Oil, Gas, And Fracking News Reads: 07June 2020 – Part 1

Written by rjs, MarketWatch 666

Here are some selected news articles from the week ended 06 June 2020. Part 2 is available here.

This is a feature at Global Economic Intersection every Monday evening.

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Distillates demand falls to 28 year low, distillates supplies rise to 37 year high

Oil prices rose for a sixth straight week to close at a 3 month high this week on improving US economic data and on hopes that OPEC would announce an extension of their production cuts at a meeting rescheduled for Saturday….after rising 6.7% to $35.49 a barrel last week on the apparent success of the OPEC+ production cuts, the contract price of US light sweet crude for July delivery opened lower on Monday as oil traders hedged bets in advance of the possible OPEC+ meeting this week to discuss whether to extend production cuts beyond June, but steadied to finish down just 5 cents at $35.44 a barrel as rising U.S.-China tensions weighed on sentiment even in the face of reports that OPEC and Russia were close to a deal on extending output cuts…oil opened higher and continued rising through Tuesday on reports that Saudi Arabia and Russia were close to inking a two-month extension of the current oil production cuts through September 1st and finished $1.37 higher at $36.81 a barrel as economic activity began to recover after the easing of coronavirus lockdowns…oil prices then erased most of Tuesday’s gains early on Wednesday on doubts that the OPEC meeting would go ahead as planned, but rallied late iin the session to finish 48 cents higher at $37.29 a barrel as prices were supported by a reported drawdown of U.S. crude inventories…oil prices were little changed on Thursday as investors awaited a decision from crude producers on whether to extend their record output cuts and settled 12 cents higher $37.41 a barrel…oil prices spiked higher early on Friday after an unexpected drop in the US jobless rate and then rallied to a $2.14 increase at $39.55 a barrel on Opec’s decision to bring forward to Saturday their discussion of extended output cuts, thus finishing the week more than 11% higher, with both US and international prices finishing at their highest level since March 6th…

Meanwhile, natural gas prices finished the week lower as traders watched the daily changes in natural gas output and US LNG exports for supply & demand clues… after slipping 3.2 cents or 1.7% to $1.849 per mmBTU last week on falling demand for LNG, the contract price of natural gas for July delivery opened lower on Monday despite forecasts for warmer weather and higher air conditioning demand and tumbled to a 4% loss at $1.774 per MMBTU, as US LNG exports continued to drop in the face of record low gas prices in Europe and Asia…natural gas traded in a narrow range on Tuesday and finished three-tenths of a cent higher, and then rose 4.4 cents to $1.821 per mmBTU on Wednesday on improving supply and demand balances, as traders watched a tropical storm that could disrupt Gulf Coast production and as LNG exports edged up with higher gas prices in Europe…natural gas ended little changed at $1.822 per mmBTU on Thursday as rising LNG exports offset a smaller-than-expected weekly storage build and an increase in natural gas output, but then fell back 4 cents to end the week 3.6% lower at $1.782 per mmBTU on forecasts for milder weather and lower air conditioning demand through mid-June.…

The natural gas storage report from the EIA for the week ending May 29th indicated that the quantity of natural gas held in underground storage in the US rose by 102 billion cubic feet to 2,714 billion cubic feet by the end of the week, which left our gas supplies 762 billion cubic feet, or 39.0% higher than the 1,952 billion cubic feet that were in storage on May 29th of last year, and 422 billion cubic feet, or 18.4% above the five-year average of 2,292 billion cubic feet of natural gas that has been in storage as of the 29th of May in recent years….the 102 billion cubic feet that were added to US natural gas storage this week was less than the consensus forecast for a 111 billion cubic feet increase from a survey of analysts by S&P Global Platts, while it was close to the average 103 billion cubic feet of natural gas that have been added to natural gas storage during the same week over the past 5 years and was somewhat below the 118 billion cubic feet addition of natural gas to storage during the corresponding week of 2019…

The Latest US Oil Supply and Disposition Data from the EIA

US oil data from the US Energy Information Administration for the week ending May 29th showed that due to a drop our oil imports, a decrease in crude production, an increase in refining, and a big addition to the SPR, we had to withdraw oil from our stored commercial supplies of crude oil for the third time in four weeks, and for the 11th time in the past thirty-eight weeks….our imports of crude oil fell by an average of 1,021,000 barrels per day to an average of 6,179,000 barrels per day, after risng by an average of 2,003,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 382,000 barrels per day to an average of 2,794,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 3,385,000 barrels of per day during the week ending May 29th, 639,000 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 fell by 200,000 barrels per day to 11,200,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production totaled an average of 14,585,000 barrels per day during this reporting week..

US oil refineries reported they were processing 13,307,000 barrels of crude per day during the week ending May 29th, 316,000 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 278,000 barrels of oil per day were being added to the supplies of oil stored in the US….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 and from oilfield production was 1,001,000 barrels per day more than what was added to storage plus 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 (-1,001,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the average daily supply of oil and the average daily consumption of it balance out, essentially a fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting an error or errors of that magnitude in the oil supply & demand figures we have just transcribed…however, since the media usually treats these weekly EIA figures as gospel and since these numbers often drive oil pricing and hence decisions to drill for oil, we’ll continue to report them, just as they’re watched & believed as 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 5,992,000 barrels per day last week, which was still 18.3% less than the 7,336,000 barrel per day average that we were importing over the same four-week period last year….the 278,000 barrel per day net addition to our total crude inventories included a record 574,000 barrels per day that were added to our Strategic Petroleum Reserve, which was partly offset by a 297,000 barrels per day withdrawal from our commercially available stocks of crude oil ….this week’s crude oil production was reported to be down by 200,000 barrels per day to 11,200,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was down by 200,000 barrels per day to 10,800,000 barrels per day, while a 32,000 barrel per day decrease in Alaska’s oil production to 380,000 barrels per day was not enough to have an impact on the rounded national total….last year’s US crude oil production for the week ending May 31st was rounded to 12,400,000 barrels per day, so this reporting week’s rounded oil production figure was about 9.7% below that of a year ago, yet still 32.9% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016…

Meanwhile, US oil refineries were operating at 71.8% of their capacity while using 13,307,000 barrels of crude per day during the week ending May 29th, up from 71.3% of capacity during the prior week, but still among the lowest refinery utilization rates of the last thirty years…hence, the 13,307,000 barrels per day of oil that were refined this week were 21.4% fewer barrels than the 16,938,000 barrels of crude that were being processed daily during the week ending May 31st, 2019, when US refineries were operating at 91.8% of capacity….

With the increase in the amount of oil being refined, gasoline output from our refineries was quite a bit higher, increasing by 608,000 barrels per day to 7,779,000 barrels per day during the week ending May 29th, after our refineries’ gasoline output had increased by 5,000 barrels per day over the prior week… however, since our gasoline production is still recovering from a multi-year low, this week’s gasoline output was still 22.6% lower than the 10,049,000 barrels of gasoline that were being produced daily over the same week of last year….meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 66,000 barrels per day to 4,714,000 barrels per day, after our distillates output had decreased by 24,000 barrels per day over the prior week…after this week’s decrease in distillates output, our distillates’ production was 12.8% less than the 5,404,000 barrels of distillates per day that were being produced during the week ending May 31st, 2019….

With the big increase in our gasoline production, our supply of gasoline in storage at the end of the week increased for the 2nd time in 6 weeks and for the 6th time in 18 weeks, rising by 2,795,000 barrels to 257,795,000 barrels during the week ending May 29th, after our gasoline supplies had decreased by 724,000 barrels over the prior week…our gasoline supplies also increased this week because our imports of gasoline rose by 490,000 barrels per day to 782,000 barrels per day, while our exports of gasoline rose by 53,000 barrels per day to 263,000 barrels per day, while the amount of gasoline supplied to US markets increased by 296,000 barrels per day to 7,549,000 barrels per day ….with this week’s inventory increase, our gasoline supplies were 10.1% higher than last May 31st’s gasoline inventories of 234,149,000 barrels, and roughly 10% above the five year average of our gasoline supplies for this time of the year…

Even with the decrease in our distillates production, our supplies of distillate fuels increased for the ninth time in 20 weeks and for the 14th time in 35 weeks, rising by 9,934,000 barrels to a 37 year high of 174,261,000 barrels during the week ending May 29th, after our distillates supplies had increased by 5,495,000 barrels over the prior week….our distillates supplies rose by more this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, fell by 548,000 barrels per day to a 28 year low of 2,718,000 barrels per day, and because our exports of distillates fell by 135,000 barrels per day to 740,000 barrels per day, while our imports of distillates rose by 8,000 barrels per day to 163,000 barrels per day….after this week’s inventory increase, our distillate supplies at the end of the week were 34.7% above the 129,372,000 barrels of distillates that we had stored on May 31st, 2019, and about 28% above the five year average of distillates stocks for this time of the year…

Finally, with the big drop our oil imports, the big addition to the SPR, the increase in refining, and the drop in production, our commercial supplies of crude oil in storage fell for the 3rd time in nineteen weeks and for the twentieth time in the past 52 weeks, decreasing by 2,077,000 barrels, from a 38 month high of 534,422,000 barrels on May 22nd to 532,345,000 barrels on May 29th….but with near steady increases this year and three record increases over past 9 weeks, our commercial crude oil inventories are still 12% above the five-year average of crude oil supplies for this time of year, and nearly 50% above the prior 5 year (2010 – 2014) average of crude oil stocks for the end of May, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first rose above 400 million barrels and continued rising….since our crude oil inventories have generally been rising over the past year and a half, except for during this past summer, after generally falling until then through most of the prior year and a half, our crude oil supplies as of May 29th were 10.2% above the 483,264,000 barrels of oil we had in commercial storage on May 31st of 2019, 21.9% above the 436,584,000 barrels of oil that we had in storage on June 1st of 2018, and 3.7% above the 513,207,000 barrels of oil we had in commercial storage on June 2nd of 2017…

Furthermore, if we check the total of our commercial oil supplies and the stockpiles of all the refined product made from oil, we find those supplies have just increased by 15,144,000 barrels to a record high of 1,429,929,000 barrels, 9.7% more than the 1,303,043,000 barrel total of the same week a year ago…

This Week’s Rig Count

The US rig count fell for the 13th week in a row during the week ending June 5th, and is now down by 64.2% over that thirteen week period….Baker Hughes reported that the total count of rotary rigs running in the US decreased by 17 rigs to 284 rigs this past week, which was the fewest rigs deployed in Baker Hughes records going back to 1940 and 120 fewer rigs than the prior all time low, also down by 691 rigs from the 975 rigs that were in use as of the June 7th report of 2019, and 1,645 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 their first attempt to put US shale out of business….

The number of rigs drilling for oil decreased by 16 rigs to 208 oil rigs this week, after falling by 15 oil rigs the prior week, leaving oil rig activity at its lowest since June 19, 2009, which was also 583 fewer oil rigs than were running a year ago, and less than a seventh of the recent high of 1609 rigs that were drilling for oil on October 10th, 2014….at the same time, the number of drilling rigs targeting natural gas bearing formations was down by 1 to 76 natural gas rigs, which was the least natural gas rigs running in at least 80 years, down by 110 natural gas rigs from the 186 natural gas rigs that were drilling a year ago, and less than a twentieth of modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008…in addition to those rigs drilling for oil & gas, two rigs classified as ‘miscellaneous’ continued to drill this week; one on the big island of Hawaii, and one in Lake County, California… a year ago, there were no such “miscellaneous” rigs deployed..

The Gulf of Mexico rig count was up by one to 13 rigs this week, with all of those Gulf rigs drilling for oil in Louisiana’s offshore waters…that’s still ten fewer rigs than the rig count in the Gulf a year ago, when 21 rigs were drilling offshore from Louisiana and two rigs were operating in Texas waters…there are no rigs operating off other US shores at this time, nor were there a year ago, so the Gulf of Mexico rig count is equal to the national rig count, just as it has been since the onset of this past winter…

The count of active horizontal drilling rigs decreased by 18 rigs to 253 horizontal rigs this week, which was the fewest horizontal rigs active since April 21st, 2006, and hence is a new 14 year low for horizontal drilling…it was also 602 fewer horizontal rigs than the 855 horizontal rigs that were in use in the US on June 7th of last year, and less than a fifth of the record of 1372 horizontal rigs that were deployed on November 21st of 2014…meanwhile, the vertical rig count was unchanged at 7 vertical rigs this week, but those were down by 39 from the 46 vertical rigs that were operating during the same week of last year…on the other hand, the directional rig count increased by 1 to 24 directional rigs this week, but those were still down by 50 from the 74 directional rigs that were in use on June 7th of 2019….

The details on this week’s changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes…the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of June 5th, the second column shows the change in the number of working rigs between last week’s count (May 29th) and this week’s (June 5th) count, the third column shows last week’s May 29th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running before the same weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 7th of June, 2019…

The basin totals above show a net decrease of 18 rigs, matching the number of horizontal rigs removed nationally this week, so hopefully the above table accounts for all the changes in activity this week has brought us….checking the rig losses in the Texas part of Permian basin, we find that 4 rigs were pulled out of Texas Oil District 8, or the core Permian Delaware, while the rig count in other Texas Permian basin districts remained unchanged…since the overall Permian rig total was down by 7 rigs, that means that the 3 rigs that were shut down in New Mexico must have been drilling in the western Permian Delaware, to account for the national Permian basin reduction of 7 rigs….elsewhere in Texas, 5 rigs were pulled out of Texas Oil District 1, and 5 rigs were pulled out of Texas Oil District 2, while a rig was added in Texas Oil District 3, and another rig was added in Texas Oil District 4…together, the changes in those districts account for the 9 rig reduction in Eagle Ford shale, which stretches in a relatively narrow band through the southeastern part of the state and thus touches on those 4 Oil Districts, and also account for the additon of a rig in that region that doesn’t target the Eagle Ford, possibly the directional drilling rig that was added this week…in other states, Oklahoma saw a one rig reduction despite the rig added in the Cana Woodford because rigs were concurrently pulled out of the Ardmore Woodford and the Granite Wash, which borders on the Texas panhandle, while Louisiana saw a one rig reduction despite the addition of the rig in the Gulf of Mexico because rigs were concurrently pulled out of the Haynesville shale in the northwest and from a non-shale basin in the southern part of the state…that Haynesville shale rig, and the rig removed from the Granite Wash basin, were the only natural gas rig reductions this week, while a rig taretting natural gas started drilling in one of those “other” basins not tracked separately by Baker Hughes at the same time…

Youngstown ‘fracking’ opponents to file appeal in federal court – Organizers behind an effort to let cities like Youngstown and other voters in Ohio ban fracking in their communities are taking their fight to a federal appeals court. A coalition of activists from Youngstown and other parts of Ohio has filed a notice in the U.S. Sixth Court of Appeals challenging a federal judge’s ruling against their claim that state and local elections boards violated their constitutional rights by preventing voters from deciding environmental issues such as fracking.In April, U.S. District Court Judge Benita Pearson dismissed the lawsuit filed by grassroots environmental groups in seven Ohio counties, including Susie Beiersdorfer and Dario Hunter of Frackfree Mahoning Valley, which has been unsuccessful eight times in backing a ballot issue to ban fracking inside Youngstown city limits. Fracking Opponents have expressed concern that fracking could endanger water supplies and pose other environmental hazards.The lawsuit claimed that election boards and the Ohio Secretary of State had violated the groups’ constitutional right to free speech and due process by rejecting petitions signed by hundreds and thousands of registered voters seeking ballot space on issues dealing with clean water, fracking, injection wells, and other environmental concerns.The groups say election officials and the Secretary of State should not be allowed to keep questions from the voters based on the content of the issues. Judge Pearson ruled that the plaintiffs failed to show that “local, community self-government” is a constitutional guarantee in this case.

Gulfport updates Utica Shale plans – Gulfport Energy plans to complete three additional Utica Shale wells during the second half of the year The wells would give Gulfport incremental production in the coming months, the Oklahoma City-based driller said in a press release. Gulfport has deferred production until later this year and into early 2021 in the hope that prices for natural gas and oil will rise by then. The company predicted that net production for 2020 would land between 1 billion and 1.075 billion cubic feet equivalent per day. Gulfport’s prior estimate put production in the range of 1.1 billion to 1.15 billion cubic feet equivalent per day. Gulfport has drilled more than 400 wells in Ohio’s Utica Shale, the most of any publicly traded company.

PTTGC, Daelim postpone investment decision on Ohio project — PTTGC America and Daelim Chemical USA, equal partners in their long-planned PTTDLM petrochemical project in Mead Township, Belmont County, Ohio, have delayed making a final investment decision (FID) on their multi-billion-dollar petrochemical project, originally expected in the middle of 2020. Senior company sources in Bangkok told CW on Monday that the FID is expected to be made either at the end of this year or, more likely, next year and it would take five to six years to complete construction of the facilities. This would take the project’s completion date to around 2027 – 28. PTT Global Chemical (PTTGC), parent of PTTGC America, first announced plans for the project in 2015. In 2018, Daelim Industrial joined as partner. The companies were hoping to make an FID on the project by the middle of this year. The company tells CW that engineering studies are still being carried out on the project, which would be based on an ethane cracker designed to produce 1.5 million metric tons/year (MMt/y) of ethylene using ethane from the Marcellus and Utica shale deposits. The downstream configuration has not yet been fully decided on but could involve the entire ethylene output being used to make the equivalent amount of high-density and linear low-density polyethylene and/or some of the ethylene also used to make ethylene glycol. Most of the output would be sold on the US market. The company tells CW that the coronavirus disease 2019 (COVID-19) pandemic as well as the latest forecasts in demand are the main reasons for the delay. PTTGC CEO Kongkrapan Intarajang said recently that the company will review its short- and long-term investment plans worldwide based on projects’ costs as well as changes in product demand expected in the post-COVID-19 global economy. President and CEO of PTTGC America, Toasaporn Boonyapipat, said on Monday, “While the pandemic has prevented us from moving as quickly as we would like within our previous timeline, our best estimate is for a final investment decision by end of this year or in the first quarter of next year.” PTTGC has spent about $200 million on site preparation and engineering studies so far. Bechtel was last year selected as the engineering, procurement, and construction contractor on the project, of which the initial costs were estimated at $5 – 6 billion. The complex would be located on a 500-acre site of a former coal-fired power plant. The site is owned by the potential investors. It would also include on-site railcar and truck loading facilities, supporting utilities, infrastructure, storage tanks, and logistics facilities.

Shell Plastics Plant Trump Touted Faces Oversupply Risks: Energy Institute Report – The New York Times – A massive Pennsylvania plastics project that President Donald Trump touted during a visit last year faces risks of oversupply and a low price outlook for the materials, a report by an institute that examines energy issues said on Thursday. The Pennsylvania Petrochemical Complex plant in Beaver County, owned by Shell, has been promoted by some as an economic savior in a region still suffering from the demise of steel industry in the 1980s. But the $6 billion to $10 billion plant, expected to open in 2021 or 2022, faces competition from other major plants owned by companies like Exxon Mobil, expected growth in recycled plastics, and the sluggish global economy, according to the report by the Institute for Energy Economics and Financial Analysis, which supports the transition to green energy. “A lot of people think it’s the second coming of the steel industry … but this is way too weak of a proposition and a questionable economic development choice,” Tom Sanzillo, IEEFA director of finance and former first deputy comptroller of New York state, said. Sanzillo hopes local officials and investors will ask questions about the plant. Shell spokesman Curtis Smith said the short-term outlook for the chemicals business is challenging, but long-term demand for petrochemical products will grow. The project is advantaged given its proximity to abundant, inexpensive feedstock, Smith said, referring to the region’s natural gas and ethane. Trump won Pennsylvania in the 2016 election by less than 1 percentage point and has visited the state often ahead of the November vote. “This is just the beginning,” Trump told thousands of building workers wearing yellow vests at the plant last August. “My administration is clearing the way for other massive, multibillion-dollar investments.” He said the project would have never happened without him, although its final permits were issued before he was elected. The White House did not immediately respond to a request for comment.

Shell’s Plastics Plant Outside Pittsburgh Has Suddenly Become a Riskier Bet, a Study Concludes – The same economic forces that are delaying construction of a plastics plant in Ohio will make another one under construction in western Pennsylvania less profitable and riskier to shareholders, an economic think tank warns in a new report.The massive, multibillion-dollar Shell Polymers plant rising from the banks of the Ohio River in Beaver County, Pennsylvania, is expected to make 1.6 million metric tons of plastic pellets annually – the building blocks for such products as bags, bottles, food packaging and toys. But a new study from the Institute for Energy Economics and Financial Analysis warns that Shell will be making less plastic and less money while facing increasingly stiff competition. That means the company won’t likely be able to hire as many workers and will contribute less to the local economy, IEEFA concludes. One key factor: the price of plastics has fallen 40 percent since the plant was planned several years ago, as a global petrochemical industry has raced to boost production capacity. These changing economics, made worse by fallout from the coronavirus pandemic, will have significant implications for Shell’s investors, local and state governments in Pennsylvania, and the people of Pennsylvania, who have supported the project through tax breaks. IEEFA, a non-profit whose work is aimed at supporting a sustainable energy economy, called on Shell to be transparent with its investors and the public as economic conditions have changed.”It will be a distressed asset for years to come,” said Tom Sanzillo, director of finance for the energy institute. “Only increased public disclosure by Shell can ensure that problems are faced squarely and with common sense.”A Shell spokesman, Curtis Smith, acknowledged “the short-term outlook for this business is challenging given global macro conditions, but it remains our view that long-term demand for the wide variety of products derived from petrochemicals will continue to grow and provide attractive returns.”

Report: Fossil fuel industry could see prolonged financial distress – The Institute for Energy Economics and Financial Analysis (IEEFA), an organization largely funded by various anti-fossil fuel agencies, on Thursday released a study that said the risks for Shell’s petrochemical complex indicates less profitability than originally projected, noting that Shell could see prolonged financial distress.The petrochemical industry in Beaver County could face prolonged financial distress, according to a report by an advocate organization for sustainable energy.The Institute for Energy Economics and Financial Analysis (IEEFA), an organization largely funded by various anti-fossil fuel agencies, on Thursday released a study that said the risks for Shell’s petrochemical complex indicates less profitability than originally projected, noting that Shell could see prolonged financial distress.”The current economic climate poses risks for this investment … This complex will not be as profitable as originally presented. This has significant implications for jobs, taxes and economic spinoffs,” said Tom Sanzillo, IEEFA’s director of finance, in a release. Kathy Hipple, a financial analyst and co-author of IEEFA’s recent report, said the profitability of the complex is due to “a cumulative set of missed revenue and profit targets, as well as an oversupply of plastics, unpredictable costs, lost market share, diminished growth and increased competition.” According to the report, the price of plastics was in the $1 per pound range between 2012 to 2016, while today, plastics are 40 to 60 cents per pound range. Last month, Royal Dutch Shell announced it was selling its Appalachian shale gas holdings in northwestern Pennsylvania for $541 million following steep first-quarter profit hits company leaders attributed to coronavirus shutdowns. But Shell has been slowly shedding its shale assets in the Appalachian Basin for years alongside Chevron Corp., which announced late last year it was looking to sell Marcellus and Utica shale holdings in the region.

Oil, gas and plastics hit by COVID-19; producers await rebound – Ellwood City Ledger – As oil and gas producers wrestle with economic uncertainty and price slumps related to COVID-19, industry supporters expect a swift rebound. Business shutdowns and stay-at-home orders in place to combat the pandemic delayed progress on two Appalachian petrochemical facilities, and a global drop in demand has reduced fracking and drilling activities here and across the United States. The country’s oil prices fell below zero for the first time in history just last month, although prices are climbing again as COVID-19 precautions lift. Shale production in the Appalachian Basin has slowed by less than 2 percent in recent months, but new figures indicate a sharper drop in the average production of new wells. U.S. Energy Information Administration analysts say nationwide natural gas prices will likely remain below average until business activities resume and production slows at the end of the year. Kallanish Energy this week reported a 6.8 percent increase in Pennsylvania’s quarterly natural gas production – the lowest statewide growth rate since 2017. Even pre-pandemic, an abundance of cheap gas produced in the Permian Basin and other shale reserves was flooding the natural gas market and driving prices down. Global energy prices had declined, and Pennsylvania utilities were paying less for natural gas. EQT Corp. and Range Resources, the region’s two largest gas drilling companies, announced plans to lower capital spending by $75 million and $90 million this year, respectively; however, both companies still expect to meet annual production goals. “The outlook for natural gas prices later this year and into 2021 has drastically improved since our year-end call in mid-February,” said Cabot Oil and Gas Corp. CEO Dan Dinges on a recent earnings call, echoing similar statements made by other regional producers. EQT plans to temporarily halt production of nearly one-third of its daily natural gas output in Pennsylvania and Ohio until market conditions improve later this year.

Pa. Supreme Court denies Sunoco pump station appeal – The Pennsylvania Supreme Court has dealt another blow to the Mariner East Pipeline through Lebanon County. The state’s top judicial body on Monday, June 1 denied the company’s petition to appeal a lower court’s decision, putting the future of the Sunoco Pipeline’s pump station in West Cornwall Township in jeopardy. The court upheld an October 2019 ruling by the Commonwealth Court, which said the West Cornwall Township Zoning Hearing Board acted improperly in May 2015 when it issued a permit for construction of a pumping station along Route 322 near Butler Road. The station, according to previous reports, is needed to provide the pressure necessary to maintain the volatile gases in a liquid state while being transported. However, construction was completed in September 2014 and gases began flowing through the station in January 2015, several months before the permit was issued. The Concerned Citizens of Lebanon County (CCLC) brought suit against pipeline owner Energy Transfer Partners, the parent company of Sunoco, in a case that bounced between the township and Court of Common Pleas for several years until a fresh appeal landed it before Commonwealth Court, which decided in CCLC’s favor. Sunoco in January filed a petition with the state Supreme Court to allow them to appeal the Commonwealth Court’s decision. “We are very pleased, after five years of litigation, to finally be vindicated,” CCLC member Pam Bishop said Tuesday. “The permit that was issued has been voided,” she said. “If it was anybody else, and the township found a building that did not have its permit … the township would ask them to take it down. That would be the normal procedure. We’re not sure what the township will do.”

Tensions With China Are Wounding West Virginia – The One State The President Wanted To Save – The political season will enter guns a blazing after Labor Day. But the players are warming up now – something triggered by some states and their attorneys general who are asking that the Chinese government be held to account for the outbreak of COVID-19. It’s a ploy that has an uncommon twist. One of the politicos calling for such action is West Virginia Attorney General Patrick Morrisey, who is struggling to get his footing after getting knocked out of the U.S. Senate race by Joe Manchin in 2016. The reason Morrisey’s signature stands out is that West Virginia is in deep in negotiations with the China Energy Investment Corp. – a deal that would have it invest $84 billion to develop the state’s shale gas fields; China wants to feed its chemical and manufacturing base. The prospective deal would be a game-changer for West Virginia. The three-year investment from China would exceed the state’s annual $75 billion gross economic output. Moreover, China is one of the few countries in the world still buying coal and China paid American coal producers at least $128 million last year. U.S. utilities, meanwhile, are closing their coal-fired units and replacing them with natural gas and renewables. West Virginia sits atop the Marcellus Shale basin, which holds 141 trillion cubic feet of recoverable natural gas. The Utica Shale basin, which is next door, is just as plush. That means China could invest its $84 billion in Pennsylvania or Ohio – states that may value their business and that do not engage in inflammatory political rhetoric. The worst offender is Donald Trump, who said last week at the White House, “They’ve ripped off the United States like no one has ever done before.” If China Energy does invest in West Virginia, it could trigger an economic boon there: It would attract cracker plants that break apart the “dry gas” used to heat homes from the “wet gas” used in chemical manufacturing. It could also be used as a magnet to attract an ethane storage and distribution hub to harness petrochemicals. Economic developers note that such an investment is worth 100,000 new jobs – chump change, though, for career politicians.

Ballad of a Land Man: Kentucky theatre takes on fracking –On a temporary stage deep in the Appalachian woods of Rockcastle County, Kentucky, the outdoor play Ezell: Ballad of a Land Man was a different kind of production. The five acts – called Welcome, Journey, Performance, Return and Feast – generated an immersive storytelling experience, through which the audience was invited to feel a connection to place and to consider the intricacies of stewardship and belonging. For creator Bob Martin and producer Carrie Brunk, Ezell is an outgrowth of both a passion for locally-engaged theater and their community’s efforts to resist the expansion of fossil fuel extraction. The two, known collectively as Clear Creek Creative, have deep roots in Kentucky and intimately aware of the painful history of resource extraction in Appalachia. A speculator for oil and gas companies knocked on Martin’s and Brunk’s door in 2014, offering a lease for the mineral rights on the land they call home. At the time, oil and gas companies were aggressively positioning themselves for fracking the Rogersville Shale that lies under a great swath of eastern Kentucky. We first meet Ezell as he bounds on to the makeshift stage. His enthusiasm for life is infectious. His character is neither a hero nor a villain. He’s human. Complicated. Real. We see his scars from a hard life of working in coal mines and the military. He returns to his ancestral land, perhaps the last place he felt whole, in an attempt to repair the rifts in his arduous life. The one-man play powerfully wrestles with the personal, financial, generational, and societal barriers Ezell faces to truly going home. As the character says in the play: “Well cousin, to sit on MY porch of MY cabin, I’m gonna have to give up farmin’ these hillside flats and drinkin’ from that spring and trade them for these frackpads and these deep wells. That’s right… And they’re gonna need water, and a lot of it, over 2 million gallons per well. So they’ll tap that spring and they shoot that water down two miles deep and 2 miles across in every direction to break open that shale and bring up that gas. AND, I’ll sit on MY porch, and look out over that holler with these FRACKPADS and all these generators lined up pumping out 24 HOURS A DAY, 7 DAYS A WEEK!” But it’s more complex than that: Ezell also shares tender observations about what has been and will be lost. The majestic chestnut trees that proliferated in the forest. The cold, clear spring with 57 degree water. The family graveyard going back generations. The traditions of the Cherokee people who once lived in the hills and valleys.

NJ Investigates Whether It Has Enough Natural Gas Capacity for the Next Decade – The state is launching an investigation into whether New Jersey has enough natural gas capacity to serve its customers over the next decade, a probe that could alter whether an expansion of new pipelines continues. The proceeding, sought by both gas utilities and conservation groups opposed to the buildout in recent years, aims to answer whether there is enough capacity in the pipeline system and what ”nonpipeline” solutions can reduce stress on the system during times of peak demand. The bigger-picture issue for critics of the pipeline expansion is how to rein in policies to ensure six million people in New Jersey rely on gas to heat their homes, and align them more with the Murphy administration’s clean-energy agenda and goals to reduce emissions contributing to climate change. “Now, more the ever, we should be vigilant about not wasting precious resources on unneeded projects,” said Tom Gilbert, campaign director for energy, climate and natural resources for the New Jersey Conservation Foundation. “Gas experts have shown that New Jersey has a surplus of available natural gas today and at any point in the foreseeable future.”

NJ tells high court not to bite on ‘overstated’ impacts in pitch from PennEast – The State of New Jersey has told the US Supreme Court that PennEast Pipeline exaggerated the industrywide harms likely to result from a federal appeals court decision blocking condemnation of property in which the state holds an interest. The June 2 brief from the state comes as PennEast has asked the national’s high court to overturn a 3rd US Circuit Court of Appeals decision it contends would enable states to block interstate gas pipelines, threatening the nation’s energy markets and likely chilling investments in infrastructure across the country. Oil and gas trade groups and the Federal Energy Regulatory Commission have also warned of far-reaching consequences of the September 2019 3rd Circuit ruling. That decision found state sovereign immunity blocked PennEast from pulling New Jersey into federal court to condemn more than 40 properties in which the state held an interest. The ruling threw into question the route for the 116-mile, 1.1 Bcf/d natural gas project linking Marcellus Shale dry gas production to markets in Pennsylvania, New Jersey, and New York. New Jersey in its brief filed June 2 argued the Supreme Court should not take up the case because there was no circuit court split to resolve and the 3rd Circuit ruling was unanimously decided, reflecting proper application of sovereign immunity and statutory interpretation rules. As such, it said the petition for Supreme Court review rested heavily on overstated warnings of dire consequences. “PennEast is wrong” in asserting the 3rd Circuit created a state veto of interstate natural gas pipelines that will prevent development across the country, New Jersey argued. The decision only identifies which parties can file appropriate condemnation suits, it said. “That is why this question has arisen so infrequently, and why it is not likely to arise frequently in the future,” New Jersey said. “The sky has not fallen,” since a district court upheld Texas’ analogous assertions of sovereign immunity in a condemnation action involving Sabine Pipe Line in 2017, New Jersey argued in the brief. Rather, FERC has received 53 applications for major new natural gas projects and approved 34 with 19 pending and no denials. And, parties have only identified two cases, including PennEast, since the Texas ruling in which states asserted immunity, it said.

Court ruling could delay compressor project – While it could delay the project from coming online and cost the gas company money, a federal appeals court decision to throw out an air permit issued by state regulators will not stop ongoing construction of a natural gas compressor station on the banks of the Fore River, Mayor Robert Hedlund said. The U.S. Court of Appeals for the First Circuit on Wednesday overturned the air permit for the natural gas compressor station Enbridge is building in North Weymouth, ordering the state Department of Environmental Protection to conduct a new analysis of what would be the best available control technology to limit air pollution. In his decision, Judge William Kayatta said the state did not follow its own procedures when it approved a gas turbine, rather than an electric motor, to cut emissions at the station. The state will need to hold proceedings regarding the control technology for the project. Kayatta disagreed with many of the other arguments that petitioners made in their attempts to get the permit tossed, such as the regulators’ failure to consider existing levels of air toxins such as benzene and formaldehyde that already exist in the Fore River Basin. Hedlund praised Town Solicitor Joe Callanan and outside lawyers for their work on the town’s appeal, which raised the issue of using a gas-fired turbine to power the compressor. Hedlund said the state Department of Environmental Protection could either conduct the analysis and still allow the gas turbine, or require Enbridge to modify its plans and use an electric motor. “We have to remain vigilant to protect the health and safety of our residents because this does not stop construction of this facility,” Hedlund said. “It has the potential to delay Enbridge a couple of months, so we remain vigilant to look at all issues to protect the health and safety of residents.” The compressor station is part of the Atlantic Bridge project, which would expand the Houston company’s pipelines from New Jersey into Canada. Enbridge got the final go-ahead from the Federal Energy Regulatory Commission in November and started cleanup of contamination at the site shortly after. The company also needed several state permits, all of which were granted by regulators despite vehement and organized opposition from local officials and residents for several years.

State’s top court wrestles with land seizure for National Fuel pipeline plan – New York State’s highest court heard arguments Tuesday on whether an Allegany County widow must surrender land to National Fuel for construction of a natural gas pipeline. The pipeline would move natural gas from Pennsylvania to Canada through Western New York. The Court of Appeals case may turn on which of two bureaucratic findings the court thinks controls the outcome. The Federal Energy Regulatory Commission granted National Fuel a permit for the Northern Access pipeline. But the state Department of Environmental Conservation refused to grant the company a water quality certificate allowing the pipeline to cross streams in Western New York. There are 192 stream crossings along the 97-mile route from the fracking fields of Pennsylvania – 26 miles in Pennsylvania, 71 miles in Western New York. Pennsylvania authorities have granted National Fuel all the permits it sought, but New York has not. FERC officials ruled the DEC’s rejection of the stream crossing permit invalid because the decision came 36 days after the expiration of a deadline set in the federal Clean Water Act for the DEC to act on National Fuel’s request. The company and the DEC had agreed to an extension of the deadline, but FERC said the Clean Water Act doesn’t allow extensions. The DEC and the Sierra Club sued FERC in federal court. The case is pending before the U.S. Second Circuit Court of Appeals, with National Fuel intervening on FERC’s side. Tangled up in all the legal and regulatory issues are 200 acres in Clarksville owned by Theresa Schueckler, whose late husband, Joseph, refused to sell a slice to National Fuel for its pipeline. National Fuel took the Schuecklers to court early in 2017, and a State Supreme Court justice in Allegany County granted National Fuel the power to seize their land under the state’s eminent domain law. The Schuecklers appealed and in November 2018 won a 3-2 ruling by the Appellate Division, where the majority decided to ignore FERC’s decision that the DEC acted too late. The three judges said National Fuel couldn’t seize land for a project that hadn’t been approved by the DEC.

E.P.A. Limits States’ Power to Oppose Pipelines and Other Energy Projects – The New York Times – The Environmental Protection Agency on Monday announced that it had limited states’ ability to block the construction of energy infrastructure projects, part of the Trump administration’s goal of promoting gas pipelines, coal terminals and other fossil fuel development. The completed rule curtails sections of the U.S. Clean Water Act that New York has used to block an interstate gas pipeline, and Washington employed to oppose a coal export terminal. The move is expected to set up a legal clash with Democratic governors who have sought to block fossil fuel projects. Specifically, it limits to one year the amount of time states and tribes can take to review a project and restricts states to taking water quality only into consideration when judging permits. The Trump administration has accused some states of blocking projects for reasons that go beyond clean water considerations, such as climate change impacts. Andrew Wheeler, the administrator of the E.P.A., said the agency was moving to “curb abuses of the Clean Water Act that have held our nation’s energy infrastructure projects hostage, and to put in place clear guidelines that finally give these projects a path forward.” States, he said, would no longer be allowed to use the law to object to projects “under the auspices of climate change.” The rule was initially proposed in August shortly after President Trump issued an executive order directing agencies to “promote efficient permitting processes and reduce regulatory uncertainties that currently make energy infrastructure projects expensive and that discourage new investment.” Mr. Trump then directed the E.P.A. to revise rules for permits issued under Section 401 of the Clean Water Act, which gives states and tribes the ability to judge the potential impact that energy projects and other construction proposals might have on water quality. He called the current rules “outdated.” The American Gas Association, which represents natural gas distribution and transmission companies, praised the changes and described states’ objections to pipelines and other projects as “abuse.”

Environmental groups open new line of attack at FERC on Atlantic Coast Pipeline | S&P Global Platts – A coalition of environmental groups opened June 1 a new front in their legal war against the 600-mile, 1.5 Bcf/d Atlantic Coast Pipeline project, contending that a supplemental environmental impact statement is needed.The action comes as lead developer Dominion Energy already is laboring to get the project back into construction after a series of legal setbacks. For instance, it is hoping for a positive US Supreme Court decision soon to help reinstate permission vacated by a federal circuit court for the pipeline to cross the Appalachian Trail.The project is intended to move Appalachian gas to mid-Atlantic markets. Should the developer prevail in the Supreme Court, it faces a possible new avenue of litigation in the form of a roughly 4,000-page filing posted on the Federal Energy Regulatory Commission’s website June 1 by Southern Environmental Law Center, Appalachian Mountain Advocates and Chesapeake Bay Foundation on behalf of a coalition of conservation groups.The groups argued in the filing that a supplemental EIS is needed in light of new information that has come to light since FERC issued an EIS for the pipeline project in 2017, and given upcoming FERC decisions on key matters such as whether to extend certificate authorization for the project beyond the October expiration date and whether to lift FERC’s existing stop-work order on construction. Part of the groups’ rationale for a new review is that the region’s energy infrastructure has undergone a dramatic shift away from gas-fired power, while the cost of the pipeline has ballooned. “In January 2020, Virginia – the site of over half of the ACP’s proposed route – told the Supreme Court that in light of the mounting evidence that the pipeline is not needed, the ACP threatens Virginia’s natural resources without clear corresponding benefits,” they wrote.

EPA Changes Rule To Limit States’ Ability To Oppose Pipelines, Energy Projects – Federal environmental regulators finalized a rule Monday that reduces the time states have to approve federal permits for energy projects. The Environmental Protection Agency finalized changes to a portion of the Clean Water Act called Section 401. For decades, it has given states and tribes the power to review new projects to make sure they don’t harm local waterways. Under the law, states also had the power to withhold approval and set special conditions. In West Virginia, for example, the rule allowed environmental regulators to revoke and then reissue a permit for the Mountain Valley Pipeline. Section 401 has been used by some states, like New York, to prevent new pipelines from being built.In a press release, the EPA said some states abused the law, using it to stall energy projects, and the new rule, which sets a one-year time limit for states to approve or reject projects, is returning the law to its original intention.”EPA is returning the Clean Water Act certification process under Section 401 to its original purpose, which is to review potential impacts that discharges from federally permitted projects may have on water resources, not to indefinitely delay or block critically important infrastructure,” said EPA Administrator Andrew Wheeler.Under the adjusted rule, states are also now only able to consider water quality impacts, not a project’s impacts on things like climate change.Environmental groups opposed the rule change.In a statement, Jon Devine, director of federal water policy at the Natural Resources Defense Council said the rule was a mistake and infringes on states’ rights. “Enforcing state and federal laws is essential to protecting critical lakes, streams, and wetlands from harmful pollutants and other threats,” he said. “But the Trump administration’s rule guts states’ and tribes’ authority to safeguard their waters, allowing it to ram through pipelines and other projects that can decimate vital water resources.”

Besieged by Protesters Demanding Racial Justice, Trump Signs Order Waiving Environmental Safeguards –With the nation convulsed by multiple crises, President Donald Trump returned to a favorite stand-by of his presidency – asserting his authority to sweep aside environmental restraints and speed up construction of oil and gas pipelines. But the executive order that he signed Thursday night – the third of his presidency aimed at expediting pipelines – is destined to spur more of the type of litigation that has rendered his previous directives ineffective so far. The White House invoked the same legal authority the president has to expedite hurricane and flood response actions to declare an “economic emergency,” that requires the waiving of environmental reviews and other regulations. “This order will be a sitting duck for the sorts of legal challenges that have been so successfully brought against other Trump environmental rollbacks,” said Michael Gerrard, founder and faculty director of the Sabin Center for Climate Change Law at Columbia University. “Few developers or lenders will risk millions on starting construction in reliance on this order surviving in court.” The White House provided few details on the order before the scheduled signing at 4:30 p.m. “I can tell you it does have to do some of the permitting and energy as it relates to rebuilding this country,” said presidential spokesman Hogan Gidley in a brief noon appearance before reporters. Finally, after 6:15 p.m., the White House made copies of the order available. “From the beginning of my Administration, I have focused on reforming and streamlining an outdated regulatory system that has held back our economy with needless paperwork and costly delays,” Trump said in the document. “Antiquated regulations and bureaucratic practices have hindered American infrastructure investments, kept America’s building trades workers from working, and prevented our citizens from developing and enjoying the benefits of world-class infrastructure. The need for continued progress in this streamlining effort is all the more acute now, due to the ongoing economic crisis.” The president’s critics were quick to point out that his order was poorly timed, since minority communities would be disproportionately affected by his move to waive the environmental review mandated under the National Environmental Policy Act (NEPA). “Gutting NEPA takes away one of the few tools communities of color have to protect themselves and make their voices heard on federal decisions impacting them.”

Natgas flows to U.S. LNG export plants sink to 9-month low due to coronavirus – (Reuters) – The amount of natural gas flowing on pipelines to U.S. liquefied natural gas export plants is at its lowest levels since August, a signal of weak worldwide demand due to government lockdowns to repress the coronavirus. Worldwide gas prices have plunged to record lows in Europe and Asia as lockdowns squeeze demand. Consumption of liquefied natural gas (LNG) has remained stronger than gasoline demand as LNG is used for power generation, but the cash crunch hitting the global economy has cut demand. The amount of gas flowing to U.S. LNG plants was on track to fall to a nine-month low of 4.3 billion cubic feet per day (bcfd), data provider Refinitiv said in a preliminary report Monday that may be revised on Tuesday. U.S. gas at the Henry Hub <0#NG:> in Louisiana has traded higher than European benchmarks

Spot LNG, the worst-performing energy commodity, faces more price pain – (Reuters) – With the recovery in crude oil prices, spot liquefied natural gas (LNG) has assumed the unwanted mantle of the worst-performing major energy commodity this year. Spot LNG for delivery to North Asia in July dropped to $1.85 per million British thermal units (mmBtu) in the week to May 29, down from $1.92 mmBtu the prior week and matching the all-time low this year reached in the seven days to May 1. The price is down by nearly three-quarters from the winter demand peak of $6.80 per mmBtu from mid-October, and is almost two-thirds weaker on a year-to-date basis. In contrast, benchmark Brent crude futures have rallied nearly 150% since hitting the intraday low this year of $15.98 a barrel on April 22, ending at $39.79 on Wednesday. When it hit the April low, Brent was down 78% from its peak so far this year of $71.75 a barrel on Jan. 8, and it is still down by close to half since that high. But Brent’s partial recovery is an example of what happens when some supply discipline is applied to the markets. The Organization of the Petroleum Exporting Countries (OPEC) and its allies, including Russia, in the group known as OPEC+ agreed in April to end their price war and cut output by a combined 9.7 million barrels per day (bpd) for May and June. What crude oil shows is that having a producer organisation willing to prop up prices by cutting supply gives a better outcome price-wise than allowing only market forces to do the job. In LNG, the situation is more complex than crude. LNG trains are difficult to shut down, or even run at substantially reduced rates, meaning that closing down production is usually the very last option a producer will consider. As in crude, it seems the bulk of involuntary supply cuts is coming from the United States, where the rising price of natural gas has rendered U.S. LNG uncompetitive in both the key European and Asian markets.

Magnolia LNG sale falls through to company with ties to Lafayette, new buyer steps up – The Australian parent company behind the Magnolia LNG project near Lake Charles canceled a deal to sell the operation to a British business with a significant presence in Lafayette in late May. Global Energy Megatrend Ltd. was expected to pay $2.25 million to LNG Ltd. by May 15, but on May 25 the deal was terminated due to the buyer’s “failure to close the transaction within the required timeframe.” One day later, Magnolia LNG Holdings LLC, a Delaware-based entity incorporated on May 7, stepped up and bought Magnolia LNG for $2 million. The new purchase agreement includes an unsecured noninterest bearing promissory note worth $1.3 million if the Magnolia LNG project raises enough capital to begin construction. The new buyer also agreed to work with LNG Ltd. on a potential recapitalization of the company expected to be completed on Nov. 30. The deal includes the permits, land, detailed engineering plans and a contract for development, in addition to the underlying technology related to the LNG project. Former proposed buyer Global Energy Megatrend had described itself as an integrated natural gas company that has been leasing U.S. natural gas fields and investing in pipelines that lead to Louisiana ports and LNG export terminals. Global Energy Megatrend co-founders include Lafayette businessmen Bill Miller of Miller Energy LLC, Ben Blanchet and Eddie Moses of Miller Thomson & Partners LLC. It also has co-founders in London. Before that, LNG Ltd. had expected to be sold in a $75 million deal to Singapore-based LNG9 Ltd., but investors pulled out of that deal after a loan fell through. LNG Ltd. recently appointed administrators who were tasked with dealing with a potential insolvency; the company was on track to run out of money in May. In Australia, where LNG Ltd. is headquartered, administration is akin to Chapter 11 bankruptcy reorganization in the United States. Magnolia LNG was expected to export 8.8 million tons of LNG each year, but has not started construction. The project already has permits from the Federal Energy Regulatory Commission.

U.S. natural gas storage capacity remained relatively unchanged in 2019 – (EIA) Underground natural gas storage capacity in the Lower 48 states has remained relatively flat since 2012. The U.S. Energy Information Administration (EIA) measures working natural gas storage capacity in two ways: design capacity and demonstrated peak capacity. Both measures of capacity were relatively unchanged in 2019; design capacity declined 0.4% and demonstrated peak capacity increased 0.1% compared with 2018. For the sixth year in a row, no new storage fields were completed. Design capacity is calculated as the total of the working gas capacity for all active facilities in the Lower 48 states as of November 2019. Design capacity is an engineering estimate based on the physical characteristics of the reservoir, installed equipment, and operating procedures on the site, which often must be certified by federal or state regulators. Design capacity declined by 19 billion cubic feet (Bcf) in the Lower 48 states during 2019. Most of this decline occurred in the Mountain region, where working design capacity fell by 15 Bcf, or slightly more than 3% of the regional total. Storage operators may reduce design capacity at a storage field following an asset acquisition or reassessment of the operational capabilities. In the Mountain region, Spire Storage West reduced the working design capacity at the Belle Butte (formerly Ryckman Creek) field by 16 Bcf after acquiring the field in 2018. Increases in design capacity occurred primarily in the Pacific and East regions. In the Pacific region, the Northwest Natural Gas Company completed the North Mist capacity expansion project in Oregon, increasing working natural gas capacity by 2.5 Bcf. The North Mist expansion project was the only new natural gas storage reservoir to come online in 2019, increasing capacity at the Mist Underground Natural Gas Storage Facility. The facility provides flexible natural gas storage to Portland General Electric’s Beaver and Port Westward facilities to balance renewable power generation, such as wind and solar, which varies in response to changing weather conditions. Demonstrated peak capacity is calculated as the total of the highest storage levels reached by each storage facility during any month during the most recent five-year period, with the most recent period covering December 2014 to November 2019 (the beginning of each annual heating season). Demonstrated peak reflects how storage facilities were actually used, not just how they were designed. Demonstrated peak capacity remained nearly flat, increasing 3 Bcf, or 0.1%, for the Lower 48 states in 2019 compared with 2018, marking the first time that this metric posted an annual increase since November 2016.

U.S. natural gas falls 4% as LNG exports drop on record low global prices – (Reuters) – U.S. natural gas futures fell over 4% on Monday as liquefied natural gas (LNG) exports continued to drop with record low gas prices in Europe and Asia. The price decline came despite forecasts for warmer U.S. weather and higher air conditioning demand over the next two weeks than previously expected. Front-month gas futures for July delivery fell 7.5 cents, 4.1%, to settle at $1.774 per million British thermal units. Data provider Refinitiv said gas output in the U.S. Lower 48 states was on track to fall to 87.6 billion cubic feet per day (bcfd) on the first day of June, down from a one-year low of 89.3 bcfd in May and an all-time monthly high of 95.4 bcfd in November. With warmer weather coming, Refinitiv projected demand, including exports, would rise from 80.2 bcfd this week to 81.8 bcfd next week. That is higher than Refinitiv’s forecasts on Friday of 78.5 bcfd this week and 79.3 bcfd next week. With U.S. gas prices expected to remain higher than European benchmarks through September, the amount of pipeline gas flowing to U.S. LNG export plants was on track to fall to a nine-month low of 4.3 bcfd on the first day of June as buyers cancel cargoes. That is down from an eight-month low of 6.4 bcfd in May and a monthly record high of 8.7 bcfd in February. Most of the daily decline in LNG exports is expected at Cheniere Energy Inc’s exports plants at Sabine Pass in Louisiana and Corpus Christi in Texas, according to early Refinitiv data. Cheniere said it does not comment on its operations. Analysts at Energy Aspects said they expect around 125 U.S. cargoes to be shut-in this summer, potentially slashing LNG deliveries to Europe by up to 424 billion cubic feet compared to what was expected earlier.

U.S. natgas futures gain on storm concerns and rising LNG exports – (Reuters) – U.S. natural gas futures climbed on Wednesday ahead of a storm that could disrupt Gulf Coast production and as liquefied natural gas (LNG) exports edge up with gas prices rocketing higher in Europe. After dropping to record lows last week, major European gas benchmarks soared more than 40% over the past three days, driving forwards for September at the Title Transfer Facility (TTF) in the Netherlands above the U.S. Henry Hub in Louisiana for the first time since late April. In the Gulf of Mexico, meanwhile, Tropical Storm Cristobal is expected to sweep across Louisiana’s on- and offshore production areas over the coming weekend. Front-month gas futures rose 4.4 cents, or 2.5%, to settle at $1.821 per million British thermal units. Looking ahead, futures for the balance of 2020 and calendar 2021 were trading about 23% and 47% over the front-month, respectively, on hopes the economy will snap back as governments lift coronavirus-linked travel restrictions. Data provider Refinitiv said average gas output in the U.S. Lower 48 states fell to 88.3 billion cubic feet per day (bcfd) so far in June, down from a one-year low of 89.3 bcfd in May and an all-time monthly high of 95.4 bcfd in November. With the coming of warmer summer weather, Refinitiv projected U.S. demand, including exports, would rise from 81.0 bcfd this week to 82.0 bcfd next week. The amount of pipeline gas flowing to U.S. LNG export plants was on track to reach 4.5 bcfd on Wednesday up from a 13-month low of 3.8 bcfd earlier in the week. That compares with an eight-month low of 6.4 bcfd in May and a monthly record high of 8.7 bcfd in February. Analysts said U.S. LNG exports dropped in recent months as buyers cancel cargoes due to the collapse in European prices.

US working natural gas volumes in underground storage rise 102 Bcf on week: EIA | S&P Global Platts – US working gas in storage increased by 102 Bcf last week, which was less than the market expected, but Henry Hub futures remained static following the report. The amount of natural gas in US underground storage facilities increased 102 Bcf to 2.714 Tcf in the week that ended May 29, according to the US Energy Information Administration’s weekly report, released June 4. The injection was below the consensus expectations of analysts S&P Global Platts surveyed that called for a 111 Bcf build. Responses to the survey ranged from injections of 93 Bcf to 122 Bcf. The injection was 16 Bcf, or 13.6%, below the 118 Bcf build reported in the same week a year ago and 1 Bcf below the five-year average increase of 103 Bcf, according to EIA data. US supply-and-demand balances were largely flat week on week, with large offsetting changes in residential and commercial and power burn demand leaving only a small change, according to S&P Global Platts Analytics. Gas-fired power generation demand rose 2.9 Bcf/d on the week, with gains spread across most regions, with the Midwest, East, and South Central regions adding upward of 800 MMcf/d apiece. At the same time, the Midwest and East regions had residential and commercial demand falling by 1.4 Bcf/d and 800 MMcf/d, respectively. On the US level, declines continued in industrial, LNG feedgas and Mexican exports demand further. Upstream, total supplies held mostly steady, increasing by less than 100 MMcf/d on the week to an average 90.4 Bcf/d. Storage volumes now stand 762 Bcf, or 39%, above the year-ago level of 1.952 Tcf and 422 Bcf, or 18.4%, above the five-year average of 2.292 Tcf, the data show. The NYMEX July futures contract remained unchanged at $1.82/MMBtu in trading following the release of the weekly report and was little changed in the following 30 minutes. Henry Hub NYMEX futures for the balance of summer were trading mostly flat June 4 to the day prior’s close of $2.03/MMBtu, and flat to where it was priced a week ago, after some vacillation and a brief dip below $2/MMBtu earlier in the week. Spreads to next winter remain wide, with the July-through-October strip trading nearly 80 cents below the November-through-March window, as the market eyes a bullish 2021 on a tighter market stemming from supply drops from reduced associated gas production.

U.S. natgas flat as rising LNG exports offset small output increase – (Reuters) – U.S. natural gas futures were little changed on Thursday as rising liquefied natural gas (LNG) exports offset a smaller-than-expected weekly storage build and an increase in output. The U.S. Energy Information Administration (EIA) said utilities injected 102 billion cubic feet (bcf) of gas into storage during the week ended May 29. That was less than the 110-bcf build analysts forecast in a Reuters poll and compares with an increase of 118 bcf during the same week last year and a five-year (2015-19) average build of 103 bcf for the period. The increase boosts stockpiles to 2.714 trillion cubic feet (tcf), 18.4% above the five-year average of 2.292 tcf for this time of year. Front-month gas futures rose 0.1 cents, or 0.4%, to settle at $1.822 per million British thermal units. Refinitiv said gas production in the U.S. Lower 48 states fell to an average of 88.5 billion cubic feet per day (bcfd) so far in June from a one-year low of 89.3 bcfd in May and an all-time monthly high of 95.4 bcfd in November. Traders, however, noted daily output was up from a one-year low of 87.3 bcfd hit a couple of weeks ago. The amount of pipeline gas flowing to U.S. LNG export plants was on track to reach 5.2 bcfd on Thursday after dropping to a 13-month low of 3.7 bcfd on Monday. That compares with an eight-month low of 6.4 bcfd in May and a monthly record high of 8.7 bcfd in February. Analysts said U.S. LNG exports dropped in recent months after buyers canceled cargoes due to the collapse in European prices. But after collapsing to record lows last week, major European gas benchmarks have soared around 50% this week. That drove forwards for August and September at the Dutch Title Transfer Facility (TTF) above the U.S. Henry Hub for the first time since late April.

U.S. natgas slides on cooler weather and lower mid-June demand – (Reuters) – U.S. natural gas futures slipped 2% on Friday on forecasts for milder weather and lower air conditioning demand in mid-June. The decline came despite an increase in liquefied natural gas (LNG) exports and concerns a tropical storm threatening the Gulf of Mexico could cut output. Front-month gas futures for July delivery on the New York Mercantile Exchange fell 4.0 cents to settle at $1.782 per million British thermal unit. For the week, the front-month was down about 2% after rising almost 7% last week. Tropical Storm Cristobal is expected to sweep across Louisiana’s on- and offshore production areas over the weekend. Refinitiv said gas production in the U.S. Lower 48 states fell to an average of 88.6 billion cubic feet per day (bcfd) so far in June from a one-year low of 89.3 bcfd in May and an all-time monthly high of 95.4 bcfd in November. With the coming of milder weather in mid-June, Refinitiv projected U.S. demand, including exports, would rise from 81.2 bcfd this week to 82.2 bcfd next week before sliding to 81.6 bcfd in two weeks. The amount of pipeline gas flowing to U.S. LNG export plants was on track to reach 5.0 bcfd on Friday after dropping to a 13-month low of 3.7 bcfd Monday. That compares with an eight-month low of 6.4 bcfd in May and a monthly record high of 8.7 bcfd in February. Analysts said U.S. LNG exports dropped in recent months after buyers canceled cargoes due to a collapse in European gas prices. Major European benchmarks have soared around 60% this week from record lows last week, boosting forwards at the Dutch Title Transfer Facility (TTF) for all months over the U.S. Henry Hub for the first time since late April.

Is Puerto Rico About to Give Another Terrible Energy Contract to an American Company? – On January 6 and 7, a 6.4-magnitude earthquake and aftershocks struckPuerto Rico, killing at least one person, injuring more, and causing mass blackouts across the island’s already hobbled electrical grid. Citing damage to the Costa Sur power plant, the Puerto Rico Electric Power Authority, or Prepa, said in late January it would need to purchase some 500 megawatts of temporary generating capacity.Now it looks like an American natural gas company could win this contract, flooding the island with fossil fuels rather than investing in the renewable energy that experts say could better withstand both earthquakes and hurricanes. The company’s prior business in Puerto Rico has been conducted with minimal public oversight and a seemingly lax relationship to legal standards governing maritime fuel transport.On its quarterly earnings call in early May, New Fortress Energy announced that it had been shortlisted by Prepa, the island’s sole electric utility, to fill the gap left by damage to Costa Sur. For at least one year, NFE would supply 500 MW worth of generating capacity, reportedly at the cost of some $70 million a month. There’s also a possibility that Prepa could end up permanently purchasing this generating capacity. This would all be a pretty good deal for NFE, which is looking for a place to stash and burn extra fossil fuels that appear to be sourced largely fromthird-party providers, in addition to its liquefaction facility in Miami. As the company’s founder and CEO, Wes Edens, said on the call, “We’ve got a couple of cargoes extra that we have contracted for that we don’t need right now. And I think that what we will do is, either sell those on an outright basis or swap them into cargoes that we can then use in Puerto Rico.” Should NFE win its bid, the Federal Emergency Management Agency might furnish the funds to do just that and could reimburse the cost of the temporary generation per the terms of the Stafford Act. It wouldn’t be a great deal for building a more resilient Puerto Rican energy grid. “They just want to flood Puerto Rico and the Caribbean with fracked gas,” said Ruth Santiago, an attorney with the Environmental Dialogue Committee supporting Queremos Sol (“We Want Sun”), a platform for clean energy development and climate justice backed by a number of environmental and community groups and unions across the island. The coalition has opposed the most recent contractor bidding process, as well as ongoing fossil fuel development on the island.

Equinor planning to shut Gulf production ahead of Cristobal – Equinor is removing workers from its Titan platform in the Gulf of Mexico and is tentatively planning to shut oil production on June 5 ahead of Tropical Depression Cristobal. Cristobal was weakened from a tropical storm to a depression as it hovered over southern Mexico, but the US National Hurricane projects it to regain tropical storm strength as soon as June 5 and make landfall in Louisiana on June 7. The Norwegian energy firm only operates Titan in the Gulf but holds ownership stakes in other facilities. Equinor produces about 120,000 boe/d from the Gulf. Total crude oil production from the US Gulf is nearly 2 million b/d, according to the US Energy Information Administration. “We are currently monitoring the path of the storm and have begun the process of removing non-essential personnel from the Titan facility,” Equinor spokesman Erik Haaland said. “If the track of the storm continues along its projected path, we expect to shut in production and remove remaining personnel on Friday.” The largest producers in the US Gulf already are taking action to remove non-essential workers or to reduce production volumes temporarily. BP was the first to say it had begun ramping down its output. “With forecasts indicating that Cristobal will begin moving north across the Gulf of Mexico later this week, BP has begun removing offshore personnel and ramping down production at BP’s operated facilities Thunder Horse, Atlantis and Na Kika,” BP spokesman Jason Ryan said June 3. “Non-essential personnel are being evacuated from BP’s operated Mad Dog platform, but production remains unaffected at this time.” Murphy Oil said June 4 it began evacuating non-essential personnel from the Gulf, but a spokesman declined to comment on specific locations and on any impacts to production volumes. Talos Energy said it is preparing to evacuate workers. Other producers are beginning to reduce personnel as well.

Plaquemines Parish Faces Service Cuts, Layoffs And A Big Question: Can It Still Rely On Oil? –The people of Plaquemines Parish are experienced in surviving disasters, from floods to hurricanes, but now this community is facing one of the biggest threats yet: the collapsing oil market. The parish’s budget is tied to the price of oil because the parish is in the oil business. It owns about 100,000 acres of land in the Gulf of Mexico that it leases out to oil companies, which pay to drill there.Last year, the parish hired its usual consultants and the finance office worked up estimates for this year’s budget accounting for the price of oil. A barrel of oil then was $59. Now it’s just $30. Because of the coronavirus’ impact on oil prices, the parish faces a $7.5 million budget shortfall, forcing lawmakers to consider whether to raise taxes, lay off staff, cut services, or all of the above. At a recent parish council meeting, held on Zoom, finance manager Tommy Serpas proposed taking out bonds to cover the difference and keep the government operating.”When we run out of money in August or September, how are we going to pay the bills? I mean, everything will have to stop. We won’t be able to pay anything,” he said, sounding exasperated. Councilmember Trudy Newberry agreed: “This pandemic is an eye-opener. We need to get off our butts and we need to do something!”

19 energy companies have filed for bankruptcy in 2020: law firm – Texas-based Gavilan Resources last month filed for Chapter 11 protection, saying it intends to sell its business and assets. It cited the coronavirus pandemic and the oil price rout along with an ongoing dispute with a joint venture partner in the Eagle Ford Shale in South Texas, Kallanish Energy reports. It is among 19 new bankruptcies filed in 2020 through May 31 by U.S. energy companies, according to a list maintained by the Haynes and Boone law firm. The firm with headquarters in Dallas, Texas, said the 19 filings reflected a total debt of $13.1 billion. Other firms filing for federal protection include Whiting Petroleum, Echo Energy Partners, Ultra Petroleum, Skylar Exploration, Diamond Offshore, Freedom Oil and Gas, and Templar Energy. There were 51 bankruptcy filings from Jan. 1 through May 31 in 2016; 14 in 2017, 18 in 2018, and 18 in 2019, the law firm said in its Oil Patch Bankruptcy Monitor. Overall, there are about 225 bankruptcy cases across the country pending in federal bankruptcy courts, as of May 31, it said. There have been predictions that a wave of Chapter 11 filings is coming and that more than 100 U.S. energy companies may be forced to declare bankruptcy this year after the coronavirus pandemic and the oil price rout. According to Haynes and Boone, there have been 13 bankruptcies by oilfield service companies in 2020, through May 31. Those filings had a total debt of $11.6 billion, it said. That compares to 28 bankruptcies from Jan. 1 through May 31 in 2017, eight in 2018 and four in 2019, the law firm said in a separate listing of wellfield service companies.

Stuck with too much diesel, U.S. refiners need to restrict runs – Kemp (Reuters) – U.S. refiners are struggling to manage their production and stocks as the economy’s uneven re-opening leaves demand for some refined fuels recovering much faster than others. Output cuts by OPEC+ and U.S. domestic producers have brought crude inventories under control, but stocks of refined products, especially diesel and other middle distillates, are rising unsustainably. U.S. consumption of gasoline is recovering much faster than diesel, as stay-at-home orders are lifted but much of the manufacturing, freight and distribution system is still operating at reduced rates. By focusing on meeting rising demand for gasoline, their most important product by volume and revenue-generation, refiners have left the market awash with diesel, which is now depressing profit margins. In the week to May 29, refiners boosted crude processing to an average of 13.3 million barrels per day (bpd), up from a recent low of 12.5 million bpd in mid-April (https://tmsnrt.rs/3dvwo8o). Gasoline consumption continued to recover steadily, with the volume supplied to the domestic market reaching an estimated 7.5 million bpd last week, up from a low of just 5.1 million bpd in early April. More than half of the gasoline consumption lost when the country went into lockdown has now returned as stay-at-home orders are lifted and private motoring increases. But distillate consumption is showing a much softer recovery, with supply last week at just 2.7 million bpd, no higher than during the most intense lockdown in early April. Gasoline stocks remain high but appear under control, rising by 3 million barrels last week and up just 11 million barrels since the country went into lockdown in late March. Stocks are around 24 million barrels (10%) higher than year-ago levels and 38 million barrels (17%) above the ten-year seasonal average, which is manageable. By contrast, distillate stocks surged by almost 10 million barrels last week, the ninth weekly increase in a row, with inventories up by 52 million barrels (43%) since the end of March. Distillate stocks are now 45 million barrels (35%) higher than at the same point last year and 43 million barrels (33%) higher than the ten-year seasonal average, and are still trending higher.

20,000 gallons of oil found illegally buried in Crosby, leaking into nearby waterway, officials say – The Harris County Precinct 1 Constable’s Office is investigating what they call a serious crime against the environment in Crosby, Texas.On May 28, environmental investigators were called to 1017 Church Street and discovered tens of thousands of gallons of oil buried illegally at the property.”It was buried here and it is everywhere,” said Harris County Precinct 1 Constable Alan Rosen. “You can smell it, you can see it and it is oozing out of the ground as we dig.”Rosen says investigators were tipped off by a citizen who saw oil flowing into a nearby drainage ditch.During the investigation, Rosen says members of his Environmental Crimes division discovered ruptured barrels of oil buried deep in the ground in layers on the property. That oil was then discovered leaking into a nearby drainage ditch.”It stretched at least one-quarter mile west along Church Street and 655 feet to the south along the San Jacinto River Authority’s clean water basin,” officials wrote in a press release.Crews are working to try and clean up the leaking oil and prevent it from spreading further into surrounding waterways.”Since last week remediation teams have removed over 20 thousand gallons of contaminated oil/water mix from those ditches.”Investigators said the size and volume of the contamination were among “the largest and most significant they have ever worked.””This is a very serious environmental case,” Rosen said.The Harris County District Attorney’s Office helped Constable’s deputies obtain a search warrant Friday. Soil samples from the property will undergo chemical analysis and if investigators can prove the chemical on the property did in fact seep into the nearby ditches, they may seek criminal charges, officials wrote.As of Friday night, property owner Wesley Zarsky has not been arrested or charged.A temporary restraining order was obtained to prevent Zarsky from dumping any kind of hazardous waste or oil on the property and force him to begin cleanup.Officials estimate the total cost of cleanup has already surpassed $1 million.

Armed With Eminent Domain, Pipeline Projects Continue to Burden Landowners During the Pandemic — Pipeline giant Kinder Morgan is cutting a 400-mile line across the middle of Texas, digging up vast swaths of private land for its planned Permian Highway Pipeline. The project is ceaseless, continuing through the coronavirus pandemic. Landowner Heath Frantzen said that dozens of workers have showed up to his ranch in Fredericksburg, even as public health officials urged people to stay at home. “There weren’t wearing masks. They weren’t wearing gloves. They weren’t practicing social distancing,” he said. Frantzen believes the workers pose a danger to him and his 85-year-old father, whom he cares for. While the laborers are confined to the pipeline’s path, he worries they could spread the coronavirus by touching fence railings or gates that he might later handle. In Texas, where the governor exempted pipeline projects from his March stay-at-home order, companies like Kinder Morgan have few checks on their power of eminent domain, which allows them to build pipelines through privately owned farms and ranches that lie in their way. Eminent domain is broadly unpopular and, when used for pipelines, legally contentious. The coronavirus adds a new wrinkle to the debate over the practice as companies like Kinder Morgan continue to work through the pandemic, vexing landowners. “It is wild that people are being forced to accept others onto their land at this time, and if they have an issue with what’s happening, they have to put themselves at risk to address workers directly,” said Erin Zweiner, who represents Blanco County and Hays County in the Texas House of Representatives. “These are workers who hop all over the country, so they’re pretty high-risk spreaders.”

Drilling drought –Monday marked the first day of Hurricane Season and there’s already a tropical depression in the Bay of Campeche, but there’s a drought of sorts in progress.The Eagle Ford Shale of South Texas is on the verge of entering a drilling permit drought.Houston oil company EP Energy was the only company to file a drilling permit for a project in the region from May 20 to 26. EP Energy, which filed for Chapter 11 bankruptcy in October, is seeking permission to drill a single horizontal well in La Salle County.Record low crude oil prices caused by the coronavirus pandemic continue to take their toll on drilling permits fillings. Only 23 companies filed for 45 drilling permits in Texas from May 20 to 26.

Permian gas pollution halves in upside of oil crash –Natural gas pollution at the world’s most prolific oilfield will halve in the coming months, providing an environmental upside to the worst crash in the price of crude in decades.As tumbling demand forces producers to shut in wells across the US, analysts at Rystad Energy estimate the amount of gas flared – where drillers burn off the less valuable gas found alongside the oil – in the Permian Basin will fall from 600m cubic feet a day at the beginning of the year to below 300m cubic feet in the second half.The drop-off is equivalent to the amount of gas required to heat half of all homes in Texas.”In the second quarter we will definitely see a massive decline,” said Artem Abramov, head of shale research at Rystad. “More or less all fracking activities are on hold. Where there is still activity going on it is marginal.” Flaring occurs where gas is recovered as a byproduct of oil drilling. Often a lack of infrastructure makes finding a market for the gas uneconomical, so the easiest option is to set it alight.But the practice is highly polluting. Burning the gas emits carbon dioxide into the atmosphere. And where equipment is not up to scratch, it can also lead to methane – which traps far more heat than CO2 – being vented directly into the air. The shale boom of the past decade has caused US oil production to soar, allowing Donald Trump to boast of “energy independence”. Output surpassed 13m barrels a day earlier this year, with the Permian accounting for more than a third of this.But with the growth in production has come a rise in flaring. The Texas Railroad Commission, which regulates the practice in much of the Permian, issued almost 7,000 licences last year – more than 20 times the figure a decade earlier. Among the basin’s biggest flarers on an absolute basis are ExxonMobil-owned XTO Energy, Diamondback E&P and Encana Oil and Gas, according to the regulator.However, smaller, private equity-backed companies, eager to make quick returns, tend to be the worst offenders, analysts said. The Railroad Commission lists small-time producers including Continental Trend Resources, Siltstone Resources and Mammoth Exploration – which only produce a few hundred barrels of oil a day between them – as having the worst record for flaring relative to output.

State Reopenings Give Oil And Gas Producers A Temporary Boost – podcast – Over the past few months, the pandemic has had a profound impact on almost every aspect of the U.S. and Texas economies. Added to that, huge drops in the oil market have devastated Texas’ most lucrative export industry.But Matt Smith, director of commodity research at ClipperData, told Texas Standard host David Brown that oil and gas producers might get some relief as states reopen and people return to work. He said oil prices are slowly starting to climb.”As oil has rallied in the last month or so … oil prices are dragging gasoline prices higher, even though demand hasn’t necessarily done that ‘V’ rebound by any means,” Smith said.Oil prices will likely continue to climb along with consumer demand, and also if OPEC continues to limit oil production. Earlier this year, OPEC member country Saudi Arabia flooded the market, which contributed to the steep drop in oil prices.But Smith warned that stability in the oil and gas market is still tenuous, especially as Latin America faces its worst phase so far of the COVID-19 pandemic. What you’ll hear in this segment:

• – Why Latin America matters to U.S. oil and gas producers
• – Whether summer travel could bolster the energy sector
• – How the rise in telecommuting could have long-term effects on oil and gas production

Shale Oil Production Bouncing Back With Prices— Early signs of a shale rebound are becoming evident as crude prices emerge from their dramatic collapse earlier this year. EOG Resources Inc., America’s largest shale-focused producer, plans to “accelerate” output in the second half after shutting in about a quarter of its crude in May, exploration chief Ken Boedeker told an RBC Capital Markets conference Tuesday. Permian producer Parsley Energy Inc. is also turning wells back on just weeks after closing the taps, and producers in the Bakken formation in North Dakota are also easing the rate of shut-ins. After the breakup in the OPEC+ alliance in March and a plunge in demand because of virus-related lockdowns, which pushed the price of West Texas Intermediate to minus $40 a barrel on April 20, oil has been on a steady march upward during the past month. While the U.S. benchmark price is still about 40% below its high point in January, it has jumped to more than $35, above the operating costs of some shale wells that had been closed to save cash. Futures were up 2.3% at $36.24 at 11:50 a.m. in New York. EOG’s strategy “is to really accelerate our production into what we see as a price recovery in the second half of the year,” Boedeker said. The company, which began shutting wells in March and took 125,000 barrels a day off the market in May, recently reduced its hedge position, eliminating some protection against lower prices in a sign of confidence the price recovery will take hold. Parsley will restore the “vast majority” of the 26,000 barrels of daily output it turned off last month, it said in a slide deck for an investor presentation.” Meanwhile, shut-ins in the Bakken totaled 475,000 barrels a day as of May 28, about 7% less than a fortnight earlier. The number of frack crews working in shale fields is believed to have now bottomed at about 80 fleets, with “noticeably higher” completion work in the next three to six months, Based on current budget tweaks announced by explorers, as many as 50 frack crews could still be added by the end of the year, with that number doubling if oil prices move closer to $40 a barrel,

US Production May Be Significantly Less Than EIA Estimate: Bloomberg, Reader — June 4, 2020 – After the EIA weekly petroleum report was released yesterday, a reader who follows this very, very closely, noted: I haven’t even looked at the rest of the report, but the first thing I noticed is that a million barrels of oil per day went missing for the third week in a row, ie, production + imports + storage withdrawal has been 1 mbpd greater than refinery use + exports + the SPR addition… Best guess is that their production number has been wrong… You can see my reply at this post. Overnight, Bloomberg posted an article saying the very same thing: oil traders are asking why US inventory math doesn’t add up. “Oil traders and analysts scrutinizing U.S. inventory data for signs of a market recovery are being confronted by an odd situation: the math just doesn’t add up. Various government data sets including stockpiles, production, imports and exports are signaling that current official figures on at least some supplies are excessive.The excess is showing up in the U.S. Energy Information Administration’s so-called crude supply adjustment factor — the difference between stockpile numbers and those implied by production, refinery demand, imports and exports.That has averaged negative 980,000 barrels daily over the past four weeks — the largest in records going back to 2001, and equivalent to more than 27 million barrels.”That’s nearly exactly what the reader reported: a one-million-bopd discrepancy. The Bloomberg article continues:The adjustment factor tends to swing back and forth …Some investors lay the blame for the current discrepancy on U.S. oil production numbers. While daily output fell 700,000 barrels to 11.2 million in May, they believe oil’s plunge into negative territory in April should have led to a steeper decline. Just last month, consultancy IHS Markit said that U.S. oil producers are in the process of curtailing 1.75 million barrels a day of existing output by early June…

Lower crude oil prices will mean less exploration and development -According to the financial reports analyzed by the U.S. Energy Information Administration (EIA), global expenditures related to oil and natural gas exploration and development (E&D) increased $42 billion (13%) for 102 publicly traded oil companies in 2019, totaling $361 billion. As a result of significant crude oil price declines in 2020, however, global proved reserves will likely be revised downward, and E&D expenditures will also likely decline. Several companies have already announced large budget reductions.EIA based its analysis and its recently published 2019 Financial Review primarily on the published financial reports of 102 publicly traded companies, so the conclusions do not necessarily represent the sector as a whole because the analysis does not include private companies that do not publish financial reports.According to their financial statements, these 102 companies produced 22.2 billion barrels of oil equivalent (BOE), a measure that reflects their combined production of crude oil and natural gas, and spent $361 billion in E&D. Dividing these companies’ E&D expenditures by their combined production volumes provides a ratio of $16/BOE in 2019, or about one-quarter of the average Brent crude oil price of $64/barrel (b).In its May Short-Term Energy Outlook, EIA forecasts Brent crude oil prices will average $34/b in 2020. If this crude oil price forecast is realized, E&D expenditures per BOE could fall to less than $10/BOE in 2020 if E&D expenditures remain at about one-quarter of the Brent crude oil price.Proved reserves are estimated quantities of oil and natural gas that analysis of geological and engineering data demonstrates with reasonable certainty are recoverable under existing economic and operating conditions. Because crude oil prices directly affect the profitability of E&D projects, changes in the prices companies use to develop their calculation of reserves can significantly affect their proved reserves levels and the volume of reserves they can claim as additions.

Some analysts still bet on Chesapeake going bankrupt this year – Oklahoma City’s Chesapeake Energy continues to be on a list of analysts who predict will be among those firms filing for bankruptcy this year, a move hastened perhaps by the COVID-19 pandemic and the oil crisis.Analyst Travis Hoium, writing for Motley Fool predicted Chesapeake is one of three firms he believes will head to bankruptcy court yet this year.The oil industry has been flipped on its head over the last few months as economic shutdowns around the world have caused demand to plummet by around 20%. For a short time, oil futures prices even went negative in the U.S. because there was more supply than demand.”Producers and suppliers in the oil market are trying to cut costs and adjust finances as quickly as possible, but not everyone will survive. And Occidental Petroleum (NYSE:OXY), Chesapeake Energy (NYSE:CHK), and Transocean (NYSE:RIG) are three that I think might be considering bankruptcy by the end of the year,” wrote Hoium.Chesapeake Energy has always been a company willing to take risks to grow its business, but that’s likely to backfire. The company has $8.9 billion of debt and even before COVID-19 and the resulting drop in oil prices wasn’t able to squeeze out much of a profit.Cash on hand was a meager $82 million as of March 31, 2020, so there isn’t a big financial backstop on the balance sheet either. To shore up the balance sheet and pay off $253 million of debt coming due this year, management had planned to sell $300 million to $500 million of non-core assets, which will likely be difficult in the current energy environment. Oil prices have recovered slightly over the past month but for Chesapeake Energy, the drop in natural gas prices could be offset any oil gains. The company is still a big producer of natural gas and that market has collapsed as well. Chesapeake Energy may have enough hedges and assets to survive for a few more months, but if the weak energy market continues much longer it won’t survive the year.

Enbridge likely to miss prime construction season for new Minnesota pipeline – Enbridge had hoped this month to be building its controversial and much-delayed oil pipeline across northern Minnesota. Instead, the company may miss prime construction season for the second year in a row.Minnesota pollution-control regulators are expected to announce this week whether to make a deeper inquiry into Enbridge’s pipeline construction permits.If they do – and that seems increasingly likely – Enbridge probably won’t be able to start construction until late fall at best.The $2.6 billion proposed pipeline, which is a replacement for its deteriorating Line 3, has been winding through the state’s regulatory process for five years. The Minnesota Public Utilities Commission (PUC) reapproved the new Line 3 in early February.The PUC is the primary regulator of oil pipelines in Minnesota, including determining the risk of oil-spill hazards once they are in operation. But Enbridge must also get more technical approvals from the Minnesota Pollution Control Agency (MPCA) and other agencies.The MPCA in February released “draft permits” for the new Line 3 construction. In April, environmental groups and Ojibwe bands that oppose the new line petitioned the MPCA to conduct a “contested case” on the permits.A contested case usually involves hearings and a review by an administrative law judge. Darin Broton, an MPCA spokesman, said Tuesday that the agency is still reviewing its decision, though he declined to disclose it.”We are looking at the legal guidance set by the [Minnesota] Court of Appeals in the PolyMet case,” he said. “The Court of Appeals made it clear that agencies don’t have unfettered discretion to reject a contested case if issues of fact are unresolved.”

State officials agree to give Line 3 permits additional scrutiny State regulators agreed Wednesday to hold an additional hearing on a key permit for the proposed Line 3 replacement project, a process that is expected to delay construction of the controversial oil pipeline by several months. The Minnesota Pollution Control Agency announced that a contested case hearing will be held later this summer on a draft water quality permit for the project, in which a state administrative law judge will hear additional evidence on the proposed pipeline’s impacts on wetlands and stream crossings. The decision to hold the additional hearing pushes back the MPCA’s deadline to make a decision on the permit – known as a 401 water quality certification – until Nov. 14, three months past the original timeline. “The contested case hearing will help ensure the certification is protective of one of Minnesota’s most important resources,” said MPCA Commissioner Laura Bishop in a statement. State utility regulators have already approved Enbridge’s controversial project. The Canadian company wants to replace an aging, deteriorating pipeline that delivers crude from the Alberta oil sands across northern Minnesota. But the project has been stalled by legal and regulatory delays, which have raised the estimated project cost to $2.9 billion. The company still needs additional construction permits from the MPCA, the state Department of Natural Resources, and the U.S. Army Corps of Engineers. In a statement, Enbridge said it still anticipated starting construction on the project before the end of the year, a process that will take six to nine months to complete. “While the contested case has caused a delay to the permitting process, we believe this additional step will strengthen the MPCA’s decision record,” said Vern Yu, Enbridge’s president of liquids pipelines. The Red Lake Nation and White Earth Band of Ojibwe, along with several individuals and environmental groups – including Friends of the Headwaters, the Sierra Club and Honor the Earth – had asked for the contested case hearing on a number of grounds, including the pipeline’s contribution to climate change and the risk of oil spills. But the hearing the MPCA granted will focus on relatively narrow issues, including the amount of wetlands that will be impacted by the project, and the potential impacts where the proposed pipeline would cross streams and rivers. The Sierra Club’s North Star Chapter Director Margaret Levin welcomed the additional scrutiny on Line 3. “This tar sands pipeline would be a disaster for our waterways and communities, she said.

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