped up its physical and philanthropic presence in the Straits, hiring staff, installing surveillance infrastructure, buying land and donating to all manner of local causes. But as the company continues to defy a state order to shut down Line 5, its opponents view the largesse as part of an effort to curry favor with local residents and public officials who could influence debates about the pipeline’s fate. Others welcome the donations as further evidence that Enbridge cares about the community — stewardship that they say is also evident in the company’s efforts to better monitor its 68-year-old pipeline after a series of anchor strikes since 2018 heightened concern about a potential oil spill. The company’s growing local presence begs a question: Where does one draw the line between being a good corporate citizen and political lobbying?
Minnesota Sheriff Blockades Anti-Pipeline Camp -A Minnesota sheriff’s office blocked access Monday morning to one of the protest encampments set up to resist the Enbridge Line 3 tar sands pipeline. In a notice delivered at 6 a.m. to pipeline opponents, who own the property, the Hubbard County Sheriff’s Office stated that it would no longer be allowing vehicular traffic on the small strip of county-owned land between the driveway and the road. Sheriff’s deputies arrived with trucks carrying building materials, a witness said. Join Our Newsletter Original reporting.Fearless journalism.Delivered to you. “I was handed a notice that states the sheriff will be installing a physical barricade across the driveway to our private property,” said Tara Houska, an Anishinaabe co-founder of the anti-pipeline Giniw Collective, which organized the camp. “He’s saying that we have no right of access to our private property by vehicle.” The pipeline opponents, also known as water protectors, plan to take legal action. “This is quite simply nothing less than an overt political blockade,” said Mara VerheydenHilliard, an attorney for the pipeline opponents and director of the Partnership for Civil Justice Fund’s Center for Protest Law and Litigation. “This is an outrageous and unlawful effort to blockade people who are engaged in protected First Amendment activity and to punish them for their opposition to the Enbridge pipeline, where Enbridge is serving as the paymaster for Hubbard County sheriff.” Verheyden-Hilliard was referring to an Enbridge-funded escrow account set up by the Minnesota Public Utilities Commission to reimburse public safety agencies for activity related to Line 3. So far Enbridge has reimbursed Hubbard County $2,660 for riot helmet face shields and chest protectors as well as equipment related to removing pipeline opponents locked to construction infrastructure. The Hubbard County Sheriff’s Office did not respond to a request for comment
Pipeline workers arrested in northern Minn. sex trafficking sting - – Two Enbridge Line 3 pipeline workers from Bemidji were among six men arrested in a northern Minnesota sex trafficking sting this weekend.Enbridge said Monday both were immediately fired."Enbridge and our contractors have zero tolerance for illegal and exploitative actions," the company said in a statement. "That is why we are joining with our contractors and unions to denounce the ... actions of those who participate in sex trafficking."The sting took place on Friday and Saturday in Beltrami County, authorities said."During the operation, suspects responded to an ad on a sex advertisement website," according to a Minnesota Bureau of Criminal Apprehension (BCA) news release. "Investigators arrested the suspects as they arrived at an arranged meeting place for a commercial sex crime." The BCA's Human Trafficking Investigators Task Force worked with the Tribes United Against Sex Trafficking Task Force, the Beltrami County Sheriff's Office and the Bemidji Police Department.
Nearly 800 Line 3 pipeline workers tested positive for COVID-19 - A total of 788 workers building Enbridge’s Line 3 pipeline through the US state of Minnesota have tested positive for COVID-19, according to data obtained by Al Jazeera from the Minnesota Department of Health (MDH). The project, the largest in Enbridge history, would replace a 1,700-kilometre (1,000-mile) oil pipeline that runs from Edmonton, Alberta in Canada to Superior, Wisconsin in the US. Construction is on track to continue until the end of the year, amid protests andIndigenous resistance to the project.In late November, amid the worst wave of the pandemic in the state, thousands of out-of-state workers arrived to build the pipeline through rural communities in northern Minnesota.The data shows that shortly after construction began on December 1, 2020, a wave of pipeline workers contracted the virus. The winter surge in cases has subsided, but Line 3 workers are still contracting COVID, as the highly contagious Delta variant is now taking hold in the US.Three workers were hospitalized, and none have died, according to MDH.Healthcare workers tell Al Jazeera they believe the bulk of cases could have been prevented.In November, more than 200 healthcare workers and Indigenous tribal leaders petitioned Governor Tim Walz to issue an emergency stay on construction until after vaccines were widely available. But Walz allowed the project to go ahead.
Minnesota's OK for Enbridge to temporarily move 5B gallons of water sows tension - Some environmentalists and Ojibwe tribes are angered at the state's decision to allow Enbridge to move 5 billion gallons of water as it builds a replacement for its Line 3 pipeline — up from 510 million in the company's original permit.The water involved is in shallow aquifers, and it is temporarily being moved so that it doesn't drain into the pipeline's trench during construction.It's pumped from wells 10 to 15 feet deep and moved nearby to seep back into the soil to restore groundwater balance.Earlier this month, the Department of Natural Resources (DNR) approved Enbridge's request to move 10 times as much water as originally planned, amending a permit it originally granted in November. The company started construction late last year, and the 340-mile oil pipeline is now more than 60% built.White Earth and Red Lake — the state's two largest Ojibwe bands — say they weren't adequately consulted about the DNR's decision.And critics say the sheer volume of water transferred could endanger the ecosystem near the pipeline, including wild rice beds, and even more so during the current drought."The surface water and shallow groundwater is more sensitive to drying out in these conditions," said Christine Dolph, a research scientist at the University of Minnesota's ecology department. "The huge increase in volume is really concerning, and it is unclear why [Enbridge] would have been off by so much. It indicates they don't understand the system they are working in."Enbridge requested the increase in "construction dewatering" early this year, saying winter conditions were much wetter than expected. Also, the company said at the time that it was switching from sump pumps to move water to "well point" water extraction.The latter, which state agencies recommended to Enbridge, decreases turbidity — a good thing — but requires the transfer of more water.In its amended permit issued June 4, the DNR concluded that Enbridge's increase in dewatering was necessary for the safety of workers in the pipeline's trench."Our evaluation of nearby wetlands is [also] that the temporary dewatering of trenches is not expected to have any significant impact on nearby wetlands or other surface waters, even in drought conditions," the DNR said in an e-mail to the Star Tribune."The current drought conditions may actually reduce the need for dewatering in some areas because less water may be seeping into trenches in drought-affected areas," the agency said.Enbridge, in a statement to the Star Tribune, said it expects soggy conditions to remain, giving no indication it would reduce dewatering.
Bitcoin fracking turns waste gas to gold in Montana | Energy News Network --Houston-based Kraken Oil & Gas has dug in here for the oil released by hydraulic fracturing, or fracking, the technology that, along with horizontal drilling, spurred the Bakken oil boom in North Dakota and this stretch of eastern Montana in the late 2000s and early 2010s. Even as the boom has cooled from its peak over the last decade, production has continued on pads like this one, where the liquid oil pulled from the earth is piped away, headed toward refineries that convert it to gasoline or plastic. On sites without a pipeline connection, producers truck liquid oil away in tanks instead.Bakken oil, though, commonly comes to the surface with a not-necessarily-welcome companion: natural gas that is both harder to transport from remote well pads and less profitable to sell. In part because one component of that gas, methane, is a potent greenhouse gas — an estimated 25 times as effective at trapping planet-warming heat in the atmosphere as carbon dioxide — companies like Kraken routinely burn off unwanted waste gas in well pad flares, converting as much of the methane as they can to the comparatively benign CO2.The inherent wastefulness of flaring, as well as its climate implications, have attracted the attention of government regulators and environmentalists. North Dakota, for example, has had flaring reduction targets as far back as 2014 in an effort to encourage the oil industry to invest in the infrastructure it needs to capture byproduct gas and do something useful with it.More recently, as Bitcoin and other cryptocurrencies have emerged as major investment options, the cheap energy going up in smoke on well pads has also caught the attention of tech-savvy entrepreneurs.Unlike traditional currencies like the American dollar, which are regulated by central banks, Bitcoin and its peers are managed by digital exchanges that use decentralized databases and cryptography to keep track of ownership. New units of Bitcoin are created by digital mining, essentially performing computational gymnastics to unlock new bitcoins. Bitcoin mining, however, has become an increasingly difficult endeavor as the digital currency’s popularity has grown, requiring special-purpose hardware and tremendous amounts of electricity to power it. That power consumption has, in turn, seen the cryptocurrency industry criticized for its own impact on the climate. A Bitcoin mine operating out of an old mill building near Missoula, for example, attracted criticism after county officials said it was using as much power as a third of the households in the county. Additionally, researchers at the University of Cambridge estimate that Bitcoin currently consumes nearly 94 terawatt-hours of power a year globally, more than the combined consumption of the 108 million people who live in the Philippines.
The Keystone XL Pipeline Is Dead, but TC Energy Still Owns Hundreds of Miles of Rights of Way - When Richard Johnson heard that the Keystone XL pipeline had been canceled earlier this month, he felt a surge of relief. Johnson’s ranch lies directly on the pipeline’s planned route through the sandy plains of eastern Nebraska, and he had been tangling in court with the developer ever since the corporation used eminent domain to condemn a strip of his property in 2019.But relief quickly gave way to confusion and uncertainty when he learned that the condemnation would not necessarily be reversed, even if the pipeline is never built.As it prepared to construct Keystone XL, the Canada-based TC Energy secured hundreds of easements across farms and ranches up and down the 1,210 mile route through the Great Plains. For those landowners like Johnson who refused to sign easements, the company generally condemned the land through eminent domain proceedings. But now, even though it has canceled the project, TC Energy can retain the easements it secured indefinitely and use them for another purpose, or even sell them to other companies.“We’re still not sure where we’re at,” Johnson said. “If they secure an easement, they could sell it or assign it. To what it could be used for, I’m not real sure. But it’s that unknown that concerns me.” Even though the Keystone XL pipeline is dead, the more than decade-long fight over the controversial project is not. Pipeline opponents said the case highlights an emerging problem as the nation pivots away from fossil fuels. In Nebraska and many other states, they said, there are no laws or regulations that require pipeline developers to return easements to landowners if their projects are canceled or rejected, or after older pipelines are retired.“This has always been one of the concerns right from the beginning of fighting the pipeline,” said Jane Kleeb, founding director of Bold Nebraska, an advocacy group that helped lead opposition to Keystone XL. Kleeb worries that the route could now be used for a different pipeline. Even if the route is not used, she said, the lingering easements could hang over landowners, preventing them from developing parts of their property, diminishing its value and complicating future sales or transfers.“Those landowners, every single day, have this looming over them,” Kleeb said. “That tomorrow, a company could sell those easements to China, to Russia, to whoever, and they would have no say over that.”
SoCal spot gas prices soar as California ramps up thermal generation to keep cool | S&P Global Platts - Spot gas prices in Southern California climbed above $7/MMBtu in June 29 trading as the region turned to gas-fired generation to cope with an ongoing heat wave while power imports dropped. Cash SoCal city-gate gained 52 cents to reach $7.07/MMBtu in June 29 trading for next-day flows, according to preliminary settlement data. Spot gas price locations that represent entry points for gas flowing toward the SoCalGas system saw similar movement: SoCal Gas spiked $1.63 at $6.97/MMBtu. Thermal power demand in the California Independent System Operator footprint has exploded over the last several days since the West Coast heat wave began in earnest. CAISO data showed that thermal power generation increased 58% to 331 GWh on June 28, up from 210 GWh on June 26. While thermal power, the category used by the California system operator, include both gas- and coal-fired generation, there is only one remaining coal-fired power facility in California and the term largely refers to gas-fired generation. Lower power imports Even as California's total power demand rose, power imports into California dropped 36% to 85 GWh on June 28 from 133 GWh on June 26. Month-to-date daily power imports have averaged 125 GWh/d. The geographically expansive nature of the heat wave has meant that the Pacific Northwest's power and gas demand increased at the same time as Southern California. Portland and Seattle saw record-breaking temperatures over three consecutive days, beginning June 26 and peaking June 28 at 116 Fahrenheit and 108 F, respectively, according to the US National Weather Service. The "historic" and "unprecedented" heat wave, the US National Weather Service said June 29, resulted in excessive heat warnings, watches and advisories throughout most of the Northwest, Great Basin and California.
Nearly 400 gallons of oil spilled near Discovery Bay Yacht Harbor — The Coast Guard, California Department of Fish and Wildlife and Contra Costa County Fire Department responded to a diesel spill at Discovery Bay, near Stockton, on Monday morning. The Coast Guard Sector San Francisco watchstanders received notification around 10 a.m. from the National Response Center that approximately 400 gallons of gasoline spilled near the Discovery Bay Yacht Harbor. According to the Coast Guard, the leak came from a fuel line in the marina, and the fuel line was shut off after hundreds of gallons spilled. The Discovery Bay Yacht Harbor crew used oil absorbent tools for the area affected by the spill. The Coast Guard said it is currently investigating the cause of the spill. University of California Davis, Oiled Wildlife Care Network responded as well to care for the two Canada geese exposed to the oil spill. The Coast Guard said the geese were recovered and taken to a rehabilitation facility. The Oiled Wildlife Care Network asks that anyone with information regarding more wildlife affected by this oil exposure contact the network at 1-800-823-6926. No people were reported to be harmed by the oil spill.
Container vessel detained over oil spill -Container vessel detained over oil spill Container ship CSS Wind has been detained pending the payment of costs incurred for the cleanup of an oil spill from one of its containers on Wednesday. An estimated 2,000 litres of heavy crude oil had flowed into the sea at Gordon Cay. The ship should have left the Port of Kingston on Friday but has been prevented from doing so. Director of the Environmental Management and Conservation Division at National Environment and Planning Agency, Anthony McKenzie, told The Gleaner on Sunday that the agency took out an enforcement order against the ship and its local agent Perez y Cia Jamaica, barring the vessel from leaving port until the full cleanup costs have been determined. “We haven't concluded on that yet, we will conclude earlier in the week. So the ship is not able to move at this time.” Captain Steven Spence of the Maritime Authority of Jamaica (MAJ) said the agency's investigation found that the hazardous liquid was stored in flexi bags, as against the conventional method of storage tankers, and that the bags fell victim to Jamaica's high tropical temperature. “I think that due to the high temperature there was some sort of explosion because I can see other containers bulging and there was a spill of about 2,000 litres of the liquid.” Spence further explained that instead of being placed in the cargo hold, the container was being transported on the ship's deck and expressed concern about the fact that there were at least 21 more flexi bags on board. He said the bags would not be allowed to continue the journey in this way. “I understand that the cleanup went very well but there are still more containers on board the vessel and those containers need to be discharged. They have to be discharged because it wouldn't be safe for the vessel to travel because there are other containers which are bulging,” said Spence. The incident reportedly occurred while crew members were conducting what should have been routine bunkering operations, which involves either taking on or discharging fuel, and that during the exercise, the liquid coated the starboard hull, plating it and entered the sea. The ship, which has a gross tonnage capacity of 9,978, was also served with a detention order by the MAJ under the Port State Control Regime, which empowers it to hold the vessel in port pending the completion of investigations or if it has any doubts that the vessel may be a danger to navigation. “The decision to detain a vessel is not something that we do lightly because the cost to the shipping company can be very high and you have to make sure it is not a spurious detention. You have to really have good cause and in this case, they spilled hazardous material, heavy oil into the sea,” said Brady.
Panic grips residents as oil pipeline leaks in Lagos--Fear gripped the residents of Ijeododo Road, Igando, Alimosho, Local Government Area, Lagos, on Saturday, following a Premium Motor Spirit, PMS, popularly, called petrol, pipeline leakage in the area.The incident which occurred in the afternoon when some of the residents noticed the leakage at Igando enroute Ijeododo road and raised the alarm.Eyewitnesses account said as soon as the leakage was noticed after the heavy downpour, some of the residents on apparent fear started running helter-skelter.The Director-General, Lagos State Emergency Management Agency, LASEMA, Dr. Femi Oke-Osanyintolu, confirmed the development.Oke-Osanyintolu, at press time, 4pm, however, said the situation has been brought under control as emergency responders comprising of Lagos Fire and Rescue Services,LASEMA, and men of the Nigeria Police are at the sight of the leakage to prevent possible explosions in the area as people were advised to stay away from the area.“The agency has activated its response plan to the above. Members of the public are to exercise caution. All stakeholders are on ground to prevent a secondary incident,” Oke-Osanyintolu stated.
ONGC’s crude oil pipeline leaks into agricultural field near Mannargudi, paddy cultivation affected - Paddy seeds sown on a field at Melapanaiyur near Mannargudi were affected due to a leak in the crude oil pipeline of the Oil and Natural Gas Corporation (ONGC). The oil spill was noticed by the land owner, Sivakumar on Wednesday morning when he arrived at the field to irrigate the kuruvai crop cultivated by him through the direct sowing method. Immediately, ONGC officials were informed about the development and they started necessary work to plug the leak. Meanwhile, Mr.Sivakumar told reporters that only a compensation of ₹10 lakh would help negate the loss he had suffered now and in view of the contamination of the soil due to the oil leak, since it would take years to revive soil health. He said he had spent several thousands of rupees in sowing the kuruvai paddy seeds on his eight acres of land at Melapanaiyur. Talking to reporters, the village panchayat president, Jeevanandam demanded that the oil pipelines laid through the agriculture fields in the village be removed since they were laid two decades ago. Further, removal of the oil pipeline network would alone justify the declaration of the Delta districts as a protected agriculture zone, he maintained.
Kaohsiung oil spill drifts farther south - An oil spill in waters near Kaohsiung has expanded farther south, with the spill covering 290km2 of ocean as of Saturday. The spill occurred after a pipe cracked while it was connected to a tanker delivering oil to CPC Corp, Taiwan’s (CPC) Dalin refinery in Kaohsiung on Tuesday, the state-owned utility said. The pipe was split by large waves, the utility said, apologizing and taking responsibility for the spill. The oil slick stretches from the waters off Siaoliouciou (小琉球) to Pingtung County’s Checheng Township (車城), residents said. They said they were worried that the oil would drift farther south and affect waters near Kenting National Park in Pingtung County’s Hengchun Township (恆春), which contains valuable coral ecosystems. Hengchun Township Mayor Chen Wen-hung (陳文弘) and local fishers, as well as the offices of Democratic Progressive Party legislators Chou Chun-mi (周春米) and Chuang Jui-hsiung (莊瑞雄), have urged the CPC to clear the spill quickly. While the oil slick is not as severe as one caused by the Greek cargo ship Amorgos in 2001, it has affected a wider sea area, Kenting National Park Administration deputy director Hsu Shu-kuo (許書國) said, adding that the oil might affect coral reefs near the coastline. After the spill is cleaned up, the agency plans to commission researchers to examine underwater ecosystems, he said. The spill contains liquefied petroleum gas, gasoline, kerosene, diesel and other fuels — 10 to 15 percent is lighter substances that can evaporate in a couple of days, the Ocean Conservation Administration said.
Why Did Iraq Pull The Plug On Its $2 Billion Oil Deal With China? --Just when it looked like Iraq was becoming a regional leader it decided to halt a $2 billion pre-paid oil supply deal with China's state-owned Zhenhua Oil Co. despite aims to strengthen ties with China. Iraq decided to end a deal with Zhenhua and sell its crude supply to other customers as oil prices continue to rise. The deal with the Chinese company, that was agreed upon earlier this year, would have seen 4 billion bpd of oil supplied each month. The oil was expected to be ‘destination free’, meaning Zhenhua could sell it to other companies.However, government officials in Iraq are making the country’s budget priority clear as the State Organization for Marketing of Oil (SOMO) deputy director-general Ali al-Shatari stated, "For the time being we may say it is not applicable at this stage because of oil prices, which are high and we are in a better position and we are even generating additional profits in excess of what the Iraqi budget needs."The end of the Zhenhua deal follows recent announcements of big oil backing away from Iraq. Earlier this month, oil super-major, BP (-3.15%), said it wanted to change its operations in Iraq’s supergiant Rumaila oil field, to create a stand-alone company. U.S. super-major ExxonMobil (-2.55%) announced its intention to withdraw from Iraq’s West Qurna 1 oil field. And Royal Dutch Shell (-3.68%) got out long ago, ceasing operations in Iraq’s supergiant Majnoon oil field in 2017 and West Qurna 1 in 2018. There are several reasons for the Western supermajors’ exit from Iraq, including the movement away from traditional oil and gas towards low-carbon projects, persistent corruption in Iraq’s oil industry, and China’s dominance of Iraqi oil. However, we mustn’t overlook the fact that oil prices in Iraq have been steadily increasing since the beginning of the year, as the government promises higher export levels. SOMO’s crude was going for $65.842 a barrel in May, up 23.5% from January. And now Iraq is expecting as much as $80 a barrel, although no timeframe has been given for this confident prediction.
Oil prices could skyrocket if OPEC+ fails in pledge to deliver more supply - OPEC heads into Thursday's meeting with Russia and other allies with a better command of world oil prices than it has had in years, analysts said. OPEC+, the organization of oil-producing countries and its allies, is expected to consider adding between 500,000 and 1 million barrels per day, but analysts said there is some talk it may consider no increase. Reuters reported that an internal OPEC report points out that the market could fall back into an oil glut after the group reverses its 6 million barrels a day of production cuts by April 2022. The report gave a boost to oil prices Wednesday. Brent crude futures, the international benchmark, were trading just over $75 a barrel Wednesday. West Texas Intermediate crude futures for August were just under $74 a barrel, around their highest level since the fall of 2018. Oil prices rose Wednesday on a report of lower U.S. inventories. "This is their most important meeting in over year. They were staring down a grave situation with negative pricing last year, and they came together," Again Capital partner John Kilduff said. "The plan has been to return 500,000 barrels a month, and I think they'll stick to that. It's working for them because prices keep going higher and higher." OPEC is expected to consider extending its current production accord beyond the existing April 2022 end date, and analysts widely expect it to return 500,000 barrels to the market in August. "To me, the interesting story is if they roll over current cuts, how high do [prices] go. It's being discussed in terms of the potential options," RBC head of global commodities strategy Helima Croft said. She said the market has already priced in 500,000 barrels a day of additional production, and if it was higher than expected, prices would fall slightly. Croft said OPEC+ has become more flexible since Covid, and it can quickly adjust when it sees how big factors will affect the market. For instance, the U.S. and Iran have been discussing a new nuclear accord. If that happens, Iran could return at least 1 million barrels a day to the market. The timing of that is unclear, and that oil would have to be absorbed alongside OPEC's current production later this year if a deal is struck. "OPEC used to move like a battle ship. We had these biannual meetings. It was so hard to convene OPEC" during Covid, Croft said. She noted that OPEC operates now more like the U.S. Federal Reserve, with regular policy-setting meetings. "It means they really have directional control of the market," she said. The Organization of the Petroleum Exporting Countries, led by Saudi Arabia initiated monthly meetings this year, with the oil market in a state of flux as demand returns. OPEC Secretary General Mohammed Barkindo said Tuesday that OPEC expects demand to rise by 6 million barrels per day this year, with 5 million of that coming back in the second half of the year. "Now with the monthly meeting structure, they're more like a speedboat as opposed to a battleship. If the Delta variant is really demand-destructive in key geographies, they can reverse course," Croft said. "To me, this monthly meeting structure has given them flexibility to adjust quickly. And for market participants, everybody has to tune in. They are the story. ... This is how things have changed from 2015 when they were written off as irrelevant." Big changes in the market also changed OPEC, which had to cut production sharply last year as demand cratered and oil prices collapsed. Of less concern has been pressure from U.S. shale producers, who had previously moved aggressively to add new wells every time prices rose.
Oil Falls 2% on Rising COVID-19 Cases, Ahead of OPEC+ Talks -(Reuters) -Oil prices fell 2% to a one-week low on Monday after hitting their highest since 2018 earlier in the session, as a spike in COVID-19 cases in Asia and Europe put a brake on the rally before this week's OPEC+ meeting. Brent futures fell $1.50, or 2.0%, to settle at $74.68 a barrel, while U.S. West Texas Intermediate (WTI) crude fell $1.14, or 1.5%, to settle at $72.91. Those declines pushed both contracts out of overbought territory and were their lowest closes since June 18. Earlier in the volatile session, both benchmarks rose to their highest levels since October 2018. "The forecast for oil demand recovery over the summer may be a bit overestimated, and traders are facing a reality check this week as the (COVID-19) Delta variant reached Europe and as an infections surge in Southeast Asia and Australia is bringing back lockdowns," said Louise Dickson, oil markets analyst at Rystad Energy. Indonesia is battling record-high cases, Malaysia is set to extend a lockdown and Thailand has announced new restrictions. Australia also reported on Sunday one of the highest numbers of locally acquired coronavirus cases this year, triggering lockdowns in some cities. All eyes this week will be on the Organization of the Petroleum Exporting Countries and its allies, a group known as OPEC+, to see what happens at their meeting on Thursday. OPEC+ has increased supply by 2.1 million barrels per day (bpd) of oil from May to July after cutting supplies during the pandemic, and could decide to add more barrels in August after crude prices last week rose for a fifth week in a row. OPEC's forecasts point to an oil supply deficit in August and the rest of 2021 as economies recover from the pandemic, suggesting OPEC+ has room to raise output. Analysts at Australian bank ANZ and Dutch bank ING said they expect OPEC+ to increase output by about 500,000 bpd in August.
Oil Steadies as OPEC Fuels Demand Hopes Amid New COVID-19 Worries (Reuters) - Oil prices steadied on Tuesday as broad hopes for a demand recovery persisted, fueled by comments from OPEC's secretary general, slightly overshadowing travel curbs due to new outbreaks of the highly contagious Delta variant of the coronavirus. Brent crude futures settled up 8 cents, or 0.1%, at$74.76 a barrel, having slumped by 2% on Monday. U.S. West Texas Intermediate (WTI) crude futures settled up 7 cents, or 0.1%, at $72.98 a barrel, after a 1.5% retreat on Monday. Demand in 2021 was expected to grow by 6 million barrels per day (bpd), with 5 million bpd of that in the second half, OPEC Secretary General Mohammad Barkindo told Tuesday's meeting of the Joint Technical Committee of OPEC+, an alliance made up of OPEC states, Russia and their allies. "The current 'wild card' factor is the 'Delta Variant' of the pandemic that is resulting in rising cases and renewed restrictions in many regions," he said in a speech, a copy of which was seen by Reuters. The producer group is expected to gradually ramp up production in response to demand. "Barkindo's comments suggest that OPEC is not going to raise production quickly enough to keep up with demand," OPEC's demand forecasts show that in the fourth quarter global oil supply will fall short of demand by 2.2 million bpd, giving the producers some room to agree to add output. The market expects the rollout of vaccination programmes to brighten the demand outlook, even as the new variant rises, analysts said. "The narrative of the past few months has not changed: the war against the virus is being gradually won, the global economy and oil demand are recovering,"
Crude oil futures higher on bullish API crude draw, market awaits OPEC+ meeting -- Crude oil futures rose during the mid-morning trade in Asia June 30, as data from the American Petroleum Institute showed a large draw in US crude inventories, and as the market eagerly awaited the July 1 OPEC+ meeting. At 11:13 am Singapore time (0311 GMT), the ICE August Brent futures contract was up 43 cents/b (0.58%) from the previous close at $75.19/b while the NYMEX August light sweet crude contract was up 49 cents/b (0.67%) at $72.98/b. The data released by the American Petroleum Institute led to some bullishness in the market, as it showed a draw of 8.15 million barrels in the US crude inventories for the week ended June 25. The data was less positive with regards to downstream products inventories, showing gasoline and distillate inventories rising by 2.42 million barrels and 428,000 barrels, respectively. The market, however, was not swayed by the product builds, as they could be attributed to rising refinery utilization, which S&P Global Platts Analytics expects to have averaged 16.35 million b/d in the week ended June 25, up from an EIA-reported 16.11 million b/d during the week prior. The market remains optimistic about US products demand, and especially gasoline demand, with Apple Mobility data showing the US driving activity staying near record levels at 162% of the January 2020 baseline in the week ended June 25. The market will now be awaiting more comprehensive data from the Energy Information Administration, due to be released later June 30, for more pricing cues. Meanwhile, the market has its eyes set on the July 1 OPEC+ meeting, after the July 29 Joint Technical Committee provided little definite guidance into the producer group's production plans for August. Despite calls for higher production, analysts generally expect the coalition to raise production moderately by 500,000 b/d in August, especially as the resurgence in COVID-19 infections due to the delta variant of the coronavirus threatens demand, and as the threat of additional barrels from Iran following a possible Joint Comprehensive Plan of Action deal hangs over the market. "Russia apparently is leading a group of countries that want to [increase] output. Saudi Arabia is taking a more cautious approach, with Energy Minister, Prince Abdulaziz bin Salman, cautioning [that] it's not clear whether oil prices were rising due to real supply and demand or because of expectations and trajectories that are excessively optimistic," ANZ analysts said in a June 30 note.
Oil Jumps Ahead Of OPEC+ On Speculation Oil Supply Deal May Be Extended --Brent jumped back over $75 this morning - cementing a stellar first half for oil which saw oil prices rise by 50% for its best half since 2009 - pushed higher by a Reuters report that OPEC+ is expected to discuss the extension of the oil supply deal beyond April 2022 following earlier reports that some minsters are concerned about an oversupplied market in 2022. The jump reversed however following unconfirmed reports that ahead of tomorrow's OPEC+ meeting, Russia had expressed its favor for an increase in OPEC+ oil production starting form August, with an increase between 500k-1mln BPD suggested. As OPEC journalist Reza Zandi added, some members disagree with such suggestions out of the fear that COVID might surge again. The market continues to be dominated by what OPEC and its allies will do next with policy makers weighing pressure to increase supply and the medium-term demand effects from the pandemic. The difficulty in coming to a decision can be seen in the delay of preliminary talks until tomorrow morning to allow more time for compromise ahead of the ministerial meeting, also Thursday. Earlier in the session, WTI and Brent hit session lows of $72.82/bbl and $73.93 respectively, in a move that coincided with declines across equities, even as a base emerged thanks to reports that Iranian nuclear talks have been postponed to an unspecified date – suggesting a smaller likelihood of Iranian oil returning to the market in the initially expected time frame. Elsewhere, Tuesday's OPEC JTC did not provide a recommendation for ministers to consider. The JTC signaled uncertainty about the spread of COVID variants and the speed of vaccine rollouts. It also said that it is monitoring sovereign debt levels, inflation rates, and central bank actions. All*in-all, the technical committee reviewed a range of scenarios and aligned their base case with the June MOMR. Sources suggested Moscow and Riyadh have different views regarding the pace at which oil should be brought back to the market, with the latter favouring a more gradual approach. The Kuwaiti oil minister suggested the group is cautious about raising output amid challenges. The OPEC, JMMC, and OPEC+ meetings are all slated for Thursday at 12:00BST, 15:30BST and 17:00BEST respectively. The JMMC meeting was pushed back with some citing Russian Deputy PM Novak’s calendar, although sources suggested it is to allow for more time to negotiate a compromise (we have included a primer from Newsquawk at the bottom of this post).
WTI Pumps'n'Dumps After 6th Straight Weekly Crude Draw -Oil prices dumped and pumped overnight, testing below $73 and above $74, amid API inventory data, and OPEC+ headlines.“OPEC countries are cautious with regard to output-increase strategy amid oil market challenges,” Kuwait’s Oil Ministry said in a statement on Wednesday.“Any decision the organization will take will be in the interests of producers and consumers.”Bloomberg Intelligence Energy Analyst Fernando Valle notes that despite last week’s massive draws in crude-oil and gasoline inventories, crude prices have stayed relatively flat, signaling some skepticism with the breadth of the recovery. Inventories in China and the Middle East remain elevated, which may contribute to concerns for North American markets. Without a rebound in refined product exports, we believe that refiners are unlikely to increase output in the short term. API:
- Crude -8.153mm (-4.7mm exp)
- Cushing -1.318mm
- Gasoline +2.418mm (-700k exp)
- Distillates +428k (+100k exp)
DOE
- Crude -6.718mm (-4.7mm exp)
- Cushing -1.46mm
- Gasoline +1.522mm (-700k exp)
- Distillates -869k (+100k exp)
Analysts correctly predicted a 6th straight week of crude draws (but the official data was smaller than API) and gasoline stocks unexpectedly rose.,.. WTI hovered between $73 and $74 ahead of the print and barely budged after... Update: That didn't last long...
Oil rises on lower U.S. stockpiles, demand recovery - – Oil prices rose on Wednesday, heading for monthly and quarterly gains, after U.S. crude stockpiles fell for a sixth straight week and an OPEC report foresaw an undersupplied market this year. The Brent crude contract for August, which expired on Wednesday, ended the session up 37 cents, or 0.5% at $75.13 a barrel. The September contract rose 34 cents to settle at $74.62 a barrel. U.S. West Texas Intermediate crude (WTI) settled up 49 cents, or 0.7% at $73.47 a barrel. Both benchmarks are just below highs last reached in 2018, and are set to record their seventh monthly gain in the past eight months. WTI rose more than 10% in June while Brent rose over 8%. A Reuters poll showed that Brent was seen averaging $67.48 a barrel this year and WTI $64.54, both up from May’s poll. U.S. crude stockpiles fell last week for the sixth straight week as refiners ramped up output in response to rising demand, the Energy Information Administration said. [EIA/S] Inventories at Cushing, Oklahoma, the delivery point for WTI, slid to their lowest since March 2020, EIA data showed. “With continued decline of Cushing crude oil inventories and an upcoming OPEC+ meeting tomorrow, I expect crude oil prices will rise as the market has been crying out for more supplies,” The Organization of the Petroleum Exporting Countries and its allies, an alliance known as OPEC+, meet on Thursday. The group is expected to discuss extending its deal on cutting oil supply beyond April 2022. An internal OPEC report seen by Reuters said the oil market would be in deficit in the short term but a glut was on the horizon once the OPEC+ supply cuts ended. Hopes for a broad recovery received a boost from OPEC Secretary General Mohammad Barkindo, who said on Tuesday that demand is expected to rise by 6 million barrels per day (bpd) in 2021, with 5 million bpd of that coming in the second half of the year. (GRAPHIC: Global oil supply deficit in 2021 – https://fingfx.thomsonreuters.com/gfx/mkt/xegpbzydapq/Pasted%20image%201624878145906.png) Goldman Sachs forecasts that demand will rise by a further 2.2 million bpd by the end of 2021, leaving a 5 million bpd supply shortfall. “But the real fly in the ointment for the bull case is the UK.” Britain recorded a further 26,068 cases of COVID-19 on Wednesday, the highest daily figure since Jan. 29 and sending the seven-day tally up 70% from the week before, official data showed.
U.S. crude oil prices top $75 a barrel, the highest since 2018 - Oil prices broke above $75 a barrel on Thursday to a near three-year-high ahead of a decision from key producers on production policy for the second half of 2021. U.S. West Texas Intermediate crude for August settled up 2.4%, or $1.76, at $75.23 a barrel, hitting its highest level since October 2018. The international benchmark Brent crude for September climbed 2%, or $1.49, to $76.10 per barrel. The WTI has climbed more than 50% on the year after starting 2021 at around $48.5 per barrel. Demand has increased as people take to the roads amid the economic reopening, and a rebound in goods transportation and air travel also have supported prices. Gasoline prices are jumping on the back of a post-pandemic driving spree and $75 crude prices could mean even higher prices at the pump. The current average price for a gallon of unleaded gasoline is at $3.123 per gallon, compared to $2.179 per gallon a year ago, according to AAA. The advance came ahead of a meeting among OPEC and non-OPEC partners, an energy alliance often referred to as OPEC+, who have been positive about improved market conditions and the outlook for fuel demand growth following a sharp rebound in oil prices this year. OPEC+ meeting has been postponed to Friday. Jeff Currie, global head of commodities research at Goldman Sachs, said on CNBC's "Worldwide Exchange" that the expected OPEC production hike of 500,000 barrels per day might not be enough to keep prices down. "During the month of June, we estimate that the market was in a 2.3 million barrel per day deficit... The bottom line, demand is surging as we head into the summer travel season, and that is against a nearly inelastic supply curve," Currie said. Just over a year ago, WTI futures plunged into negative territory for the first time on record as the coronavirus pandemic took hold, shutting down economies worldwide. Bank of America recently said oil can climb all the way to $100 per barrel amid accelerating demand.
Oil Prices End Trading Day Above $75 - -- Oil advanced, closing above $75 a barrel for the first time since 2018, with an OPEC+ deal left in limbo after producers earlier signaled a tentative agreement to only gradually increase supplies through the end of the year. Futures in New York jumped 2.4% on Thursday, the biggest gain in more than a week. Talks among the OPEC+ alliance ended Thursday with no final agreement on production policy, with the United Arab Emirates raising a last-minute objection to the deal. However, the group earlier appeared to have an agreement in principle to boost output by 400,000 barrels a day each month from August to December. Ministers will reconvene on Friday. “These are cat-herding exercises to a certain extent with getting a couple dozen ministers to agree on pretty much a single number,” said Peter McNally, global head of industrials, materials and energy at Third Bridge. “These things always take time.” Oil posted the best half since 2009 as prices grind higher, aided by a global recovery taking place from the U.S. to Europe and China. Crude inventories in the U.S. are falling at the fastest rate in decades with shale producers and the OPEC+ alliance remaining disciplined. Citigroup Inc. expects the oil market to remain in a deep deficit even after accounting for higher OPEC+ output through the summer. The OPEC+ preliminary agreement was upended by the United Arab Emirates, which said it would only give its support if the baseline for its own cuts was raised considerably, delegates said, asking not to be named because the talks were private. The UAE’s cuts are measured from a starting point in 2018, which set the country’s maximum capacity at 3.168 million barrels a day. But expansion projects have since raised that number to about 4 million barrels a day. Reflecting that new capacity in its baseline could allow it to pump hundreds of thousands of barrels a day of extra crude while technically remaining in compliance with its obligation to cut. West Texas Intermediate for August delivery climbed $1.76 to settle at $75.23 a barrel. Brent for September settlement rose $1.22 to end the session at $75.84 a barrel. Brent’s prompt timespread is 88 cents a barrel in backwardation compared with 75 cents a week ago. Along the oil futures curve, the market structure strengthened and timespreads moved deeper into backwardation, a sign of supply tightness. West Texas Intermediate crude for September delivery closed at a $1.27 premium to its October contract, the strongest in about three years. The sharp gains at the front end of the futures curves for Brent and WTI are a sign that traders are banking on extreme market tightness in the coming weeks.
Oil Steady While Traders on Sidelines as OPEC+ Talks Drag On - Oil prices steadied on Friday as OPEC+ ministers resumed talks on raising oil output the day after the United Arab Emirates blocked a deal, which could delay plans to pump more oil through the end of the year. Brent crude futures rose 33 cents to settle at $76.17 a barrel, after rising 1.6% on Thursday, while U.S. West Texas Intermediate (WTI) crude futures fell 7 cents to settle at $75.16 a barrel, having jumped 2.4% on Thursday to close at their highest since October 2018. On Thursday, both benchmark contracts rose after OPEC+ sources said the group aimed to hike output by less than expected. OPEC+ are set to meet again on Monday after UAE opposed the proposals, which also included extending the pact on output to the end of 2022. The long rally in prices could be undermined if OPEC+ nations go their separate ways and add to supply as they see fit. WTI was on track for a 1.5% rise for the week, with the U.S. crude market expected to tighten as refinery runs pick up to meet recovering gasoline demand. Brent was largely steady on the week, as the market assessed fuel demand concerns in parts of Asia where cases of the highly contagious COVID-19 Delta variant are surging. Also, the rise in oil prices is contributing to global inflation, slowing the economic recovery from the coronavirus crisis. Citi analysts said they do not expect WTI to climb to a premium to Brent as they project U.S. oil output to pick up at the end of 2021 and grow further in 2022. Meanwhile, the number of U.S. oil rigs, an early indicator of future output, rose by four, to 376 in the week to July 2, its highest since April 2020, according to energy services firm Baker Hughes Co.
OPEC+ ends Friday's meeting without a deal, to seek agreement Monday on oil output policy — OPEC and non-OPEC ministers finished Friday's meeting without a resolution and they will meet again on Monday on oil output policy, CNBC's Brian Sullivan reported. The energy alliance, often referred to as OPEC+, met via videoconference on Friday afternoon to decide on whether to keep output policy unchanged or to ramp up supply further. OPEC+ except for the United Arab Emirates agreed to an easing of cuts and their extension to the end of next year, according to Reuters citing an OPEC+ source. The UAE said the extension is conditional to revising its baseline production, Reuters reported. Oil prices moved on the news, rising slightly Thursday before losing momentum Friday as traders digested the implications. International Brent crude futures traded at $76.03 a barrel, up 0.2% for the session, while U.S. West Texas Intermediate futures settled 7 cents lower at $75.16 a barrel Friday. The OPEC alliance had agreed in principle to increase supply by 400,000 barrels per day from August to December 2021 in order to meet rising demand, Reuters reported, citing unnamed OPEC+ sources. OPEC kingpin Saudi Arabia and non-OPEC leader Russia had also proposed extending the duration of cuts until the end of 2022, according to Reuters. However, Reuters reported that the UAE opposed these plans on the grounds that OPEC+ should change the baseline for cuts, effectively raising its production quota. Neil Atkinson, an independent oil analyst, told CNBC's "Squawk Box Europe" on Friday that tensions between the UAE and other OPEC+ members had been "bubbling under for quite some time now." "The Abu Dhabi National Oil Company has been investing in new capacity, it's been taking a more active role in trading," he said, adding that it has perhaps started operating more like an international oil company than a national oil company. Unlike international oil companies, decisions taken by national oil companies tend to be influenced by the state. "They look to the future, they see demand for oil continuing to grow in the medium term, they've installed more capacity and they want a greater share of that market as we move through the 2020s," he added. Analysts at risk consultancy Eurasia Group said they believe the oil producer group is still likely to reach a deal. "The UAE might be negotiating but it is unlikely to muster courage to risk it all till the very end. It will want to avoid sabotaging an OPEC+ agreement and potentially being blamed for a rise in oil prices that increases global inflation," the analysts said Friday, noting that the UAE's own relationship with Asian energy clients could suffer if prices continue to increase. "While a UAE withdrawal from OPEC+ should definitely not be dismissed, such a decision would be surprising. Such a move would compromise Abu Dhabi's relationship with Riyadh, its broad positioning in the region, and its ability to build alliances over the long-term. Therefore, compromise appears to be the most likely outcome." OPEC+, which is dominated by Middle East crude producers, agreed to implement massive crude productions cuts in 2020 in an effort to support oil prices when the coronavirus pandemic coincided with a historic fuel demand shock.
OPEC+ seeks agreement on oil output policy after initial talks end in disarray— OPEC and non-OPEC ministers finished Friday's meeting without a resolution and they will meet again on Monday on oil output policy, CNBC's Brian Sullivan reported. The energy alliance, often referred to as OPEC+, met via videoconference on Friday afternoon to decide on whether to keep output policy unchanged or to ramp up supply further. OPEC+ except for the United Arab Emirates agreed to an easing of cuts and their extension to the end of next year, according to Reuters citing an OPEC+ source. The UAE said the extension is conditional to revising its baseline production, Reuters reported. Oil prices moved on the news, rising slightly Thursday before losing momentum Friday as traders digested the implications. International Brent crude futures traded at $76.03 a barrel, up 0.2% for the session, while U.S. West Texas Intermediate futures settled 7 cents lower at $75.16 a barrel Friday. The OPEC alliance had agreed in principle to increase supply by 400,000 barrels per day from August to December 2021 in order to meet rising demand, Reuters reported, citing unnamed OPEC+ sources. OPEC kingpin Saudi Arabia and non-OPEC leader Russia had also proposed extending the duration of cuts until the end of 2022, according to Reuters. However, Reuters reported that the UAE opposed these plans on the grounds that OPEC+ should change the baseline for cuts, effectively raising its production quota.Neil Atkinson, an independent oil analyst, told CNBC's "Squawk Box Europe" on Friday that tensions between the UAE and other OPEC+ members had been "bubbling under for quite some time now." "The Abu Dhabi National Oil Company has been investing in new capacity, it's been taking a more active role in trading," he said, adding that it has perhaps started operating more like an international oil company than a national oil company. Unlike international oil companies, decisions taken by national oil companies tend to be influenced by the state. "They look to the future, they see demand for oil continuing to grow in the medium term, they've installed more capacity and they want a greater share of that market as we move through the 2020s," he added. Analysts at risk consultancy Eurasia Group said they believe the oil producer group is still likely to reach a deal. "The UAE might be negotiating but it is unlikely to muster courage to risk it all till the very end. It will want to avoid sabotaging an OPEC+ agreement and potentially being blamed for a rise in oil prices that increases global inflation," the analysts said Friday, noting that the UAE's own relationship with Asian energy clients could suffer if prices continue to increase. "While a UAE withdrawal from OPEC+ should definitely not be dismissed, such a decision would be surprising. Such a move would compromise Abu Dhabi's relationship with Riyadh, its broad positioning in the region, and its ability to build alliances over the long-term. Therefore, compromise appears to be the most likely outcome."
How Much Oil Can Saudi Arabia Really Produce? So to the actual oil crude oil production numbers: as highlighted above, the average amount of crude oil that Saudi Arabia was able to pump from 1973 to last month was 8.162 million bpd. That is it, there is no equivocation on that number, and no account is taken within that number of the unverifiable claims of any other ‘oil equivalents’ that Saudi likes to throw into any questioning of that number in order to further obfuscate the issue. If this – correct – number is used as the basis for discussion then all of Saudi Arabia’s subsequent activities make perfect sense. Most tellingly in this regard, the question often asked around the time of the firstSaudi-instigated oil price war from 2014-2016 that was aimed at destroying the then-nascent U.S. shale oil threat to Saudi was: ‘Why didn’t the Saudis pump more oil to crash prices more?’ After all, the Saudi strategy was for it and all other OPEC members to pump as much crude oil as possible to push oil prices as low as possible to cause as many bankruptcies as possible in the U.S. shale oil sector. The fact of the matter is that the Saudis did pump everything it could at that point. It pumped its usual 8.1 and a bit million bpd, plus it pumped to the maximum on all of its other fields, plus it used its oil in storage but despite all of that it was not able to produce more than around 10 million barrels per day of oil at any point for more than a few months or so (basically until its storage ran out and it had to rely on genuine production from the wellheads). Given that what was at stake in the 2014-2016 oil price war was the long-term future of Saudi Arabia as a significant power in the Middle East and the world, if it could have pumped one drop of oil more over that period then it would have. This leads to Saudi’s nonsensical claims about its spare capacity. These claims have been based on the foundation that its base crude oil production is around 10 million bpd rather than the 8.162 million bpd that is factually correct. It did indeed, as mentioned, produce just about 10 million bpd during its existentially important oil price war of 2014-2016 but that was going at absolutely full tilt and included storage volumes. The point here is that spare capacity is precisely that: basically, the extra amount that a country can produce in an emergency if and when required over and above the amount that can be produced with ease every day. The Energy Information Administration defines spare capacity specifically as production that can be brought online within 30 days and sustained for at least 90 days, whilst even Saudi Arabia has said that it would need at least 90 days to move rigs to drill new wells and raise production to the mythical 12 million bpd or 12.5 million bpd level. Abiding by this rule, Saudi Arabia’s genuine spare capacity up to at least the end of 2016 was at most about 2 million barrels per day using 8 million bpd as the base number, so equalling about 10 million bpd in total, which is precisely what it produced when it needed maximum production most (that is, during the 2014-2016 oil price war). The Saudis instead have been using the correct spare capacity of 2 million bpd but adding it to the false baseline production number of 10 million bpd for years, giving a number that it keeps mentioning of total capacity of 12-13 million bpd. Indeed, during its ill-fated 2020 oil price war the Saudi Ministry of Energy said it would increase its maximum sustained capacity to 13 million bpd. So fundamentally wrong is this Saudi number that it was forced to say so in the prospectus for its latest bond Saudi Aramco stated that it has not yet embarked on work to expand its maximum sustained capacity to this 13 million bpd level.
US troops come under fire in Syria after weekend airstrikes -- U.S. forces in Syria came under fire on Monday, a day after the Pentagon launched airstrikes on Iran-backed militia groups on the Iraq-Syria border. Col. Wayne Marotto, spokesman for Operation Inherent Resolve, confirmed the attack on Twitter, saying it occurred around 7:44 p.m. local time in Syria. No injuries were reported. Marotto later tweeted that U.S. forces responded by conducting "counter-battery artillery fire at rocket launching positions." .. The attack comes just one day after the U.S. carried out airstrikes on weapons storage facilities operated by the Iran-backed militia groups Kata'ib Hezbollah and Kata'ib Sayyid al-Shuhada. U.S. military officials believe that the storage facilities were being used for unmanned aerial vehicle attacks against American troops based in Iraq. "At President Biden's direction, U.S. military forces earlier this evening conducted defensive precision airstrikes against facilities used by Iran-backed militia groups in the Iraq-Syria border region,” the Pentagon said in a statement Sunday. “The strikes were both necessary to address the threat and appropriately limited in scope. As a matter of domestic law, the President took this action pursuant to his Article II authority to protect U.S. personnel in Iraq.
IDF Forces Deploy New Semi-Autonomous Robots To Gaza Border - An armed robot equipped with optical sensors and a 7.62mm machine gun has been spotted on the Gaza border by the Democratic Front for the Liberation of Palestine, a secular Palestinian Marxist–Leninist organization, according to The Times of Israel's Emanuel Fabian. Israel Defense Forces (IDF) appear to have deployed a new semi-autonomous robotic ground tank called the Jaguar that patrols the Gaza border and removes soldiers out of harm's way from sniper attacks by Hamas and Palestinian Islamic Jihad groups. The Jerusalem Post said Israel Aerospace Industries' Elta systems develop the unmanned ground vehicle in close collaboration with IDF's Ground Forces Command. The Jaguar military robot is on a six-wheeled chassis that is heavy-duty and highly maneuverable, equipped with a weapon station, communications and sensors. A turret is mounted on the front of the robot, firing a 7.62mm MAG machine gun that can be operated remotely.
‘Catastrophe’ warning as Lebanon's fuel crisis hits hospitals -Dr. Samer Saade’s car ran out of fuel this morning while he was on his way to work at Hammoud Hospital University Medical Center in Sidon, southern Lebanon. “I haven’t been able to fill my car for the past four days,” Saade told Arab News. The emergency room physician, like practically all Lebanese, has been hit hard by the ongoing fuel shortage in the crisis-hit country.Giant queues clogging roads near petrol stations have become a common sight and refueling is limited to 15 or 20 liters, making long-distance travel a thing of the past.The fuel crisis, however, is not only limited to the petrol needed for cars; it has also made its way to the country’s beleaguered electricity grid.Lebanon’s hospitals were already struggling to cope with the coronavirus disease (COVID-19) pandemic before the latest electricity crisis.Now, doctors say, they are being stretched even further with shortages of medical supplies and fuel.“Medicine shortages, equipment shortages, hyperinflation pricing out the poor from getting care — anything that can go wrong in this country will go wrong, basically,” Saade said.At the hospital, state electricity “barely comes on for two or three hours per day,” Saade said, with four private generators needed to fill the gap.Two of Lebanon’s Turkish power barges have been shut down amid an ongoing feud with the parent company, while the other four state-owned power plants are running on fumes.
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