Focus on Fracking: US oil supplies at 36½ year low, refinery utilization at 40 month high, biggest build of distillates supplies in 29 months

US oil supplies now at a 36½ year low, Strategic Petroleum Reserve at a 38½ year low; highest refinery utilization rate in 40 months, biggest build of distillates supplies in 29 months

oil prices fell every day this past week and ended near a 12 month low after a G7 price cap on Russian oil exports kicked in as global recession fears mounted...after rising to a three week high above $83 last week before settling at $79.98 a barrel on the potential for a further output cut by the OPEC+ group, Covid-19 lockdown easing in China, a large inventory draw, an expected halt to SPR releases, and a weaker U.S. dollar, the contract price for the benchmark US light sweet crude for January delivery climbed as much as 3% in early trading on Monday after China signaled a broader relaxation of Covid curbs, OPEC+ announced its decision not to change oil production targets, and a price cap on Russian oil took effect, but then followed equity markets lower in afternoon trading and tumbled to close $3.05 lower at $76.93 a barrel after a U.S. service sector survey raised fears that the Fed would continue its aggressive tightening and eventually steer the U.S. economy into recession....oil prices edged higher in Asian trading on Tuesday after the G7 price cap on Russian seaborne oil came into force on Monday on top of a European Union embargo on imports of Russian crude by sea, but again tumbled in US trading, falling $2.68 to $74.25 a barrel, the lowest price in nearly a year, after the International Energy Agency (IEA) said the Omicron coronavirus variant was set to dent global demand recovery....oil prices held their 11 month low in overnight trading, in spite of an American Petroleum Institute Report of another huge draw from US crude supplies, and then fell further on Wednesday, as recession worries gripped financial markets after top U.S. banks warned of a recession in 2023 and China reported weak trade balance figures for November, and settled $2.24 lower at a twelve month low of $72.01 a barrelafter the weekly EIA inventory report showed continued soft demand and growing stocks of refined fuels, feeding concerns of a weakening economy....oil prices bounced off the 12 month lows in early trading Thursday on prospects of a broader reopening in China that could boost global oil demand next year, but resumed their slide in afternoon trading to settle 55 cents lower at $71.46 a barrel, as traders focused on concerns that global economic slowdowns would slash fuel demand, while an oil leak that led to a shutdown of the Keystone Pipeline and talk of a potential buyback of oil to refill U.S. reserves helped to limit price losses...oil priices bounced again in Asian trading Friday on news that the closure of the Canada-to-U.S. Keystone pipeline had disrupted US supplies, but again turned lower in US trading to settle down 44 cents at $71.02 a barrel, as growing recession fears negated any supply woes after weak economic data from China, Europe and the United States...oil prices thus finished the week off 11.2%, their biggest weekly drop since March and ended trading at their lowest level since December 21, 2021

meanwhile, natural gas prices finished lower for a second straight week, despite colder forecasts for the rest of December... after falling 14.3% to a two week low of $6.281 per mmBTU last week on milder forecasts and a delay in the restart of the Freeport export terminal, which will leave more gas available for domestic use, the contract price of US natural gas for January delivery opened 45 cents lower and extended last week's selloff by more than 11% on Monday in falling 70.4 cents to $5.577 per mmBTU, as forecasts for milder weather cast a shadow on the demand outlook, already hurt by the delayed restart of the Freeport export plant....natural gas prices slid 10.8 cents, or almost 2% to a fresh five-week low of $5.469 per mmBTU on Tuesday, as natural gas prices followed crude prices lower after forecasts for milder weather next week than was previously expected....but a revision in the forecasts for colder weather over the next two weeks and profit taking by short sellers led to a reversal of natural gas prices on Wednesday, as January gas rose 25.4 cents to $5.723 per mmBTU, a rally which extended into Thursday, when \as prices rose 23.9 cents to $5.962 per MMBTU, as a polar plunge forecast for next week continued to drive prices, despite an EIA report showing a smaller-than-expected decline in inventories last week...colder forecasts through late December brought another near 5% price gain of 28.3 cents to $6.245 per mmBTU in Friday's trading, but prices still finished 0.6% lower on the week...

The EIA's natural gas storage report for the week ending December 2nd indicated that the amount of working natural gas held in underground storage in the US fell by 21 billion cubic feet to 3,462 billion cubic feet by the end of the week, which meant our gas supplies were still 51 billion cubic feet, or 1.5% less than the 3,513 billion cubic feet that were in storage on December 2nd of last year, and 58 billion cubic feet, or 1.6% below the five-year average of 3,520 billion cubic feet of natural gas that were in storage as of the 2nd of December over the most recent five years....the 21 billion cubic foot withdrawal from US natural gas working storage for the cited week was less than the average forecast for an 31 billion cubic feet withdrawal by a Reuters poll of analysts, and much less than the 59 billion cubic feet that were pulled from natural gas storage during the corresponding week of 2021, and also much less than the average 49 billion cubic feet of natural gas that have typically been withdrawn from our natural gas storage during the same week over the past 5 years...

The Latest US Oil Supply and Disposition Data from the EIA

US oil data from the US Energy Information Administration for the week ending December 2nd indicated that even after a near record drop in our oil exports and an incremental increase in our oil production, we needed to pull oil out of our stored commercial crude supplies for the 11th time in 17 weeks, and for the 19th time in the past 33 weeks, despite the ongoing releases of oil from the SPR.....Our imports of crude oil fell by an average of 24,000 barrels per day to average 6,012,000 barrels per day, after falling by an average of 1,027,000 barrels per day during the prior week, while our exports of crude oil fell by 1,518,000 barrels per day to average 3,430,000 barrels per day, which together meant that the net of our trade in oil worked out to an import average of 2,582,000 barrels of oil per day during the week ending December 2nd, 1,494,000 more barrels per day than the net of our imports minus our exports during the prior week.. Over the same period, production of crude from US wells was reportedly 100,000 barrels per day higher at 12,200,000 barrels per day, and hence our daily supply of oil from the net of our international trade in oil and from domestic well production appears to have averaged a total of 14,782,000 barrels per day during the December 2nd reporting week…

Meanwhile, US oil refineries reported they were processing an average of 16,585,000 barrels of crude per day during the week ending December 2nd, an average of 53,000 fewer barrels per day than the amount of oil that our refineries processed during the prior week, while over the same period the EIA’s surveys indicated that a net average of 1,041,000 barrels of oil per day were being pulled out of the supplies of oil stored in the US. So, based on that reported & estimated data, the crude oil figures from the EIA for the week ending December 2nd appear to indicate that our total working supply of oil from net imports, from oilfield production, and from storage was 762,000 barrels per day less than what our oil refineries reported they used during the week. To account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a (+762,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet in order to make the reported data for the daily supply of oil and for the consumption of it balance out, a fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting there must have been an omission or error of that magnitude in this week’s oil supply & demand figures that we have just transcribed....moreover, since last week’s EIA fudge factor was at (+1,452,000) barrels per day, that means there was a 690,000 barrel per day difference between this week's balance sheet error and the EIA's crude oil balance sheet error from a week ago, and hence the changes to supply and demand from that week to this one that are indicated by this week's report are off by that much, rendering those comparisons completely meaningless....however, since most everyone treats these weekly EIA reports as gospel, and since these figures often drive oil pricing, and hence decisions to drill or complete oil wells, we’ll continue to report this data just as it's published, and just as it's watched & believed to be reasonably 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)….

This week's 1,041,000 barrel per day decrease in our overall crude oil inventories left our oil supplies at 800,917,000 barrels at the end of the week, which was our lowest total oil inventory level since January 31st, 1986, and therefore at a new 36 1/2 year low....Our oil inventories decreased this week as an average of 741,000 barrels per day were being pulled out of our commercially available stocks of crude oil, while 300,000 more barrels per day of oil were being pulled out of our Strategic Petroleum Reserve. That draw on the SPR was an extension of the emergency withdrawal under Biden's "Plan to Respond to Putin’s Price Hike at the Pump" (sic), that was originally intended to supply 1,000,000 barrels of oil per day to commercial interests over a six month period from its inception to the midterm elections in November, in the hope of keeping gasoline and diesel fuel prices from rising over that time....The SPR withdrawals under that program had been fluctuating in recent weeks because the administration has alsoo been attempting to use the Strategic Petroleum Reserve to manipulate prices on a weekly basis; furthermore, Biden recently announced another 15,000,000 barrel release from the Strategic Petroleum Reserve to run thru December, while simultaneously announcing he'd buy crude to replenish the SPR if oil prices fall to or below the $67-72 a barrel range, effectively putting a floor under oil at that price.....Including the administration's initial 50,000,000 million barrel SPR release earlier this year, their subsequent 30,000,000 barrel release, and other withdrawals from the Strategic Petroleum Reserve under recent release programs, a total of 269,122,000 barrels of oil have now been removed from the Strategic Petroleum Reserve over the past 28 months, and as a result the 387,019,000 barrels of oil that still remain in our Strategic Petroleum Reserve is now the lowest since February 24th, 1984, or at a new 38 1/2 year low, as repeated tapping of our emergency supplies for non-emergencies or to pay for other programs had already drained those supplies considerably over the past dozen years, even before the Biden administration's SPR releases. The total 180,000,000 barrel drawdown of the current release program, now scheduled to run through December, will remove almost a third of what remained in the SPR when the program started, and leave us with what would be less than a 20 day supply of oil at the current consumption rate...

Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 6,168,000 barrels per day last week, which was 4.1% less than the 6,432,000 barrel per day average that we were importing over the same four-week period last year. This week’s crude oil production was reported to be 100,000 barrels per day higher at 12,200,000 barrels per day even though the EIA's rounded estimate of the output from wells in the lower 48 states was unchanged at 11,700,000 barrels per day because Alaska’s oil production was 6,000 barrels per day lower at 450,000 barrels per day and added 100,000 barrels per day to the rounded national total. US crude oil production had reached a pre-pandemic high of 13,100,000 barrels per day during the week ending March 13th 2020, so this week’s reported oil production figure was still 6.8% below that of our pre-pandemic production peak, but was 25.7% above the pandemic low of 9,700,000 barrels per day that US oil production had fallen to during the third week of February of 2021...

US oil refineries were operating at 95.5% of their capacity while using those 16,585,000 barrels of crude per day during the week ending December 2nd, up from their 95.2% utilization rate during the prior week, and the highest utilization rate since August 2nd 2019....The 16,585,000 barrels per day of oil that were refined this week were 5.1% more than the 15,785,000 barrels of crude that were being processed daily during week ending December 3rd of 2021, and nearly matched the 16,597,000 barrels that were being refined during the prepandemic week ending December 6th, 2019, when our refinery utilization was at 90.6%, within the normal utilization range for early December ...

With the decrease in the amount of oil being refined this week, gasoline output from our refineries was also lower, decreasing by 295,000 barrels per day to 9,065,000 barrels per day during the week ending December 2nd, after our gasoline output had increased by 196,000 barrels per day during the prior week. This week’s gasoline production was also 5.2% less than the 9,563,000 barrels of gasoline that were being produced daily over the same week of last year, and 7.1% below the gasoline production of 9,753,000 barrels per day during the prepandemic week ending December 6th, 2019. At the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 21,000 barrels per day to 5,332,000 barrels per day, after our distillates output had increased by 200,000 barrels per day during the prior week. And with those increases, our distillates output was 9.0% more than the 4,872,000 barrels of distillates that were being produced daily during the week ending December 3rd of 2021, and 0.9% more than the 5,263,000 barrels of distillates that were being produced daily during the week ending December th 2019...

Even with the decrease in our gasoline production, our supplies of gasoline in storage at the end of the week rose for the 7th time in 17 weeks, and by the most since July 8th, increasing by 5,319,000 barrels to 213,768,000 barrels during the week ending December 2nd, after our gasoline inventories had increased by 2,770,000 barrels during the prior week. Our gasoline supplies rose by more this week even as the amount of gasoline supplied to US users rose by 41,000 barrels per day to 8,358,000 barrels per day, in part because our exports of gasoline fell by 116,000 barrels per day to 1,012,000 barrels per day while our imports of gasoline fell by 16,000 barrels per day to 519,000 barrels per day. But after 31 gasoline inventory drawdowns over the past 44 weeks, our gasoline supplies were still 0.1% lower than last December 3rd's gasoline inventories of 219,304,000 barrels, and about 3% below the five year average of our gasoline supplies for this time of the year…

With the elevated level of our distillates production, our supplies of distillate fuels increased for the 13th time in 18 weeks, and by the most since May 29th, 2020, rising by 6,159,000 barrels to 118,807,000 barrels during the week ending December 2nd, after our distillates supplies had increased by 3,547,000 barrels during 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, decreased by 106,000 barrels per day to 3,550,000 barrels per day, and because our imports of distillates rose by 220,000 barrels per day to 372,000 barrels per day, and because our exports of distillates fell by 26,000 barrels per day to 1,274,000 barrels per day... But after fifty-two inventory withdrawals over the past eighty-four weeks, our distillate supplies at the end of the week were were still 6.2% below the 126,610,000 barrels of distillates that we had in storage on December 3rd of 2021, and about 9% below the five year average of distillates inventories for this time of the year...

Meanwhile, even after the big decrease in our oil exports, our commercial supplies of crude oil in storage fell for the 13th time in 21 weeks and for the 32nd time in the past year, decreasing by 5,194,000 barrels over the week, from 419,084,000 barrels on November 25th to 413,898,000 barrels on December 2nd, after our commercial crude supplies had decreased by 12,581,000 barrels over the prior week. After this week's decrease, our commercial crude oil inventories fell to around 9% below the most recent five-year average of crude oil supplies for this time of year, but were still almost 23% more than the average of our crude oil stocks as of the first weekend of December over the 5 years at the beginning of the past decade, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels. And after our commercial crude oil inventories had jumped to record highs during the Covid lockdowns of the Spring of 2020, and then jumped again after February 2021's winter storm Uri froze off US Gulf Coast refining, our commercial crude supplies as of this December 2nd were 4.4% less than the 432,870,000 barrels of oil we had in commercial storage on December 3rd of 2021, and 17.8% less than the 503,231,000 barrels of oil that we had in storage on December 4th of 2020, and 7.6% less than the 447,918,000 barrels of oil we had in commercial storage on December 6th of 2019…

Finally, with our inventories of crude oil and our supplies of all products made from oil near multi-year lows over the most recent months, we are also continuing to watch the total of all U.S. Stocks of Crude Oil and Petroleum Products, including those in the SPR....after the big gasoline and distillates inventory increases we've already noted for this week, the total of our oil and oil product inventories, including those in the Strategic Petroleum Reserve and those held by the oil industry, and thus including everything from gasoline and jet fuel to propane/propylene and residual fuel oil, rose by 3,776,000 barrels this week, from 1,600,432,000 barrels on November 25th to 1,604,208,000 barrels on December 2nd, after our total inventories had decreased by 10,173,000 barrels during the prior week. This week's increase still left our total petroleum liquids inventories down by 184,225,000 barrels over the first 48 weeks of this year, and less than 0.3% from a new 18 year low...

This Week's Rig Count

The number of drilling rigs active in the US decreased for the 8th time in the past 19 weeks during the week ending December 9th, but even after 92 weekly increases over the past 115 weeks, active rigs are still 1.6% below the prepandemic rig count....Baker Hughes reported that the total count of rotary rigs drilling in the US decreased by 4 rigs to 780 rigs over the past week, which was still 205 more rigs than the 576 rigs that were in use as of the December 10th report of 2021, but was 1,149 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, a week before OPEC began to flood the global market with oil in an attempt to put US shale out of business….

The number of rigs drilling for oil decreased by 2 to 625 oil rigs during the past week, after the number of rigs targeting oil had been unchanged during the prior week, but there are still 154 more oil rigs active now than were running a year ago, even as they amount to just 38.9% of the shale era high of 1609 rigs that were drilling for oil on October 10th, 2014, and as they are still down 8.5% from the prepandemic oil rig count….at the same time, the number of drilling rigs targeting natural gas bearing formations decreased by 2 to 153 natural gas rigs, which was still up by 48 natural gas rigs from the 105 natural gas rigs that were drilling during the same week a year ago, even as they were only 9.5% of the modern high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008….

Other than those rigs targeting oil and natural gas, Baker Hughes also reports that two "miscellaneous" rigs continued drilling this week: one of those was a directional rig drilling to between 5,000 and 10,000 feet on the big island of Hawaii, while the other was a directional rig drilling to between 5,000 and 10,000 feet into a formation in Lake county California that Baker Hughes doesn't track....While we haven't seen any details on either of those wells, in the past we've identified various "miscellaneous" rig activity as being for exploration, for carbon dioxide storage, and for utility scale geothermal projects...a year ago, there were were no such "miscellaneous" rigs running...

The offshore rig count in the Gulf of Mexico was up by 1 to 18 rigs this week, with 16 Gulf rigs drilling in Louisiana's offshore waters, and two rigs drilling for oil offshore from Texas....the Gulf rig count is now up by 4 from the 14 Gulf rigs running a year ago, when 12 of the Gulf rigs were drilling for oil offshore from Louisiana and two were deployed for oil offshore from Texas...the directional rig that had been drilling to between 5,000 and 10,000 feet for natural gas in the Cook Inlet of Alaska was shut down this week, at least for the winter, so the national offshore rig count remained at 18..

In addition to rigs running offshore, there are now two water based rigs drilling through inland bodies of water this week; those include a directional rig drilling for oil at a depth greater than 15,000 feet in Terrebonne Parish, Louisiana; and a directional rig drilling for oil to between 5,000 and 10,000 feet, inland in Lafourche Parish, Louisiana; the directional rig drilling for oil on water inland in St Mary Parish, Louisiana was shut down this week....a year ago, there were two such rigs drilling on inland waters...

The count of active horizontal drilling rigs was down by 3 to 708 horizontal rigs this week, which was still 187 more rigs than the 521 horizontal rigs that were in use in the US on December 10th of last year, but just over half of the record 1,374 horizontal rigs that were drilling on November 21st of 2014....in addition, the directional rig count was down by two to 46 directional rigs this week, while those were still up by 15 from the 31 directional rigs that were operating during the same week a year ago…on the other hand, the vertical rig count was up by 1 to 26 vertical rigs this week, which was also up by two from the 24 vertical rigs that were in use on December 10th of 2021….

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 December 9th, the second column shows the change in the number of working rigs between last week’s count (December 2nd) and this week’s (December 9th) count, the third column shows last week’s December 2nd active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running on the Friday before the same weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 10th of December , 2021...

checking the Rigs by State file at Baker Hughes for the changes in the Texas Permian, we find that there was one rig pulled out of Texas Oil District 8, which overlies the core Permian Delaware, while rig counts in other districts in the Texas Permian were unchanged...since the national Permian basin count was unchanged, we can thus conclude that at least one of the rigs added in New Mexico was set up to drill in the far western Permian Delaware, in the southwest corner of that state, while it's possible another could have been, were there offsetting changes in one of the other Texas Permian districts that don't show up in the totals...elsewhere in Texas, there was a rig added in Texas Oil District 1, which would account for the Eagle Ford increase, while there were two rigs pulled out of Texas Oil District 3, apparently from a basin that Baker Hughes doesn't track.... there was also a rig added in Texas Oil District 10, which would account for one of the Granite Wash rig additions, with the other being in Oklahoma....the rig addition in the Barnett shale, underlying Dallas Ft Worth, does not show up in a corresponding district total, so we assume it was offset by a rig removal nearby from a basin that Baker Hughes doesn't track...

elsewhere in Oklahoma, rig were removed from the Cana Woodford, from the Ardmore Woodford, and from the Mississippian shale....rigs removed from Alaska include the directional rig that had been drilling for natural gas in the Cook Inlet, and an oil rig that had been drilling on the North Slope...meanwhile, the rig pulled out of Wyoming had been drilling in a basin not tracked by Baker Hughes....unfortunately, we can't report more detail on any of those rigs, and especially which of them had been drilling for natural gas, because the Baker Hughes file that should link to this week's data only provides us with a duplicate copy of this week's Pivot Table....

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Ohio lawmakers may require fracking under state land - Last-minute changes to a poultry bill would label natural gas as "green" energy and require fracking under state-owned land and parks in Ohio. Opponents of House Bill 507 say the new language would force Ohio to lease state parks and public lands for oil and gas drilling called fracking. The Ohio Environmental Council says this could extend to state universities and colleges as well.Proponents of the changes say the state could still reject unworthy projects."There’s nothing in this amendment that would force the state to accept a lease that isn’t appropriate or fair for the state of Ohio," said Rob Brundrett, president of the Ohio Oil and Gas Association.Ohio has allowed fracking under state land for over a decade Ohio lawmakers approved fracking under state land in 2011, but the Oil and Gas Land Management Commission has been slow to approve any projects. Former Gov. John Kasich signed that bill into law but didn't appoint anyone to the commission for years. Under Gov. Mike DeWine, the commission has met more frequently but has not approved leases."This has been on the books for over a decade," Brundrett said. "We’re just trying to make it more efficient for everyone involved.”The new language says Ohio "shall," rather than "may," lease state land for oil and gas drilling. The change would take effect when the bill is enacted and last until the commission creates its own rules on leasing this land. Sen. Tim Schaffer, R-Lancaster, said "shall kind of lights a fire, if you will." But Senate Minority Leader Kenny Yuko, D-Richmond Heights, said the change "cuts out the public and the important process of deciding if and how drilling occurs in our state parks." He called the "dangerous" policy an "end run" on leasing state lands.. State nature preserves are exempt from drilling under the 2011 law. Another change would label natural gas as "green energy," a designation that environmentalists scoff at. "It’s effectively PR and an attempt to confuse Ohioans," said Nolan Rutschilling, managing director of energy policy at the Ohio Environmental Council Action Fund, Natural gas emits significantly less carbon dioxide than coal but contributed to 33% of the United States' methane emissions in 2020 and 4% of U.S. greenhouse gas emissions, according to U.S. Environmental Protection Agency estimates. Schaffer said natural gas is "an extremely clean source of energy" and a major resource in Ohio. In July, European Union lawmakers designated natural gas and nuclear power as "green" or "sustainable" energy. Schaffer said it was important to follow suit. But Rutschilling said the European Union's decision was limited and temporary. He worries that the Ohio change would greenlight natural gas for investments meant for wind, solar and other renewable energy sources in the future. The bill itself would not allow most natural gas to qualify for renewable energy credits. Another last-minute addition would prohibit municipalities from banning pesticides registered with the Ohio Department of Agriculture. The underlying House Bill 507 had nothing to do with natural gas. It would decrease the number of poultry chicks that may be sold or given away from six to three.

Ohio Senate to vote on expanding gas drilling on state lands - – With little public notice, the Ohio Senate could vote Wednesday on legislation to expand natural gas drilling in state parks. The bill also would change the legal definition of “green energy” – a term typically referring to power derived from sun, wind, or water – to include natural gas. Natural gas is mostly methane, a powerful heat-trapping greenhouse gas that’s formed over millions of years underground and freed via drilling into the earth. Additionally, the amended legislation would prohibit municipalities from banning the use of certain pesticides within their borders. All these changes were made late Tuesday afternoon to House Bill 507 – legislation that until that time only addressed laws around poultry sales and food safety. At the time of the vote, text of the amendments was not available online. The amendments and legislation passed the Senate Agriculture and Natural Resources committee 5-1, with Republicans in support and the committee’s lone attending Democrat in opposition. The legislation could be put to a Senate vote as soon as Wednesday, pending the discretion of Senate leadership. The House could accept the Senate’s changes and send the bill to the governor or send the matter to a conference committee to hash out the differences. Since 2011, state law has granted agencies the ability, if they choose, to lease out their land for oil and gas production and exploration. The amendment adopted Tuesday would require state agencies to lease their lands to applicants seeking to drill, instead of just allowing them to. The proposal “forces state agencies to lease state parks and public lands for fracking and oil and gas development when the industry says so,” according to an analysis from the Ohio Environmental Council. Industry requests to drill for oil and gas on public lands can “drag on for years and years,” Sen. Tim Schaffer, a Lancaster Republican, said at a hearing Tuesday. His comments amounted to some of the only substantive remarks about the six amendments adopted. Beyond just natural gas, the amended legal definition of “green energy” under the bill would include any energy resource that is “more sustainable and reliable relative to some fossil fuels” – a broad definition that could conceivably include coal, a major climate change driver and among the dirtiest of fuel sources. No analysis from the Legislative Service Commission was available as of Tuesday evening. The effects of including natural gas within the legal definition of “green energy” are subtle, according to the OEC Action Fund’s Nolan Rutschilling. It could set a worrisome precedent for state utility regulators, he said, or could just be a push to rebrand a product associated with human-caused climate change. “It sets a precedent we don’t like. It’s largely a public relations move,” he said. “And it’s just scientifically incorrect.” The amendment states that besides for gas “produced from biologically derived methane,” that energy generated by using natural gas is not eligible for a renewable energy tax credit. Sen. Mark Romanchuk, an Ontario Republican, proposed the green energy amendment, an aide confirmed. Romanchuk declined to explain his thinking in an interview. Senators adopted three other amendments into HB 507, ranging in subject matter from disposal of abandoned vehicles, auctioneer licensure requirements, and food safety laws.

Reopening of Valley injection well under deep scrutiny - Youngstown Vindicator — AWMS Water Solutions of Howland, the company that owns two oil and gas wastewater injection wells along state Route 169 in Weathersfield Township just north of Niles, says the outcome of its case being heard by the Ohio Oil and Gas Commission will set precedent in Ohio for regulations governing seismic activity associated with injection wells.Seismic activity refers to earthquakes produced by injection wells, which inject the wastewater from the oil and gas industry deep underground as a means of disposal. The Ohio Oil and Gas Commission is reviewing the parameters set by the Ohio Department of Natural Resources under which the injection well will operate when it reopens.On May 21, 2021, Eric Vendel, chief of the ODNR Division of Oil and Gas Resources, issued orders stating after the AWMS well reopens, it must shut down again if an earthquake of a magnitude 2.1 or greater occurs within a 3-mile radius of the facility, as occurred in 2014 not long after it first opened.“AWMS also shall depressurize and not resume operations until a full evaluation of the data from the seismic event is performed by AWMS,” the orders state. The orders indicate they can be appealed to the Ohio Oil and Gas Commission — which AWMS did.The company’s appeal focuses on the requirement that the well close again if an earthquake of magnitude 2.1 or larger occurs, which AWMS found to be too restrictive.An appeal hearing took place in Columbus in February, and the company and ODNR filed followup briefs in March in which they again debated the parameters under which the well would reopen.The Ohio Oil and Gas Commission continues to review the issues but has not issued a ruling. AWMS Water Solutions, LLC. Is a wholly owned subsidiary of Avalon Holdings Corp. of One American Way in Howland.

New Research Dives into Fracking’s Impact on Water Flow in Ohio - Cleveland Scene - It found reductions that were severe and had the potential to negatively impact ecosystems.New Research Dives into Fracking’s Impact on Water Flow in Ohio - Cleveland Scene - It found reductions that were severe and had the potential to negatively impact ecosystems. Fracking is a very water-intensive industry, and a new study dives into the impact of unconventional oil and gas drilling on aquatic ecosystems in the Ohio River Basin. Ponds, streams and reservoirs typically supply the water for hydraulic fracturing, which is used to create fissures in rock from which oil and gas are extracted. Ohio Northern University Associate Professor of Chemistry Christopher Spiese said examining water-flow reductions is important as it results in reduced depths and the total volume of the water source. "You're restricting the habitat that fish and invertebrates have to feed and spawn," said Spiese. "Water can actually get warmer, which can then lead to reduced survival rates for these critters. It enables invasive species to have an opening to start to impinge on the rivers and native species retreat." Spiese and other researchers at Ohio Northern developed a model for estimating river flow and compared the data to water usage from the industry. He explained that while they didn't see dramatic reductions in stream flow, the reductions that were discovered were severe and had the potential to negatively impact ecosystems. The research calls for more accurate data collection and reporting for fracking water use. Spiese said in their work with groups such as the Freshwater Accountability Project and FracTracker, they've found discrepancies between water withdrawals and water-usage reporting. He added that there are policy implications that should be considered. "We'd ultimately like to see an assessment of risk-benefit analysis kind of stuff," said Spiese. "What is this actually costing Southeast Ohio in terms of ecosystems, environmental health, human health, versus how much is it actually bringing in for economic benefits? And I don't know which way that scale is going to tip." According to the report, water withdrawal in Ohio below 100,000 gallons per day does not require a permit. With those below that threshold unregulated, Spiese said there are unknowns about the quantity of water withdrawn from individual watersheds.

Ohio family continues to fight pipeline construction on their farmland - — A Union County farm family is continuing to oppose construction of a natural gas pipeline across their preserved farmland in a case before Ohio’s Third District Court of Appeals. Meanwhile, administrative changes at the Ohio Department of Agriculture, as well as proposed changes to Ohio’s eminent domain laws, could affect similar cases in the future. On Nov. 22, the Third District Court of Appeals heard oral arguments for two linked cases, Columbia Gas of Ohio, Inc. v. Patrick E. Bailey, et al. and Columbia Gas of Ohio, Inc. v. Don Bailey Jr., et al. These cases appeal a Union County Common Pleas Court ruling in April that dismissed Columbia Gas’s request to use eminent domain for pipeline construction. The lower court dismissed Columbia Gas’s eminent domain petition citing inconsistencies in the language used in documents provided to the court and those reviewed by the Ohio Power Siting Board. A 25-foot easement labeled “temporary” before the siting board was listed as “perpetual” in the eminent domain request to the court. In the appeal before the district court, the Bailey family is asking the court to uphold the lower court’s dismissal of the eminent domain request, based on the inconsistent perpetual/temporary easement descriptions.The appeals court has already ruled on a case involving a neighboring farm, Columbia Gas of Ohio, Inc. v. Phelps Preferred Investments, LLC. The Phelps case involved the same inconsistent easement descriptions. In July, the appeals court upheld the lower court’s dismissal of the eminent domain request.The Phelps case is different from the Baileys’, however, because the Phelps farmland is not protected by an ag easement. The Baileys want the appeals court to go a step further in their cases to consider the ag easement and deny the eminent domain request because the ag easement establishes a “prior public use.”

Is EOG's Latest Discovery a Premium Play? - In its latest earnings report, EOG Resources highlighted its well results in the volatile oil window of the Utica shale, touting the region’s contribution to its premium inventory. EOG stated it expects “the Utica Combo to be its next large-scale premium resource play” and that it believes it can be developed using three-mile laterals. Historically, this area has seen limited production activity due to the comparably worse well performance against the Utica wet and dry gas windows. However, the historical underdevelopment of the volatile oil window and the black oil window means there is an abundance of potential locations that could add to Appalachia inventory estimates. In this Energy Market Insight, we’ll take a look into EOG’s claims and analyze their potential impacts on Utica production and activity going forward. Ohio’s state data shows EOG completed one well in 2021, Rose 0801, located in Carroll County. In 2022, EOG drilled four additional wells located in Carroll, Noble, and Stark counties. In its latest earnings report, EOG stated it plans to drill 20 wells in the area through 2023, signaling its commitment to developing the area further. With the preliminary data suggesting impressive results for the underdeveloped window, the magnitude of potential development comes into question. BTU’s current inventory estimates extend into the wet gas window but are very limited in the volatile oil window, as there are few existing wells to build inventory around. Furthermore, current inventory estimates show breakevens increase as locations move from the dry gas to the black oil window, with volatile oil window locations being greater than $4/MMBtu, which has been prohibitive to development. If EOG could replicate the results of its Rose 0801 well across all of its acreage using three-mile laterals, BTU estimates it would add 1,509 Utica shale locations. If other acreage owners could replicate the results across the entire window, there could be over 3,200 additional locations. If the region saw producer activity equal to the dry and wet gas windows at ~15 wells per month, the volatile oil window could add more than 15 years of inventory to the area. However, the greatest hindrance to this rapid development in the region is the additional infrastructure buildout that would be required to support any significant growth, as most existing infrastructure is centered around the wet gas window.

New Study Shows Ohio's Plastic Industry Surpassing China's Thanks to Natural Gas - Ohio’s plastic manufacturing industry is beating out China’s, thanks to its abundant natural resources that provide manufacturing and economic advantages, according to a new Shale Crescent USA study by JobsOhio. The study debunks the long-held belief that importing plastic-based manufactured goods is more affordable, when in fact, increasing domestic production and making critical materials like plastics in Ohio has distinct advantages. In a release, JobsOhio noted: “However, since the COVID-19 pandemic spotlighted the financial and logistics benefits of shorter supply chains, Ohio has surpassed China as the world’s low-cost center for plastics manufacturing, thanks to advantages in cost, economic climate, and market access.” Ohio has long had a competitive standing when it comes to U.S. plastics manufacturing. In fact, this year, the Plastics Industry Association ranked Ohio as the No.1 state in the nation for plastics employment in its 2022 Size and Impact Report. Ohio’s energy and transportation advantages are just some of the emerging key differentiators in manufacturing when compared to China. The onshoring of U.S. manufacturing is directly correlated to manufacturers reaping the benefits of domestic production, and is good news for workers throughout the country and the Buckeye State. Ohio is a prime example of this: the state’s advanced infrastructure, highly-skilled workforce, and central location make it an ideal manufacturing hub. And importantly, Ohio and neighboring Pennsylvania and West Virginia have an abundance of natural resources to fuel manufacturing plants and provide ancillary benefits and market opportunities – and move industry away from China.

Edwards Testifies on Bill to Add Incentives for Natural Gas Pipelines - Athens Messenger -- State Representative Jay Edwards (R-Nelsonville) Tuesday provided sponsor on legislation that would create areas within which tax and other incentives would be available to promote the development of natural gas infrastructure projects. These incentives are available in locally designated areas, called EnergizeOhio zones, and can include loan programs, cost recovery provisions, and a personal property tax reduction. EnergizeOhio zones are petitioned to the Department of Development and must be developing natural gas pipelines and the associated infrastructure.“House Bill 685 gives us the upper hand in the development of these pipelines,” Edwards said. “These incentives will promote the quick expansion of our pipeline system and keep Ohio’s energy moving.” EnergizeOhio zone designations last five years and can be renewed for an additional five years if they meet certain requirements. H.B. 685 now awaits its second hearing in the House Energy and Natural Resources Committee.

Revealed: Nearly 100 potential PFAS-polluted sites in Pennsylvania, Ohio and West Virginia from fracking waste - -— Waste from fracking wells that used PFAS – commonly known as “forever chemicals”– has been dumped at dozens of sites across Pennsylvania, Ohio and West Virginia — all of which could face contamination of soil, groundwater and drinking water as a result.PFAS (per- and polyfluoroalkyl substances) have been used in hydraulic fracturing and other types of oil and gas wells across the U.S. for at least a decade.Exposure to the chemicals, which are also used to make various consumer products nonstick and waterproof, is linked to health problems including kidney and testicular cancer, liver and thyroid problems, reproductive problems, lowered vaccine efficacy in children and increased risk of birth defects, among others.Regulatory loopholes and a lack of transparency make it impossible to know how extensively the chemicals have been used in oil and gas production. In August, however, Environmental Health News (EHN), documented the first case of private drinking water contaminated with PFAS potentially linked to fracking wells, and in October EHN mapped the eight locations where operators have publicly disclosed the kind of PFAS they used in Pennsylvania fracking wells.Now, a new map developed for EHN by FracTracker using public data reveals that waste generated at the eight Pennsylvania fracking wells with documented PFAS use has traveled to at least 97 additional sites for reuse and disposal. Those eight wells generated more than 23 million gallons of liquid waste and 30,390 tons of solid waste between 2012 and 2022 so far. “It’s unique that we’re able to trace this in Pennsylvania,” Matt Kelso, a manager of data & technology at FracTracker, who developed the map, told EHN. “Other states may tell you a little about the waste generated at well pads, but most don’t publicly report where it goes.”

Pennsylvania Natural Gas Production Continues to Dip, 4Q Drilling Below Last Year's Pace -- Pennsylvania natural gas production from horizontal wells totaled 1.88 Tcf or 20.6 Bcf/d in the third quarter, down 0.8% from the third quarter of 2021, according to data from the state’s Department of Environmental Protection (DEP). This marks the third straight quarter in which output did not rise on a year/year (y/y) basis, DEP said, and the strongest y/y decline in quarterly production since the publishing of monthly data began in 2015. The number of new horizontal wells spud, however, totaled 158, a 47-well increase from 3Q2021. “This uptick in drilling was likely in response to the dramatic increase in prices in late summer,” DEP researchers said. “Preliminary data for the fourth quarter show that the number of wells spud in October and November is down 13.6% from the same period in 2021.” The statewide number of producing wells stood at 11,119 wells for 3Q2022, up 4.1% from the year-ago period. “Horizontal producing wells, which account for over 99% of production, increased by 4.4%,” researchers said.They added, “Growth in producing wells fell to its lowest rate since data have been published…Decelerating or flat growth in producing wells is due to less drilling activity in 2020 and 2021 and older wells that were shut in or plugged. The uptick in drilling in 2022 should lead to stronger growth in producing wells.”Researchers highlighted a “dramatic” increase in U.S. and Pennsylvania natural gas prices in 3Q2022 versus the same period last year.. “Current forecasts project that prices will remain elevated in the short term due to global supply and demand pressures.” The Energy Information Administration (EIA) confirmed as much in its latest Short-Term Energy Outlook published on Tuesday. EIA is expecting Henry Hub spot prices to average $6/MMBtu in 1Q2023, up from a November average of around $5.50. EIA also raised its full-year 2023 production forecast to 100.4 Bcf/d from a month-earlier projection of 99.7 Bcf/d. Over the longer term, Pennsylvania and the Appalachian Basin in general is to be a vital supply source to the U.S. and global markets, according to TC Energy Corp.’s Stanley Chapman III, vice president of U.S. and Mexico natural gas pipelines.Susquehanna County accounted for 20.9% of Pennsylvania’s gas output during the first three quarters, followed by Washington (18.1%), Bradford (15.2%), Greene (14.6%) and Lycoming (5.8%) counties. Pennsylvania’s natural gas production totaled 5,637 Bcf through September, second only to Texas at 8,371 Bcf. Louisiana, Alaska and West Virginia ranked third, fourth and fifth, respectively, at 2,946 Bcf, 2,645 Bcf and 2,158 Bcf. “These data show that after relatively strong production growth compared to other major producing states in [2021], Pennsylvania is the only major producing state to record negative annual growth through September 2022,” DEP researchers said.

Republicans push to ease gas pipeline regulations; some Democrats refuse to let bill through - — Rep. Mike Kelly (R-Penn.) says gas pipeline regulations are overly burdensome and get in the way of domestic energy production. “If we have it domestically, if we’re blessed in a way that very few places in the world are, why not access what we have and create jobs,” Kelly said. He’s introduced a bill to streamline the permitting process and build more infrastructure for gas pipelines across the country, as well as approve the Mountain Valley Pipeline completion. “I never quite understood this idea that sometimes you have to cut down what you’re able to do,” Kelly said. Kelly says approving the bill eases regulations so pipelines can transport gas from Pennsylvania to the Northeast, and would lower energy costs for families and businesses. “For the American citizen, they don’t know how hard their own government makes it on them to access energy,” Kelly said. The bill was also introduced in the Senate, where some Democrats say it’s unnecessary. “I certainly don’t support that legislation,” Sen. Kirsten Gillibrand (D-N.Y.) said. Gillibrand is pushing against the bill and says lawmakers need to focus on transitioning away from gas energy. “We need much more investment in clean energy and the infrastructure to support clean energy.” With a packed legislative schedule, the bill may not advance this year, but Kelly promises to bring it back to the floor when he returns for the next Congress.

New developments arise from both sides of pipeline debate - - There were new developments last week in the debate involving the Mountain Valley Pipeline. One involved legislation that could clear the path for the project. The other was a call from opponents to provide a more thorough review. The legislation was announced Thursday by Pennsylvania Sen. Pat Toomey (R-Pennsylvania). It’s similar to the proposal US Sen. Joe Manchin (D-West Virginia) offered in September, that would streamline permitting for fossil fuel projects and clear the way for completion of the Mountain Valley Pipeline. Sen. Toomey and a Pennsylvania Republican in the House of Representatives introduced companion bills. By approving the legislation, Toomey said in a news release, Congress would “create regulatory certainty for pipeline construction nationwide and greenlight the long-delayed Mountain Valley Pipeline.” Mountain Valley Pipeline opponents said they weren’t surprised to see the proposal resurface, but said lawmakers should reject it again. Roberta Bondurant and Grace Terry are members of the group Preserve Bent Mountain. ‘Legislators have an obligation to protect the public,” Bondurant told WDBJ7. “And in advancing MVP, they are failing to do that. In fact they are working against public safety.” “And think about it,” Terry added, “if it were a good project, it wouldn’t have run into the trouble that it’s had.” This week, more than 40 environmental and advocacy groups called for a “fair and open” review of the pipeline’s plan to cross the Jefferson National Forest. They said the process should include public comment before the U.S. Forest Service and the Bureau of Land Management issue a draft report. David Sligh is the Conservation Director of the group Wild Virginia.. “As citizens, members of the public have the right to have a say, to have a fair say, in how their public resources are going to be managed,” Sligh said Friday afternoon. “And so it’s a practical thing to get the best information, and it’s a fairness thing to make sure that folks who are going to be most affected have the best chance to weigh in.”

Democrats try to salvage Manchin’s deal on energy permitting reform - The push by Sen. Joe Manchin III to overhaul the nation’s permitting process for infrastructure projects could get some last-ditch help from Democratic leaders, who are trying to attach the permitting bill to the annual defense policy measure, according to two people familiar with the matter. With the blessing of Senate Majority Leader Charles E. Schumer (D-N.Y.), House Speaker Nancy Pelosi (D-Calif.) has been in talks with House Armed Services Committee Chairman Adam Smith (D-Wash.) about attaching a version of Manchin’s permitting bill to the National Defense Authorization Act (NDAA), according to the two individuals, who spoke on the condition of anonymity to describe private conversations.New text of the defense bill that includes the permitting bill could be released Monday before the House Rules Committee considers the measure, the people said, although they cautioned that the plans were in flux and subject to change.Spokespeople for Manchin (D-W.Va.), Pelosi and Schumer did not immediately respond to requests for comment.The effort to salvage Manchin’s permitting crusade is the latest attempt by Democrats to honor a deal that secured his vote for the Inflation Reduction Act, a sweeping climate, energy and health-care law that President Biden signed in August. Manchin insisted on a follow-up permitting bill as part of the deal, part of his long quest to speed up America’s permitting process for energy infrastructure, including the contested Mountain Valley Pipeline, which would transport natural gas about 300 miles from his home state of West Virginia to Virginia.

Top Dems weigh adding permitting reform to defense bill - Democratic leaders are trying to slip controversial permitting provisions developed by Sen. Joe Manchin into the latest version of the fiscal 2023 defense authorization bill, according to three people familiar with the matter. The sources, who were granted anonymity to speak candidly about the matter, said lawmakers were maneuvering over the weekend to get the provisions included in the final version of the annual National Defense Authorization Act. It would be a last-second win for Manchin, who was promised a vote on his permitting overhaul in exchange for his support for the Inflation Reduction Act in August. The defense legislation is a must-pass bill and one of the last possible legislative vehicles for Democrats to get permitting reform done before they lose control of the House in January. “This is a politically astute move by Democrats to force Republicans to fight the mere mention of reform at the cost of an NDAA, which they have championed for years,” said Alex Herrgott, a former Republican staffer who started the Permitting Institute. Spokespeople for House Speaker Nancy Pelosi (D-Calif.), Senate Majority Leader Chuck Schumer (D-N.Y.) and Manchin did not respond to requests for comment. The House Rules Committee is set to meet this afternoon to prepare the NDAA for a vote, and the latest iteration could reach the floor in the coming days. Negotiators are scrambling to get the military authorization bill to the president’s desk before the end of the year. Manchin has for weeks been pushing to tack permitting onto the defense bill. But NDAA negotiators have resisted including the controversial provisions to ensure quick passage for the defense funding bill. House Armed Services leader Adam Smith (D-Wash.) has nonetheless acknowledged that the decision would come down to Democratic leadership (E&E Daily, Nov. 16). Timeline uncertain Manchin sparked the political fight over permitting this summer, when he floated a draft bill that would have approved his cherished Mountain Valley pipeline and created a White House priority list of projects.. The permitting provisions lawmakers want to add to the NDAA are expected to build on the Manchin draft.

Lawmakers await revamped permitting bill - Lawmakers are bracing for a revamped version of Sen. Joe Manchin’s permitting overhaul while congressional leaders continue to negotiate a deal with the West Virginia Democrat. Manchin confirmed Monday that he has been working on changes to the draft permitting reform legislation he first circulated in September. Democratic leaders are hoping to attach the new language to the fiscal 2023 National Defense Authorization Act to honor a deal they struck with Manchin in August in exchange for his vote on the Inflation Reduction Act. “There’s been a lot of input from both sides,” Manchin told reporters, adding that there have been “some adjustments” to the draft legislation. “It’s pretty much up in the air. We’ll see what happens.” A deal to overhaul the nation’s permitting laws could give Manchin a win on Mountain Valley pipeline, a long-sought project for West Virginia lawmakers, but it threatens to enrage progressives and derail President Joe Biden’s environmental justice pledges. The White House on Monday threw its support behind the effort. Press secretary Karine Jean-Pierre said that Biden was in favor of tacking Manchin’s permitting reform legislation onto the NDAA, honoring the agreement that got the administration’s marquee legislative achievement across the finish line. It’s not clear exactly how Manchin’s language might change from the September draft. In addition to authorizing Mountain Valley — a politically contentious project — Manchin’s proposal is expected to cut down permitting requirements for energy projects across the board. Senate Armed Services Chair Jack Reed (D-R.I.) said it would be up to leadership to determine the “last-minute items that pop up every year.” Senate Environment and Public Works Chair Tom Carper (D-Del.) told reporters Monday, “Our Republican colleagues would like to include some provisions in permitting reform that I’ve not been comfortable at all in accepting, and there’s been an ongoing discussion. It’s now above my pay grade, so we’ll see where a conversation, negotiation between the administration, our leader’s office, the Manchin office, where it leads.” It’s not clear at this point whether Senate Majority Leader Chuck Schumer (D-N.Y.) and House Speaker Nancy Pelosi (D-Calif.) would be able to rally the votes for a defense bill that includes permitting reform. The situation has already set off a firestorm among congressional progressives and environmental justice advocates after Democratic leaders began maneuvering over the weekend to include permitting in the NDAA. Final text of the defense bill is expected out as soon as Tuesday. Manchin’s bill has also engendered fierce opposition from Virginia lawmakers who oppose Mountain Valley, which would carry natural gas between West Virginia and the Old Dominion (E&E Daily, Sept. 16). “I was OK with the first 85 pages, but I’m completely opposed to taking the Mountain Valley pipeline outside of normal permitting rules and just greenlighting it and eliminating all the judicial review processes,” Sen. Tim Kaine (D-Va.) said Monday of Manchin’s original draft permitting proposal.

Pelosi pitches Dems on permitting as progressives rage - House Speaker Nancy Pelosi pitched Democrats on Sen. Joe Manchin’s permitting overhaul during a caucus meeting Tuesday morning, according to lawmakers who were in the room. It’s a sign of leadership’s continued insistence on including the issue in the annual National Defense Authorization Act, as negotiators wade through riders to the must-pass bill they hope to vote on this week. The deal between Manchin, a West Virginia Democrat, and party leadership to pass the permitting bill by the end of the year has enraged progressives, who oppose expediting environmental reviews for fossil fuel projects. “[Pelosi] acknowledged that this was a contentious issue, a point of disagreement with some of us, and talked about the need for energy transmission in order to quickly realize all the investments in the Inflation Reduction Act,” Rep. Jared Huffman (D-Calif.) told reporters this morning. “Look, nobody wants to see more clean energy than me — I’m a climate hawk — but I also understand there are ways to get that transmission without throwing the [environmental justice] community under the bus,” said Huffman. Pelosi and Senate Majority Leader Chuck Schumer (D-N.Y.) agreed to pass the permitting language, which includes an authorization of the contentious Mountain Valley pipeline, in exchange for Manchin’s vote on the Inflation Reduction Act in August. Progressives got it dropped from a stopgap spending measure in September, and Manchin has said that he tweaked the language since he unveiled a draft bill earlier this fall. House progressives are now threatening to vote against the rule setting up debate on the floor, which could sink the entire defense bill. Environmental justice advocacy groups are embarking on a last-minute lobbying campaign to kill it. They held a protest outside the Cannon House Office Building on Tuesday morning and are planning another event with progressive lawmakers to oppose the bill in the afternoon. The effort is also facing opposition from Republicans, who don’t want non-defense riders tacked onto the NDAA. Many in the GOP also believe Manchin’s proposal does not go far enough to cut down environmental permitting for energy projects.

Progressives push back on permitting in defense bill | The Hill --At least two progressive Democrats on Monday said they would vote against a defense spending bill if it contains elements of Sen. Joe Manchin’s (D-W.Va.) permitting reform push.Reps. Raúl Grijalva (D-Ariz.) and Ro Khanna (D-Calif.) tweeted that they would vote against the annual bill, known as the National Defense Authorization Act (NDAA), if it contained what they described as “giveaways to the fossil fuel industry.“We can advance permitting for clean energy without taking a hatchet to environmental protections for frontline communities. This is not what @RepMcEachin would have wanted,” Grijalva said, invoking the late Rep. Donald McEachin (D-Va.).“I will vote against the NDAA rule if we continue with this fossil fuel giveaway,” he added. Meanwhile, Khanna expressed optimism that the legislation could be stopped.“I will vote against the rule for NDAA consideration if it includes giveaways to the fossil fuel industry. If even 10 House progressives vote against it, it likely can’t pass,” Khanna tweeted. A spokesperson confirmed that the lawmaker was referring to permitting reform in his tweet.

Last year, Grijalva voted for the NDAA while Khanna voted against it.
Permitting reform refers to changes to the energy approval process. Manchin has been pushing for changes that would be expected to speed up approvals for both fossil and renewable energy infrastructure.

Progressives ready to block defense bill over permitting - A top House Democrat will vote to block consideration of a must-pass defense spending bill if it includes permitting language that could undermine environmental protections. The warning shot from Rep. Raúl Grijalva (D-Ariz.), chair of the House Natural Resources Committee, comes as congressional Democratic leaders are seriously weighing inclusion of a permitting provision in the fiscal 2023 National Defense Authorization Act. His threat also illustrates the intensity of the continued left-wing opposition to the provision, which party leaders first sought to tack onto a stopgap spending bill in September at the behest of Grijalva’s counterpart, Senate Energy and Natural Resources Chair Joe Manchin (D-W.Va.). “It’s gotten to the point where it has become craven, where ‘we’re just going to get it done regardless,’” Grijalva told E&E News on Monday of leadership’s insistence on finding a home for Manchin’s overhaul effort. “I understand, and I’ve tried to give to senators the reassurance that the transmission and grid issues — the promotion of renewable and alternative energies — have to be dealt with, but not like this,” he continued. “Taking a hatchet to [the National Environmental Policy Act] is not the way to go.” Grijalva’s plan would be to vote against the “rule” for the bill. That’s a resolution that governs parameters for floor debate. Members of the majority rarely oppose rules for bills backed by party leaders. And if enough Democrats band together to oppose the rule for the NDAA, it could thwart the underlying bill. Grijalva said he wasn’t launching a coordinated effort to sink the rule at this time, but the Arizona Democrat has enormous influence among House progressives and environmentalists, and he led the opposition to the permitting language earlier this year. His plans could compel others to follow suit. Leaders of the Congressional Progressive Caucus are already surveying their members to see if there’s an appetite to vote against the NDAA rule in case permitting reform text is included, a House Democratic aide confirmed to E&E News. At least one progressive House Democrat, Rep. Ro Khanna of California, said Monday he planned to vote against the rule “if it includes giveaways to the fossil fuel industry.” “We all have a stake in tackling the climate crisis & it’s critical we listen to communities hit hardest,” Khanna said on Twitter, adding, “If even 10 House progressives vote against [the rule], it likely can’t pass.” No decisions have been made yet about including permitting language in the NDAA, which could shorten timelines for National Environmental Policy Act reviews, limit the ability for citizens to launch judicial challenges for proposed energy projects and approve the controversial Mountain Valley pipeline — a Manchin priority. But as NDAA negotiations continue, House Democratic chiefs of staff were told Monday during their weekly meeting that their party leadership is “discussing permitting in the context of NDAA,” according to one chief on the call granted anonymity to share details of a private briefing.

Doubts emerge about NDAA as permitting vehicle - Progressive opposition to including Sen. Joe Manchin’s (D-W.Va.) permitting reform deal in a defense spending bill is throwing cold water on the energy policies’ inclusion.

In recent days, several House Democrats have said that they would not only oppose the defense bill itself if Manchin’s provisions are put in; they will also oppose the rule that allows the bill that comes to the floor.
Since Republicans almost never vote for rules put forward by Democrats even if they support the underlying bill, the maneuver may only require a few defectors to succeed.

House Armed Services Chairman Adam Smith (D-Wash.) told The Hill on Tuesday that he doesn’t think the policies, which are aimed at speeding up the approval process for energy projects, have the votes to succeed. “It does not appear to me that there’s the votes to sustain that,” Smith told The Hill. “If it was up to me at this point it would not be in, but it’s not up to me, but it seems to me like there’s not the support for it.” ut, he said it’s up to leadership to decide whether to include them and that a final decision hadn’t yet been made.

Congressional Progressive Caucus Chair Pramila Jayapal (D-Wash.) indicated she believes the progressive effort would be enough to kill the permitting reform’s chances in the NDAA.
“Typically Republicans don’t vote for the rule, some of them might, but I can’t imagine there would be enough to counter the number of progressives that have already told me they’re voting against the rule,” she said. She added the caucus was still taking stock of how large the opposition to the rule could be.

Manchin's last-gasp permitting effort fails - Congressional Democratic leaders fell short in a last-ditch effort to honor a promise to pass Sen. Joe Manchin’s permitting overhaul proposal. The final text of the fiscal 2023 National Defense Authorization Act released Tuesday night did not include language that would have shortened timelines for National Environmental Policy Act reviews and limited citizen judicial challenges for proposed energy projects. It’s a blow for Manchin, a West Virginia Democrat and chair of the Senate Energy and Natural Resources Committee. His proposed reform efforts would have included approval for the Mountain Valley pipeline, a natural gas project in his state. “Our energy infrastructure is under attack and America’s energy security has never been more threatened,” Manchin said in a statement Tuesday night. “Failing to pass bipartisan energy permitting reform that both Republicans and Democrats have called for will have long term consequences for our energy independence. “The American people will pay the steepest price for Washington once again failing to put common sense policy ahead of toxic tribal politics,” he continued. “This is why the American people hate politics in Washington.” Manchin’s failure is a victory for an unlikely coalition of progressives and conservatives, who again came together to fight the permitting plan after successfully blocking it from being attached to the stopgap government spending measure back in September. “Thanks to the hard-fought persistence and vocal opposition of environmental justice communities all across the country, the Dirty Deal has finally been laid to rest,” House Natural Resources Chair Raúl Grijalva (D-Ariz.), who led the opposition both times, said in a statement. “House Democrats can now close out the year having made historic progress on climate change without this ugly asterisk.” House Speaker Nancy Pelosi (D-Calif.) and Senate Majority Leader Chuck Schumer (D-N.Y.), with President Joe Biden’s support, were working furiously behind the scenes this week to make good on their commitment to Manchin that they’d find the votes for his proposal — a trade for his support for the Inflation Reduction Act. Pelosi was pitching her members hard on the plan in a closed-door caucus meeting Tuesday morning, according to lawmakers and aides inside the room, extolling the advantages of legislation that would speed up deployment of new transmission lines. “Schumer makes the argument, with which I agree, that the $369 billion that we put in the [Inflation Reduction Act] for renewables, new innovation, new technology — in order to get that done quickly … having the permitting process run smoothly and not dragging out over a long period of time is very helpful,” House Majority Leader Steny Hoyer (D-Md.) told reporters at his weekly briefing Tuesday afternoon. But Hoyer also acknowledged the language under consideration for inclusion in the NDAA was “very controversial,” and made clear Schumer and Pelosi’s main motivation was in deference to Manchin. “We passed the IRA, the inflation reduction bill — the only reason we passed it is because Joe Manchin decided to vote for it,” said Hoyer. “I talked to Joe Manchin … at the Kennedy Center on Sunday night, and he was still hoping it would move forward.”

The U.S. wants to slash carbon emissions from power plants. Natural gas is in the way - Under President Joe Biden, the United States aims to cut all carbon pollution by 2035 from the power plants that run American homes and businesses. It's a first step toward the broader goal of zeroing out greenhouse gas emissions across the entire economy by midcentury to rein in climate change. But the ambitions of the Biden administration are set to collide with the country's power industry, which looks like it will continue burning fossil fuels for the foreseeable future. Over the next few years, the U.S. is expected to build around 17 gigawatts of natural gas plants, enough to power close to 12.8 million homes, according to the U.S. Energy Information Administration. Unless they're closed early, those plants could operate for decades on an electric grid that still gets almost 60% of its power from fossil fuels. Natural gas creates fewer emissions than coal when it's burned, but producing and transporting gas releases huge amounts of methane, a potent greenhouse gas. Most remaining oil and gas deposits must remain buried for the world to have a decent shot at keeping global temperatures from rising to more dangerous levels, according to a study last year in the journal Nature. But analysts don't expect the U.S. will end its reliance on natural gas any time soon. To close America's remaining coal plants, which generate around a fifth its electricity, many industry analysts believe the country needs natural gas to ensure reliable energy supplies until cleaner options like battery storage are widely available. "If you're going to kick that 20% of coal off the grid by 2030 or 2035, there is zero chance you can do that without increasing gas," says Andy DeVries, an analyst at CreditSights who tracks companies in the U.S. power industry. "After the coal's off the grid, how much longer does it take to then kick the gas off? That's at least another 10 years," DeVries says. "And that's aggressive." Scientists say the incremental cuts that countries are making to emissions won't be enough to avoid a future that brings more damaging storms, floods and heat waves. The U.S. has a giant pipeline of renewable energy projects — 45 gigawatts of solar and wind are expected to be built next year alone — but continuing to add emissions from new fossil fuel plants makes it harder to limit global warming.

How states are trying to fit gas utilities into a low-carbon future – A zero-carbon future is largely incompatible with an ever-expanding network of fossil-gas infrastructure. What sense does it make to let utilities keep building pipelines that must stop carrying fossil fuels in less than 30 years to meet decarbonization mandates? But states with ambitious climate goals also need to keep gas utilities financially healthy enough so they can maintain their remaining infrastructure in safe running order. States are also responsible for protecting low-income customers, who can’t easily switch from gas to electric heating and cooking, from being stuck paying exorbitant prices for a dwindling resource delivered by an increasingly underused delivery network. These competing imperatives mean that states are stuck trying to pull off a tricky policy balancing act, as seen most recently in California and Colorado. Last week, public utility commissions in both states adopted measures aimed at reducing the risk of “stranded assets” — gas pipelines that may not be able to earn back the cost of building them in future decades. They’re also trying to gain a better understanding of what can be done to supplant new gas lines with cleaner and more cost-effective alternatives, and ultimately to address the broad conundrum of what to do with gas utilities. The value of gas assets at risk of being stranded as the world moves to cut the use of fossil fuels amounts to hundreds of billions of dollars, according to various estimates. This includes the large-scale pipelines that carry gas from where it’s pulled out of the earth and the power plants that burn it to generate electricity. It also encompasses the distribution networks of pipes that deliver gas directly to customers’ homes and buildings. States with decarbonization goals are taking action to limit these stranded-asset risks. This year, Oregon and Washington state cut back subsidies for gas-system expansion, and Connecticut regulators ended a program that subsidized homes switching from heating oil to gas, saying it was no longer cost-effective or compatible with the state’s climate goals. Cities and counties are also acting to ban gas from newly constructed homes and businesses in California, Massachusetts, New York, Oregon, Washington state, Washington, D.C., and most recently, Maryland’s Montgomery County. (But this trend has provoked a backlash in a number of other states, where legislatures have passed laws preventing cities and counties from banning gas.) All in all, the risks for gas utilities are rising as it becomes clear that keeping global warming below catastrophic levels will require a steep reduction in burning gas, a 2021 report from consultancy Brattle Group warns.

Follow the markets to see where U.S. natural gas activity is high - (UPI) -- Operators working in the inland shale basins in the United States are focusing their activity on natural gas to capitalize on elevated prices, though gains aren't universal, analysis finds. Enverus Intelligence Research (EIR), a subsidiary of Canada-based energy research firm Enverus, found that, since the start of 2021, operators in Texas shale have shifted their activity in line with the rally in natural gas prices. "The relative well-level economics in the gas-weighted areas generate comparable returns and value when compared to the core of the basin and should compete for capital for operators with regional optionality," Stephen Pratt, a senior associate at EIR, said in an emailed statement.Wholesale natural gas prices are highly variable, moving on anything from the weather to curtailments overseas. Henry Hub, the U.S. benchmark for the price of natural gas, was trading around $5.47 per million British thermal units, down from August highs of $9.65 but still higher than the $3.80 level that started the year.The federal government expects Henry Hub will average $5.43 next year, compared with the $3.91 average for 2021. On production, the government said it expected an uptick in natural gas for next year, though gains could be limited by a lack of pipeline capacity that can carry products away from the field.Enverus found that markets are supportive of operations in the Permian, but that might not be the case elsewhere. A month-on-month forecast from the U.S. Energy Department finds that, by volume, the Appalachia basin -- comprising both the Marcellus and Utica shale plays -- is the most productive. Appalachia gains, however, are not as great as those in the Permian basin in Texas and New Mexico or the Haynesville play straddling the border of Louisiana and Texas. Haynesville production is on pace to accelerate by 1% from November levels, Permian by 0.6% and 0.4% in the Appalachia basin.Federal estimates put total U.S. natural gas production at 98.1 Bcf/d for 2002, a 0.1% revision higher than previous forecasts. By 2023, the United States is expected to produce 100.4 Bcf/d, an increase of 0.6% from previous estimates.

U.S. natgas succumbs to Freeport restart delay as demand outlook dims (Reuters) - U.S. natural gas futures extended a sell-off and fell more than 10% on Monday as forecasts for milder weather cast a shadow on demand outlook, hurt by the delayed restart of the Freeport liquefied natural gas (LNG) export plant. Front-month gas futures for January delivery shed 70.4 cents, or 11.2%, to settle at $5.577 per million British thermal units, having touched its lowest level since the end of October at $5.556. "The big factor putting downward pressure on prices today is the weather revisions. With warmer weather in the near future, less gas will be consumed in the residential and commercial sector. Our demand models show sharply lower demand for gas over the near-term," said John Abeln, analyst with data provider Refinitiv. Freeport LNG on Friday again delayed the restart of the second-biggest U.S. LNG export facility, moving its forecast for resuming processing to year end, pending regulatory approval. The delay is further curtailing gas demand from the export sector, energy consulting firm Ritterbusch and Associates said in a note. "With storage at around average levels, supplies appear adequate to meet requirements of a normal to moderately colder-than-normal winter. And although cold temperatures in Europe have been boosting prices, any implied increase in U.S. exports appears to be a minor consideration for now." The Freeport plant, which can convert about 2.1 billion cubic feet per day (bcfd) of gas into LNG, shut on June 8 due to an explosion caused by inadequate operating and testing procedures, human error and fatigue, according to a report by consultants hired by the company to review the incident and propose corrective actions.

Polar Plunge Seen for Next Week Drives Price Recovery for Natural Gas Futures - Natural gas futures bounced around Wednesday after weather models added a large chunk of demand to the long-range outlook, with frigid Canadian air forecast to plunge into the Lower 48 next week. After a sharp rally overnight lost momentum, confirmation in the midday data sent the January Nymex gas futures contract roaring higher and ultimately to a $5.723/MMBtu settlement. February futures shot up 23.9 cents to $5.617. Spot gas prices were sharply higher out West, fueled by another round of bitter cold and snow. NGI’s Spot Gas National Avg. climbed 73.5 cents to $6.540. After falling for four straight sessions, futures rebounded overnight after both the Global Forecast System (GFS) and European Centre models reversed and trended 15-20 heating degree days (HDD) colder. Although a revision was largely expected by traders, the amount of demand added back into the outlook likely was more than the natural gas markets were expecting, according to NatGasWeather. The latest data showed overnight lows plunging below zero across most of the northern half of the country during the Dec. 16-21 period. The southern United States also could see overnight temperatures slide into the 20s and 30s. This is notable, considering daytime highs on Tuesday in Houston reached 85 degrees, breaking the previous record of 81 set in 1999, according to local forecaster Space City Weather. Even more shocking, it snowed on the same day in 2017. Despite the increased likelihood of a mid-December cold snap, the damage done to prices from a much warmer-than-normal pattern in the first half of the month is significant, according to NatGasWeather. The prompt-month futures contract has shed $2 in about a week’s time. At the same time, the span of mild weather and resulting light demand is seen padding storage inventories before the peak winter months, which could limit a price rally. After falling more than 350 Bcf below the five-year average at the end of summer, stocks are poised to flip back to a surplus in the next couple of weeks, the forecaster said. Ahead of Thursday’s Energy Information Administration (EIA) weekly inventory report, storage withdrawal estimates pointed to a paltry draw anywhere from 8 Bcf to 60 Bcf for the week ending Dec. 2. To put this into perspective, the EIA recorded a 59 Bcf decrease in storage during the similar week last year and the five-year-average decline of 49 Bcf. A Wall Street Journal survey of 14 analysts averaged a withdrawal of 30 Bcf. A Bloomberg survey showed estimates as low as 8 Bcf with a median of 31 Bcf, while Reuters’ poll produced a median 27 Bcf withdrawal. NGI modeled a 25 Bcf decline in stocks. As of Nov. 25, total working gas in storage stood at 3,483 Bcf, which was 89 Bcf below year-earlier levels and 86 Bcf below the five-year average. Aside from the warmth that’s helped to lower demand, analysts point to robust production that has aided the steady improvement in supplies. Lower 48 dry gas output has hit 102 Bcf/d in recent months, with most daily declines chalked up to maintenance events rather than a structural shift in production. On Wednesday, for example, El Paso Natural Gas Pipeline (EPNG) declared a force majeure at two constraint points along its system. This was on top of the work already underway downstream on Line 1600. East Tennessee Natural Gas LLC also declared a force majeure on the Boyds Creek Compressor Station along the 3300 Line to complete emergent repairs. Meanwhile, Tennessee Gas Pipeline announced a force majeure impacting flows in Libertyville, NJ.

U.S. natgas up 4% on colder forecasts despite small storage draw (Reuters) - U.S. natural gas futures gained about 4% on Thursday on forecasts for colder weather and higher heating demand over the next two weeks than previously expected. That price increase came despite a federal report showing a smaller-than-expected storage decline last week, when mild weather kept heating demand low and ample wind power reduced the amount of gas that generators needed to burn to produce electricity. The U.S. Energy Information Administration (EIA) said U.S. utilities pulled 21 billion cubic feet (bcf)of gas from storage during the week ended Dec. 2. That was lower than the 31-bcf decline analysts forecast in a Reuters poll and well below a decrease of 59 bcf in the same week last year and a five-year (2017-2021) average decline of 49 bcf. The price increase also came despite Freeport LNG's announcement last week that it will delay the planned restart of its liquefied natural gas (LNG) export plant in Texas from mid-December to the end of the year. . Front-month gas futures for January delivery on the New York Mercantile Exchange rose 23.9 cents, or 4.2%, to settle at $5.962 per million British thermal units (mmBtu). In the spot market, gas prices in California have nearly doubled over the past couple of weeks as freezing weather and snow blankets parts of the state and pipeline outages and constraints limit gas flows from Texas. In Northern California, next-day gas for Thursday at the PG&E citygate hit its highest since February 2014, while gas at the Southern California Border rose to its highest since February 2021. The combination of mild weather in Texas and the pipeline constraints and maintenance outages limiting gas flows to California helped cut spot prices at the Waha hub in the Permian basin in West Texas by around 80% over the past week. U.S. gas futures are up about 61% so far this year as much higher global prices feed demand for U.S. exports due to supply disruptions and sanctions linked to Russia's war in Ukraine. Gas was trading at $43 per mmBtu at the Dutch Title Transfer Facility (TTF) in Europe and $34 at the Japan Korea Marker (JKM) in Asia.

U.S. natgas futures jump 5% on colder forecasts for late December (Reuters) - U.S. natural gas futures jumped 5% to a one-week high on Friday on forecasts for much colder weather and higher heating demand through late December than previously expected. In the spot market, U.S. West Coast power and gas prices have more than doubled over the past couple of weeks - with gas hitting multi-year highs - as freezing weather and snow blankets parts of California and gas pipeline outages and constraints limit flows of the fuel from Texas. That colder weather should force utilities to pull more gas from storage in coming weeks. Gas stockpiles were about 1.6% below the five-year (2017-2021) average for this time of year. The increase in futures prices came despite Freeport LNG's announcement last week that it will delay the planned restart of its liquefied natural gas (LNG) export plant in Texas from mid-December to the end of the year. That delay should keep LNG exports below record levels hit in March and leave more gas in the United States for domestic use. Some analysts do not expect Freeport to return until January, February or later because it will likely take federal pipeline safety regulators longer than Freeport expects to review and approve the plant's restart plan once the company submits it. The Freeport plant, which can turn about 2.1 billion cubic feet per day (bcfd) of gas into LNG, shut on June 8 due to an explosion caused by inadequate operating and testing procedures, human error and fatigue, according to a report by consultants hired to review the incident and suggest corrective actions. Front-month gas futures for January delivery on the New York Mercantile Exchange rose 28.3 cents, or 4.7%, to settle at $6.245 per million British thermal units (mmBtu), their highest since Nov. 2. That put the contract down about 1% this week after falling about 11% last week. U.S. gas futures were up about 69% so far this year as much higher global prices feed demand for U.S. exports due to supply disruptions and sanctions linked to Russia's war in Ukraine. Gas was trading at $42 per mmBtu at the Dutch Title Transfer Facility (TTF) in Europe and $33 at the Japan Korea Marker (JKM) in Asia. Data provider Refinitiv said average gas output in the U.S. Lower 48 states rose to 99.7 bcfd so far in December, up from a monthly record of 99.5 bcfd in November. With colder weather coming, Refinitiv projected average U.S. gas demand, including exports, would rise from 117.8 bcfd this week to 123.1 bcfd next week and 142.0 bcfd in two weeks. The forecasts for next week was higher than Refinitiv's outlook on Thursday. The average amount of gas flowing to U.S. LNG export plants rose to 11.9 bcfd so far in December, up from 11.8 bcfd in November. That remains below the monthly record of 12.9 bcfd in March due to the Freeport outage.

Gas line hit in College Park; delays likely along Route 1 - A gas line was struck Thursday morning and began to leak at the intersection of Lakeland Road and Baltimore Avenue in College Park.Fire officials said it appeared that no one was hurt in the incident. They also said that a contractor in the area had hit a line and ruptured it. Officials with Prince George’s County Fire said on Twitter the incident happened around 8:30 a.m. and is likely to cause “significant impact to pedestrian and vehicle traffic” along Route 1.Drivers are advised to avoid the area. Officials did not immediately disclose what caused the gas line to be hit.

A new Gulf oil spill study finds even deadlier impact on one of Florida's most popular fish | WUSF Public Media -- Field research on the consequences of the Deepwater Horizon oil spill found that heart, vision and hearing damage caused to mahi mahi populations by even low amounts of oil can cut the chances of survival within a week to just half. mMore than a decade after BP’s Deepwater Horizon drilling rig exploded into a lethal inferno that killed 11 and spilled more than 3 million barrels of oil in the Gulf of Mexico, researchers piecing together its lasting impacts have found more profound damage than previously known — to one of the Gulf’s most important fish. Testing wild mahi mahi, the team found for the first time that even low amounts of oil can cut survival rates in half within a week of exposure. The fish also stopped spawning for at least a month.“Those are massive numbers,” said Martin Grossell, lead principal investigator for one of 12 research groups funded by the BP’s Gulf of Mexico Research Initiative and a professor at the University of Miami Rosenstiel School. The findings were first published in September in the journal Environmental Science and Technology. In previous experiments, Grossell’s lab confirmed low levels of oil can damage the hearts, hearing and vision of young lab-bred mahi, impairing their fitness. The field work, done over three weeks in the northern Gulf of Mexico, now confirms that damage can be deadly, he said. “It will lead to mortality in the wild where fish have to compete for resources and avoid predation,” he said. “So it's a tougher life out there than it is in the lab.” For drilling opponents, these findings and others provide more evidence to end Gulf oil exploration. The Biden administration has proposed expanding it and is now taking public comment on a new lease. “These findings about the mahi are really no surprise,” said Catherine Uden, the South Florida field representative for the nonprofit conservation group Oceana. “It just goes to show that there are so many long lasting effects from fish to sea turtles to dolphins, and all of the impacts to the environment.” The group has joined a broad coalition of environmental groups and scientists calling for the administration to end Gulf drilling under the proposal.

Louisiana now lacks a seat at an energy table -- An announcement over the Thanksgiving holiday caused Louisiana's Republican congressional delegation to go after Democratic President Joe Biden — an attack that also underscored the state’s political vulnerability on energy issues. It all started when the U.S. Treasury Department's Office of Foreign Assets Control gave Chevron Corp., based in San Ramon, California, license to drill for a modest amount of oil and natural gas in Venezuela. The announcement was couched in humanitarian terms, ostensibly to ease suffering among the Venezuelan people caused by U.S. human rights sanctions. The country’s brutal dictator, Nicolas Maduro, recently made noises about meeting with opposition leaders. But the backstory is that the administration has been discussing since March how Venezuela could increase production. That country’s crumbling infrastructure produces about 800,000 barrels per day. In the 1990s, Venezuela produced about 3 million barrels per day. Biden wants to increase the supply of oil and thus lower the price of gasoline while also adhering to his campaign promise to work toward weaning the U.S. off carbon-producing fossil fuels that are hastening global warming. Underscoring the importance of drilling and refining to Louisiana's economy, Republicans in the congressional delegation vented on social media and Fox television. “The answer is right beneath our feet! How infuriating is it?” a Fox Business journalist asked U.S. Sen. Bill Cassidy, R-Baton Rouge. “It really is infuriating,” Cassidy replied. “This administration has chosen to focus only on carbon emissions, which means we get more carbon emissions — they’re burning coal in Europe because we can’t supply them with gas and oil — while at the same time we lose jobs here.” U.S. Rep. Steve Scalise, R-Jefferson, said in an interview that once in power, Republicans would forward bills to fill the oil shortage and lower prices at the pump, which in turn would weaken inflation. Specific bills that address permitting, pipelines, and leasing likely will be among the first legislation out of the gate when the Republican majority takes administrative control of the House on Jan. 3. But for the first time in who knows how many years, Louisiana’s delegation won’t have a seat at the table where such legislation is considered. With Scalise’s ascendance to House majority leader, the number two post, he’ll have to step down from the House Committee on Energy and Commerce. It’s not "Louisiana’s seat," but someone from the delegation has been on the committee since oil and natural gas oversight was added to its duties almost a century ago. If Louisiana’s delegation pushes one of its own for a seat on the committee, the question is who? And how?

Some 120,000 U.S. oil wells sit abandoned, new research shows - The Washington Post - Across the country, fossil fuel companies have walked away from thousands of oil and gas wells, leaving them unplugged and idle even as many of these drill sites leak greenhouse gas emissions and pose direct threats to human health. But until recently, states had little incentive to identify these wells and few resources to plug them. Now, the bipartisan infrastructure law that President Biden signed last year is changing the calculus around this mounting environmental challenge. The law, which authorized a record $4.7 billion for states’ efforts to plug abandoned wells, has set off a scramble among state officials to document the wells within their borders. As a result, states have now reported more than 120,000 abandoned wells in total, marking a nearly 50 percent increase from the 81,000 wells that they reported last year, according to a new analysis of state data by researchers at the Environmental Defense Fund and McGill University. Even this figure may mask the true extent of the problem. By some estimates, the number of undocumented abandoned wells in the United States — those that have yet to be discovered — could be as high as a million. Abandoned wells — also known as “orphaned wells” because no owner can be found — can leak toxic substances such as arsenic, formaldehyde and benzene, polluting the air and groundwater. Using census data, the analysis found that 14 million people live within a mile of an orphaned well, including 1.3 million adults with asthma. Exposure to air pollution can worsen asthma symptoms, according to the Centers for Disease Control and Prevention. Orphaned wells can also emit methane, a potent greenhouse gas that causes climate change. Responsible for roughly a third of global warming today, methane traps about 80 times as much heat as carbon dioxide during its first 20 years in the atmosphere.Abandoned wells are a huge climate problem. In January, the Interior Department announced that states could apply for an initial $1.15 billion in federal grants to fund the closure and cleanup of abandoned wells. The department noted that the grants would be based on three criteria: the number of documented orphaned wells in each state, the estimated cost of cleaning up the wells in each state, and the job losses in each state from March 2020 through November 2021. In August, Interior awarded an initial $560 million to 24 states to begin plugging and remediating more than 10,000 orphaned wells. Twenty-two states received $25 million each, while Arkansas and Mississippi got $5 million each to measure methane emissions from the wells and begin plugging them.

Lack of bidders increasing costs to plug abandoned oil and gas wells in Kentucky - - Contractors have started plugging some of the thousands of oil and gas wells abandoned by the fossil fuel industry across Kentucky, using new federal funding. But a lack of companies able or willing to bid on the work is increasing costs, a Kentucky official said recently. Kentucky received an initial $25 million grant through the Bipartisan Infrastructure Law this August to plug, reclaim and cap between 1,000 to 1,200 documented sites — known as “orphan” wells — that if poorly plugged or unplugged, can be a significant contributor of greenhouse gas emissions like methane. The federal grant is part of a broader plan from the White House to reduce nationwide emissions of methane. The greenhouse gas remains in the atmosphere for a shorter time compared to carbon dioxide but is 25 times more potent than carbon dioxide at trapping heat in the atmosphere. Unplugged or poorly plugged orphan wells can also leach toxic chemicals into underground aquifers or cause methane to unknowingly accumulate inside buildings, creating an explosive hazard. Dennis Hatfield, director of the Division of Oil and Gas in the Kentucky Energy and Environment Cabinet, in a Dec. 2 meeting said 171 wells across Kentucky have so far been plugged with the funding, and work is ongoing or completed in 12 counties. The cabinet has sent out phases of requests to plug hundreds of orphan well sites in 26 counties in Eastern and Western Kentucky. Hatfield said a shortage of participating bidders is a problem. In a couple of instances, he said, packages of well sites had to be re-bid because of a lack of responses from companies who could do the work. He said bonds required to be taken on by the bidders, along with added federal regulations regarding payroll, have made it harder for smaller companies to get involved. “It’s probably doubled or tripled the cost of the labor component,” Hatfield said. “Our goal is to have as many contenders in there so that we get the most competitive price.” A report last year by the Environmental Defense Fund shows more than 13,000 documented orphan wells lie across the state, a tenth of the national total of more than 120,000 wells. The nonprofit research group Resources for the Future in a report analyzed data on nearly 20,000 orphan wells in four states, finding that the the average cost to plug a well to be around $20,000; the price per plugged well jumps to an average of $76,000 when the ground surrounding the well site is also rehabilitated.

Lujan wants more federal funds for New Mexico's abandoned oil wells - An estimated 1,700 oil and gas wells sit abandoned in New Mexico, potentially spewing pollution in the state’s land and a, Wells can be left unused and unmonitored by energy companies when they are deemed financially unviable.During the volatile oil and gas industry’s frequent ups and downs, oil-rich areas like New Mexico’s southeast Permian Basin region can see more wells going into service and later abandoned or “orphaned” in industry terms.To address this issue, U.S. Sen. Ben Ray Lujan (D-NM) introduced the Abandoned Well Remediation Research and Development Act to provide federal funds used to find and identify abandoned oil and gas wells and track their impacts on the environment, while also developing a process for plugging and restoring the land to its natural state The Act would amend the Infrastructure Investment and Jobs Act, which contained provisions from Lujan’s previous Revive Economic Growth and Reclaim Orphaned Wells (REGROW) Act that provided about $4.3 billion for cleanup of the wells on state and private land.The REGROW Act also earmarked another $400 million for the work on federal and Tribal lands, and $32 million for associated research.

Oil spill in rural Kansas creek shuts down Keystone pipeline - Toledo Blade— An oil spill in a creek in northeastern Kansas shut down a major pipeline that carries oil from Canada to the Texas Gulf Coast, briefly causing oil prices to rise Thursday. Canada-based TC Energy said it shut down its Keystone system Wednesday night following a drop in pipeline pressure. It said oil spilled into a creek in Washington County, Kansas, about 150 miles northwest of Kansas City. The company on Thursday estimated the spill's size at about 14,000 barrels and said the affected pipeline segment had been “isolated” and the oil contained at the site with booms, or barriers. It did not say how the spill occurred. “People are sometimes not aware of of the havoc that these things can wreak until the disaster happens,” said Zack Pistora, who lobbies the Kansas Legislature for the Sierra Club's state chapter. Concerns that spills could pollute waterways spurred opposition to plans by TC Energy to build another crude oil pipeline in the Keystone system, the 1,200-mile Keystone XL, which would have cut across Montana, South Dakota and Nebraska. Critics also argued that using crude from western Canada's oil sands would worsen climate change, and President Joe Biden's cancelation of a U.S. permit for the project led the company to pull the plug last year. In 2019, the Keystone pipeline leaked an estimated 383,000 gallons of oil in eastern North Dakota. Janet Kleeb, who founded the Bold Nebraska environmental and landowner rights group that campaigned against the Keystone XL, said there have been at least 22 spills along the original Keystone pipeline since it began service in 2010. She said federal studies have shown the type of heavy tar sands oil the pipeline carries can be especially difficult to clean up in water because it tends to sink. “All oil spills are difficult, but tar sands in particular are very toxic and very difficult, so I’m awfully concerned,” said Kleeb, who is also the Nebraska Democratic Party's chair. But the U.S. Environmental Protection Agency said there were no known effects yet on drinking water wells or the public, and the oil didn't move from the creek to larger waterways. Randy Hubbard, the Washington County Emergency Management coordinator, said there were no evacuations ordered because the break occurred in rural pastureland. TC Energy said it had set up environmental monitoring at the site, including around-the-clock air quality monitoring. A U.S. Energy Information Administration spokesperson said the Keystone pipeline moves about 600,000 barrels of oil per day from Canada to Cushing, Oklahoma, where it can connect to another pipeline to the Gulf Coast. That’s compared to the total of 3.5 million to 4 million barrels of Canadian oil imported into the U.S. every day. Past Keystone spills have led to outages that lasted about two weeks, but this outage could possibly be longer because it involves a body of water, said analysts at RBC Capital Markets in a note to investors. “It could eventually impact oil supplies to refiners, which could be severe if it lasts more than a few days.” The spill was 5 miles northeast of Washington, the county seat of about 1,100 residents. Paul Stewart, an area farmer, said part of it was contained on his land using yellow booms and a dam of dirt. The spill occurred in Mill Creek, which flows into the Little Blue River. The Little Blue feeds the Big Blue River, which flows into Tuttle Creek Lake, north of Manhattan, home of Kansas State University. The EPA said the oil did not affect the Little Blue. Dan Thalmann, publisher and editor of The Washington County News, a weekly publication, said crews were creating a rock path to the creek because recent rains made fields too soft to move in heavy machinery. “Gosh, the traffic past my house is unbelievable — trucks after trucks after trucks,” said Stewart, who took down an electric fence he'd finished putting up Wednesday, fearing it might be knocked down and dragged into a field. Chris Pannbacker said the pipeline runs through her family's farm. She and her husband drove north of their farmhouse and across a bridge over Mill Creek. “We looked at it from both sides, and it was black on both sides,” said Pannbacker, a reporter for the Marysville Advocate newspaper. Junior Roop, the sexton of a cemetery near the spill site, said people could smell the oil in town. “It was about like driving by a refinery,” he said.

Oil spill in rural Kansas creek shuts down Keystone pipeline system - (photos) The Keystone pipeline system was shut down by operator TC Energy after an oil spill released an estimated 14,000 barrels into a creek in Washington County, Kansas. The system transfers oil between Canada and the U.S. Crews were able to control downstream migration of the oil as of Thursday night. Repair planning is underway as are shoreline assessments, according to TC Energy. Continuous air quality monitoring has also been deployed, the company said. The emergency shutdown was issued early Thursday morning after a detected pressure drop in the system. TC Energy said it will conduct a full investigation into the root cause of the incident and is cooperating with regulators. The affected segment was isolated and booms were deployed to control downstream migration of the spill, TC Energy said. The Environmental Protection Agency dispatched two regional coordinators to the scene. TC Energy also mobilized a response crew originating from Steele City, Nebraska, to begin containment and source control, according to the the EPA. Washington County is about 20 miles south of Steele City, Nebraska. According to the EPA, there are no known impacts to drinking water wells or the public but surface water of Mill Creek has been impacted. U.S. Transportation Secretary Pete Buttigieg said his agency is "monitoring and investigating" the Keystone leak. "Our Pipeline and Hazardous Materials Safety Administration has issued a Corrective Action Order requiring a shutdown of the affected segment, analysis of the cause, and other safety measures," Buttigieg said in a tweet Friday. TC Energy said it immediately activated its emergency response procedures and has established environmental monitoring, including around-the-clock air monitoring. It's still unclear what caused the spill. The EPA said it will oversee TC Energy’s response operations to ensure proper cleanup and evaluate the cause of the incident.

Keystone pipeline leaks 14,000 barrels of oil into creek in biggest spill yet - An oil spill in a creek in north-eastern Kansas this week is the largest for an onshore crude pipeline in more than nine years and by far the biggest in the history of the Keystone pipeline, according to federal data. Canada-based TC Energy estimated the spill on the Keystone system at about 14,000 barrels and said the affected pipeline segment had been “isolated” and the oil contained. It did not say how the spill occurred. After a drop in pressure on the pipeline that carries oil from Canada to the Texas Gulf coast, the company said it shut down its Keystone system on Wednesday night. Oil spilled into a creek in Washington county, Kansas, about 150 miles north-west of Kansas City. The transportation secretary, Pete Buttigieg, on Friday tweeted that the government was investigating. Zack Pistora, a lobbyist in Kansas for environmental campaign group the Sierra Club, noted the latest spill was larger than all of the 22 previous spills combined on the Keystone pipeline, which began operations in 2010. “This is going to be months, maybe even years before we get the full handle on this disaster and know the extent of the damage and get it all cleaned up,” he said. In September 2013, a Tesoro Corp pipeline in North Dakota ruptured and spilled 20,600 barrels, according to US Department of Transportation data. A more expensive spill happened in July 2010, when an Enbridge Inc pipeline in Michigan ruptured and spilled more than 20,000 barrels into Talmadge Creek and the Kalamazoo River. Hundreds of homes and businesses were evacuated and federal regulators later ordered Enbridge to dredge the contaminated sediment from the river. The Keystone pipeline’s previous largest spill came in 2017, when more than 6,500 barrels were spilled near Amherst, South Dakota, according to a US Government Accountability Office report released last year. The US Environmental Protection Agency said there were no known effects yet on drinking water wells or the public in connection with this week’s spill. “Our primary focus right now is the health and safety of onsite staff and personnel, the surrounding community and mitigating risk to the environment,” a TCV Energy company statement said. Junior Roop, the sexton of a nearby cemetery, said people could smell the oil in town. “It was about like driving by a refinery,” he said. Concerns that spills could pollute waterways spurred opposition to plans by TC Energy to build another crude oil pipeline in the Keystone system, the 1,200-mile Keystone XL, which would have cut across Montana, South Dakota and Nebraska. Critics also argued that using crude from western Canada’s oil sands would worsen the climate crisis, and Joe Biden’s cancelation of a US permit for the project led the company to pull the plug last year. A US Energy Information Administration spokesperson said the Keystone pipeline moves about 600,000 barrels of oil a day from Canada to Cushing, Oklahoma, where it can connect to another pipeline to the Gulf coast.

Federal data: Kansas oil spill biggest in Keystone history -- (aerial video) — A ruptured pipe dumped enough oil this week into a northeastern Kansas creek to nearly fill an Olympic-sized swimming pool, becoming the largest onshore crude pipeline spill in nine years and surpassing all the previous ones on the same pipeline system combined, according to federal data. The Keystone pipeline spill in a creek running through rural pastureland in Washington County, Kansas, about 150 miles (240 kilometers) northwest of Kansas City, also was the biggest in the system’s history, according to U.S. Department of Transportation data. The operator, Canada-based TC Energy, said the pipeline that runs from Canada to Oklahoma lost about 14,000 barrels, or 588,000 gallons. The spill raised questions for environmentalists and safety advocates about whether TC Energy should keep a federal government permit that has allowed the pressure inside parts of its Keystone system — including the stretch through Kansas — to exceed the typical maximum permitted levels. With Congress facing a potential debate on reauthorizing regulatory programs, the chair of a House subcommittee on pipeline safety took note of the spill Friday. A U.S. Government Accountability Office report last year said there had been 22 previous spills along the Keystone system since it began operating in 2010, most of them on TC Energy property and fewer than 20 barrels. The total from those 22 events was a little less than 12,000 barrels, the report said. “I’m watching this situation closely to learn more about this latest oil leak and inform ways to prevent future releases and protect public safety and the environment,” Democratic U.S. Rep. Donald Payne Jr., of New Jersey, tweeted. TC Energy and the U.S. Environmental Protection Agency said the spill has been contained. The EPA said the company built an earthen dam across the creek about 4 miles downstream from the pipeline rupture to prevent the oil from moving into larger waterways. Randy Hubbard, the county’s emergency management director, said the oil traveled only about a quarter mile and there didn’t appear to be any wildlife deaths. The company said it is doing around-the-clock air-quality checks and other environmental monitoring. It also was using multiple trucks that amount to giant wet vacuums to suck up the oil.

Major oil pipeline outage to hit U.S. stockpiles, refinery supplies (Reuters) - An outage on the largest oil pipeline to the United States from Canada could affect inventories at a key U.S. storage hub and cut crude supplies to two oil refining centers, analysts and traders said on Friday. TC Energy's Keystone pipeline ferries about 600,000 barrels of Canadian crude per day (bpd) to the United States. It was shut late Wednesday after a breach spewed more than 14,000 barrels of oil into a Kansas creek, making it the largest crude spill in the United States in nearly a decade. "The main question continues to be the duration of the potential outage... the longer the duration, ultimately, of course means potentially tighter inventories in Cushing or heavy (crude) on the Gulf Coast," said Michael Tran, a managing director at RBC Capital markets. The line runs directly to the Cushing, Oklahoma, storage hub, which is currently about a third full with nearly 24 million barrels in stock. If the outage last for more than 10 days, it could push Cushing storage to near the operational minimum of 20 million barrels, said AJ O'Donnell, a director at pipeline researcher East Daley Capital. Volumes in the fourth quarter will be "materially affected," as Keystone likely will run at a considerably lower pressure at least for some time once it restarts, said Harshit Gupta, Arc Independent research. Other pipelines between Canada and the United States are at or near capacity, East Daley and data analytics firm Wood Mackenzie estimates. "There's nowhere near enough to take 600,000 barrels a day. There's just not enough pipe right now," O'Donnell said. The spill in Kansas took place downstream from a key junction in Steele City, Nebraska, where Keystone splits to run into Illinois. That stretch of the line could be restarted, but the other segment affected by the spill will not come back until regulators approve a restart. TC Energy aims to restart on Saturday a pipeline segment that sends oil to Illinois, and another portion that brings oil to Cushing on Dec. 20, Bloomberg reported, citing sources. TC Energy said it was evaluating plans to return the pipeline to service. Volumes to the Gulf from Cushing have already dropped. Volumes on TC Energy's Marketlink pipeline, which flows from Cushing to Nederland, Texas, fell by about 300,000 bpd to less than 500,000 bpd, Wood Mackenzie estimates, after the leak was discovered. Gulf Coast refiners, which could suffer shortages of heavy Canadian crude, can draw on supplies from offshore Louisiana facilities and from Colombia, Mexico and Ecuador. U.S. physical crude oil grade prices were mixed on Thursday and O'Donnell at East Daley said he expects volatility to continue as long as Keystone remained offline. Meanwhile, a lengthy shutdown of the pipeline could lead to Canadian crude getting bottlenecked in Alberta, and drive prices lower, although the market's reaction on Friday was muted. Western Canada Select (WCS), the benchmark Canadian heavy grade, for December delivery last traded at a discount of $27.70 per barrel to the U.S crude futures benchmark, according to a Calgary-based broker. On Thursday, December WCS traded as low as $33.50 under U.S. crude, before settling at around a $28.45 discount.

Federal judge orders Enbridge, Bad River to make a plan to avoid a 'catastrophic' rupture of Line 5 on tribe's reservation - A federal judge has ordered the Bad River tribe and Canadian energy firm Enbridge Inc. to come up with a joint proposal to shut down and purge an oil and gas pipeline should erosion worsen at the Bad River and threaten a "catastrophic" rupture. The Bad River Band of Lake Superior Chippewa sued the Canadian energy firm in federal court in 2019 to shut down and remove Line 5. The lawsuit followed the tribe’s decision not to renew easements for the pipeline that had expired in 2013 on a dozen parcels of tribal land. Tribal officials argue the pipeline poses an unreasonable risk to health and safety as erosion at an area referred to as "the meander" threatens to expose and rupture Line 5. In response to Bad River’s lawsuit, Enbridge is planning to build a $450 million pipeline that would run 41 miles around the Bad River reservation.The nearly 70-year-old Line 5 carries up to 23 million gallons of oil and natural gas liquids per day and spans 645 miles from Superior through northern Wisconsin and Michigan to Sarnia, Ontario. Enbridge contends the pipeline has been safely operating, serving as a vital energy link to the region.In a Monday order, U.S. District Judge William Conley said risk of a significant rupture exists that could result in "catastrophic" impacts to the Bad River watershed and Lake Superior. "Thus, the court finds that a rupture of Line 5 at the meander would be a substantial and unreasonable interference with the Band’s and the public’s rights," wrote Conley. His ruling allows the pipeline to continue operating, but requires Enbridge to come to an agreement with the tribe on emergency measures to avoid a spill. Conley noted the nearest shutoff valves are 14 miles apart on either side of the meander. He said that makes it unlikely that they could be activated in time to prevent roughly 20,000 gallons of crude and natural gas liquids in that segment of pipe from spilling into the Bad River.The judge ordered Enbridge and Bad River to meet and discuss installation of emergency shutoff valves, a protocol for shutting down and purging the line, and projects that could slow further erosion by Dec. 17. The two must submit a joint proposal or each must offer their own proposal if no agreement can be reached by Dec. 24.

Enbridge and Bad River Band to meet following pipeline decision - -By the end of December, the legal battle between the Canadian energy company Enbridge Inc. and the Bad River Band will enter its next phase. U.S. District Judge William Conley issued an order Monday that requires Enbridge and the tribal community to meet to discuss ways to mitigate dangers associated with the company’s Line 5 pipeline by Dec. 17, and to submit plans by Dec. 24 for the future of Line 5. Either the tribe and the company will work together on a plan, or they’ll propose separate visions for Line 5. In his decision, Conley denied Enbridge’s requests for injunctive relief. Enbridge asserted that the Bad River Band and Naomi Tillison, director of its natural resources department, had unlawfully denied the company access to Line 5 to conduct inspections and maintenance. Enbridge argued that the Clean Water Act, the Transit Pipelines Treaty signed between the U.S. and Canadian governments in 1977 and the U.S. All Writs Act— which dates back to 1789 in its original form — gave the court the authority to order the tribe comply with Enbridge’s demands for access to tribal land. The treaty prohibits public authorities from instituting measures that would “have the effect of impeding, diverting, redirecting or interfering with in any way the transmission of hydrocarbons in transit,” the decision document notes. In his decision, Conley writes that Enbridge isn’t a party to the U.S.-Canadian treaty. Nor does the treaty suggest that “a private entity could bring a cause of action to enforce it or even that it may be enforced in federal court,” the decision states. “Instead, the signatory countries may bring claims under the Transit Treaty pursuant to a specific arbitration process, as Canada has done with respect to Line 5.” Elizabeth Ward, chapter director of the Sierra Club of Wisconsin, says invoking the treaty was an attack on tribal sovereignty. “I was happy to see the judge recognize that the 1977 Transit Treaty had no bearing on this case at all,” said Ward, who monitored the federal case closely. “Enbridge tried to argue that it was OK for them to trespass on Bad River’s land and, essentially, this treaty between the U.S. and Canada overwrote Bad River’s sovereignty. And I was glad to see the judge agree with Bad River that Enbridge was wrong.”

USA Oil and Gas Jobs Are Still in Short Supply - The short supply of labor in the US oil patch has plagued exploration and production companies all year, and the tightness continues. While the sector’s unemployment rate jumped to 3.1% in November from 0.8% in the prior month on an unadjusted basis, it’s still well below the long-term average, according to a Labor Department report released Friday. A year-ago, the jobless rate was 8.6% as many workers were sidelined due to the pandemic stalling output amid very weak oil demand. Labor shortages in US shale have been one of the biggest hurdles holding back production growth this year. Explorers, who have faced repeated calls from the Biden administration to boost production amid rising energy costs, routinely cite their inability to find enough workers to drill new wells. The number of workers employed in US oil and gas jobs totaled 135,700 in November, climbing modestly for a third straight month, but still down from this year’s peak in July. The tightness in the energy labor markets replicates trends in the wider economy. But the broader mining and logging industry -- which includes oil and gas, according to the Labor Department’s classification -- is the farthest behind of any sector in recovering its pandemic job losses, down 6.9% from February 2020.

Get the facts on fracking - Over the past 15 years or so, fracking has enabled an explosion of oil and gas extraction across the United States. By drilling horizontally and then pumping toxic fluid at high pressure to fracture shale rock, fracking captures otherwise inaccessible fossil fuels dispersed underground. As we documented in Fracking by the Numbers, the resulting environmental degradation is enormous.Fracking generates huge volumes of toxic wastewater – laced with chemicals and sometimes even radioactive substances. Leaks and spills of fracking waste have put drinking water sources and at risk on hundreds of occasions. Fracking also uses billions of gallons of water – even in drought-stricken places like Texas.Public health is also endangered by the industrial machinery connected to fracking – as wells, compressors, trucks and other equipment release toxic air pollution.In addition, dirty drilling also does substantial damage to wildlife and our natural heritage – as well pads, new access roads, pipelines and other infrastructure built for fracking turn forests and rural landscapes into industrial zones.And while fracking has brought a windfall for some, its industrial disruption and legacy waste impose a multitude of costs on communities. And dirty drilling also contributes to the climate crisis – especially as methane leaks from well pads and beyond. Against this dirty record, the oil and gas industry has sought to convince the public that fracking can be done safely. Yet our researchers in Pennsylvania uncovered fracking operators continuing to violate environmental and health rules with impunity.For all these reasons, Environment America is working to halt the expansion of fracking wherever we can and enforce stronger environmental safeguards wherever dirty drilling is already underway.

Los Angeles City Council votes to ban oil and gas drilling - The Los Angeles City Council voted unanimously on Friday to ban drilling of new oil and gas wells and phase out existing ones over the next 20 years. The vote comes after more than a decade of complaints from city residents that pollution drifting from wells was affecting their health. “Hundreds of thousands of Angelenos have had to raise their kids, go to work, prepare their meals (and) go to neighborhood parks in the shadows of oil and gas production,” said Los Angeles City Council president Paul Krekorian, one of the councilmembers who introduced this measure. “The time has come .... when we end oil and gas production in the city of Los Angeles.” Two engineers with Yorke Engineering, a California-based company that does air quality and environmental compliance review, spoke in opposition to the ordinance. They said a ban and phase out will have a negative effect because oil and gas operators will abandon wells. They said this is being underestimated by the city. If they walk away, that will mean increased air pollution and greenhouse gas emissions, they said. But Los Angeles City Attorney Mike Feuer said these claims are “not credible,” citing a review by Impact Sciences, another California-based firm that performed an environmental analysis of the ordinance for the city.

Los Angeles bans oil and gas drilling within city limits - The Los Angeles City Council has voted to ban new oil and gas drilling and phase out existing wells over the next two decades, a historic decision that comes after years of complaints by residents about how pollution from nearby drilling has caused them health issues. In a 12-0 vote, the council on Friday approved an ordinance it began drafting earlier this year that will immediately ban new extraction and shut down existing operations within 20 years. The decision to ban new drilling and decommission existing wells is one of the strongest environmental policies enacted in the state, and could pave the way for other cities around the country to adopt similar measures. Historically, environmental legislation that has originated in California has often spread to other parts of the country, such as cleaner emissions standards for cars in the 1970s. More recently, the state banned the sale of new gasoline-powered cars by 2035, and New York state soon followed suit. There are 26 oil and gas fields and more than 5,000 active and idle wells in LA. Wells are spread out all over the city, including Wilmington, Harbor Gateway, downtown, West LA, South LA and the northwest San Fernando Valley. The oil industry has largely opposed the city’s ban, arguing that phasing out production will make LA more dependent on foreign energy. Hector Barajas, a spokesman for the California Independent Petroleum Association, which represents independent oil and gas producers in the state, said that 2.5 million barrels of oil produced by the city last year would have to replaced by imports from Saudi Arabia, Ecuador and Iraq given the state’s new ban. The U.S. now produces over 12 million barrels per day, according to the U.S. Energy Information Administration. “Our in-state oil is the only California climate-compliant oil in the world, given that oil producers must adhere to the state’s greenhouse gas reduction program and account for all emissions,” Barajas said. “Foreign oil imports are totally exempt from those requirements.”

In historic move, Los Angeles bans new oil wells, phases out existing ones -- The Los Angeles City Council voted Friday to phase out all oil drilling in L.A. and ban new wells, a historic move in a city that was built by a once-booming petroleum industry and whose residents have suffered with decades of environmental consequences as a result.In a 12-0 vote, the council approved a new ordinance that immediately bans new oil and gas extraction and requires that all existing oil and gas extractions stop production within 20 years.The move is opposed by the oil industry, whose leaders warned city officials that the phase-out will hurt the city’s finances and make L.A. more dependent on foreign oil.According to the city’s planning department, Los Angeles has 26 oil and gas fields and more than 5,000 oil and gas wells. Some of the wells are active, while others are idle.Many wells are found in the Wilmington and harbor areas, but also operate in downtown, West Los Angeles, South Los Angeles, and the northwest San Fernando Valley, according to the city’s planning department.Oil wells are known to emit likely carcinogens including benzene and formaldehyde, and living near wells is linked to health problems including respiratory issues and preterm births, studies have found.Environmental justice activists charge that low-income communities of color are particularly affected by the wells and associated health problems. Stand Together Against Neighborhood Drilling, or STAND-L.A., a group of community groups that helped spearhead the law, said Friday in a statement that “Black, Latinx and other communities of color currently living near polluting oil wells and derricks in South L.A. and Wilmington will eventually breathe easier.” Still, STAND-L.A.'s members skipped Friday’s City Council meeting and a subsequent news conference with several council members, saying that they couldn’t support “business as usual” while Gil Cedillo and Kevin De León, who are facing calls to resign following their role in a 2021 incendiary closed-door conversation, remain on the council. “Our city and this council must own up to the anti-Blackness that created policies that allowed oil drilling in neighborhoods in the first place and that fostered an environment where such a horrific example of racism and corruption could occur between council members,” the group said.

Newsom proposes penalizing oil companies amid high fuel prices - California Gov. Gavin Newsom (D) on Monday evening unveiled a proposal that would penalize oil companies for “excessive profits” in the Golden State.Newsom introduced the “price gouging penalty” alongside state Sen. Nancy Skinner (D) in a move they said would “deter excessive price increases and keep money in Californians’ pockets.”“California’s price gouging penalty is simple – either Big Oil reins in the profits and prices, or they’ll pay a penalty,” Newsom said in a statement.The proposal comes as California’s legislature kicks off a special session, initiated by the governor, to address the issue of price gouging.California, which also has among the highest gas taxes in the country, saw prices hit a record high of $6.44 per gallon in mid-June, according to AAA. Prices at the pump on Tuesday were about $4.72 per gallon — significantly higher than the national average of $3.38. No one can deny that California’s gas prices were outrageously high compared to other states. And those high prices hurt California consumers and businesses,” Skinner said in a statement. If approved by state lawmakers, the proposal would make it illegal for companies to charge excessive prices, and excessive refiner margins would be punishable by a civil penalty from the California Energy Commission. The definition of excessive — including the maximum margin and penalty amounts — would be determined through the legislative process, according to the proposal. Any penalties collected would go to a “Price Gouging Penalty Fund” that would be redistributed to Californians. The proposal also aims to improve transparency and oversight of the oil industry by the state and expand the abilities of the California Energy Commission and the California Department of Tax and Fee Administration to obtain data on costs, profits and pricing.To back up the proposal, the governor’s office referred to a list of occasions in which oil companies reported record high profits during the third quarter of 2022.Among those cited was a surge in profits for Phillips 66 to $5.4 billion — a 1,243 percent increase over last year’s $402 million. Meanwhile, BP posted is second-highest profits on record — $8.2 billion — with $2.5 billion going toward share buybacks for Wall Street investors. Gains at Marathon Petroleum rose to $4.5 billion, compared to $694 million during the same period last year, while $2.82 billion in profits at Valero in the third quarter marked a 500 percent surge over last year.

Big Oil talks ‘transition’ but perpetuates petroleum, House documents say -- Some of the world’s major oil companies remain internally skeptical about the “energy transition” to a low-carbon economy, even as they publicly portray their firms as partners in the cause, according to documents obtained by The Washington Post that a House committee released Friday.The documents are part of a trove obtained by the House Committee on Oversight and Reform during a year-long investigation. They reveal oil company executives dismissing the potential for renewable energy to quickly replace fossil fuels, while working to secure a future for natural gas. They also detail industry efforts to secure government tax credits for carbon capture projects that might relieve them of the need to drastically alter their business models. The documents — many of them copies of internal emails between oil company officials — describe ExxonMobil’s efforts in 2021 to persuade big industrial firms and oil giants to co-sponsor a mammoth carbon capture project in Texas. Elsewhere, in one email string, officials at Shell discuss whether BP, Shell and TotalEnergies — a French oil firm — increased their carbon footprints by selling Canadian oil sands interests to more eager investors.Big petroleum companies have come under fire for selling off oil sands properties to smaller businesses, effectively reshuffling the carbon dioxide liability. In response to that criticism, one spokesperson said: “What exactly are we supposed to do instead of divesting … pour concrete over the oil sands and burn the deed to the land so no one can buy them?Scientists say the world must rapidly transition from fossil fuels to prevent the worst expected effects of climate change, a position shared by Democrats on the House Oversight Committee.For more than a year, the committee has been investigating a handful of major oil companies, along with two of the biggest trade groups in Washington, the American Petroleum Institute and U.S. Chamber of Commerce. The investigation has sought documents about the industry’s campaigns to influence public opinion and policy on climate change.The committee says the industry is misleading the public by advertising a commitment to cleaner energy even as it disproportionately invests in fossil fuels. The committee has accused oil companies of continued deception, following previous revelations about oil companies working to undermine the credibility of climate science.“These documents demonstrate how the fossil fuel industry ‘greenwashed’ its public image with promises and actions that oil and gas executives knew would not meaningfully reduce emissions, even as the industry moved aggressively to lock in continued fossil fuel production for decades to come,” Chairwoman Carolyn B. Maloney (D-N.Y.) and Rep. Ro Khanna (D-Calif.), chair of the environment subcommittee, said in a Friday memo outlining their findings to the rest of the committee.With Democrats losing control of the House in last month’s midterms, this is likely to mark the end of their investigation. Republicans are promising a different day.

U.S. Oil Exports Hit Record High - U.S. exports of crude oil and petroleum products hit an all-time high of 11.8 million barrels per day (bpd) last week, The Maritime Executive reports. In the week to November 25, a total of 11.776 million bpd of U.S. crude and petroleum were exported, the latest data from the U.S. Energy Information Administration showed. The jump in American crude and product exports came days before the EU embargo on imports of Russian crude oil by sea, which came into effect on December 5, along with a price cap set by the EU and G7 at $60 per barrel for Russia’s crude, if traders want to use Western maritime transportation services for shipping Russian oil.Of all the 11.8 million bpd of American crude and products exported last week, seaborne exports of U.S. crude oil exceeded 7.1 million bpd, an all-time high, according to TankerTrackers.com. The tanker-tracking service counted 15 very large crude carriers (VLCCs) or ultra-large crude carriers (ULCCs)—each capable of transporting 2 million barrels of oil—departing U.S. ports last week, it said on Monday.According to the EIA’s data, weekly American crude exports have also set records multiple times in recent weeks. The United States has ramped up exports of crude as the EU looks to non-Russian supply due to the embargo. In fact, U.S. exports of crude and petroleum products have been steadily rising this year, especially after the Russian invasion of Ukraine upended energy trade flows and buyers started shunning Russian products or began preparations to purchase non-Russian supplies.The Port of Corpus Christi, Texas, for example, has set records this year in tonnage exported, largely due to crude oil exports. In the third quarter, the port beat its previous record from the second quarter, driven in large part by record exports of crude oil.

U.S. pledges to ramp up supplies of natural gas to Britain as Biden and Sunak seek to cut off Russia — The U.K. and U.S. are forming a new energy partnership focused on boosting energy security and reducing prices. In a statement Wednesday, the U.K. government said the new partnership would “drive work to reduce global dependence on Russian energy exports, stabilise energy markets and step up collaboration on energy efficiency, nuclear and renewables.”The U.K.-U.S. Energy Security and Affordability Partnership, as it’s known, will be directed by a U.K.-U.S. Joint Action Group headed up by officials from both the White House and U.K. government. Among other things, the group will undertake efforts to make sure the market ramps up supplies of liquefied natural gas from the U.S. to the U.K. “As part of this, the US will strive to export at least 9-10 billion cubic metres of LNG over the next year via UK terminals, more than doubling the level exported in 2021 and capitalising on the UK’s leading import infrastructure,” Wednesday’s announcement said. “The group will also work to reduce global reliance on Russian energy by driving efforts to increase energy efficiency and supporting the transition to clean energy, expediting the development of clean hydrogen globally and promoting civil nuclear as a secure use of energy,” it added. Commenting on the plans, U.K. Prime Minister Rishi Sunak said: “We have the natural resources, industry and innovative thinking we need to create a better, freer system and accelerate the clean energy transition.” “This partnership will bring down prices for British consumers and help end Europe’s dependence on Russian energy once and for all.” The news comes at a time of huge disruption within global energy markets following Russia’s invasion of Ukraine in February.

TotalEnergies To Cut £100M In 2023 North Sea Investments - TotalEnergies’ North Sea business chief said that the French firm would cut investment by a quarter next year due to the UK Government’s windfall tax. In a statement the TotalEnergies UK country chairman Jean-Luc Guiziou gave to Energy Voice, he stated that the move would see the company cut tens of millions of pounds from its North Sea investment plans for 2023. More precisely, TotalEnergies’ investment cut for next year equates to £100m. This is a consequence of UK chancellor Jeremy Hunt increasing the Energy Profits levy – otherwise known as the windfall tax – to a total of 35 percent and extending it until 2028. As a result, oil and gas firms will now pay 75% tax in total on profits through to the end of that year, even if oil prices fall, in an attempt to raise around £40bn for the Treasury. “Following another change to the fiscal environment for energy investors in the UK, we are now evaluating the impact of this change on our current and planned projects. We note that without a price floor to the EPL, the current regime will affect short-cycle investments, in particular infill wells. For 2023 alone, our investments will be cut by 25 percent,” Guiziou told Energy Voice. Guiziou added that a competitive and stable fiscal and regulatory regime was “vital to investment in critical energy and infrastructure projects” that would help meet the UK’s energy security needs and net zero ambitions. “The energy industry operates in a cyclical market and is subject to volatile commodity prices. We believe that the Government should remain open to reviewing the energy profits levy if prices reduce before 2028,” he said in the statement. TotalEnergies is not the only company that is seeing the levy impact its bottom line. Many producers saw their share prices drop since the windfall tax was introduced. “The average UK independent producer has seen their share price fall by more than 20 percent since the EPL announcement. In the same period, the share price of the UK-listed majors has increased by almost 10 percent and US independents have seen an increase of over 25 percent. Increased pressure from our global providers of capital for geographic diversification should surprise no one,” Harbour Energy CEO Linda Cook said in a letter recently. Additionally, Harbour was demoted from the FTSE 100 index to the 250 with the changes taking effect from the start of trading on December 19. Harbour’s share price drop also pushed the company to speed up its work on diversifying its portfolio worldwide as the UK-focused firm has been hard hit by the windfall tax.

The Rising Risk Of Russian Oil Spills In Scandinavia - The narrow waterway between Denmark and Sweden – a key chokepoint for oil supply from Russia’s western ports – will see the risk of oil spills increase when the EU sanctions against Russian oil exports by sea enter into force at the end of this year. The UN agency International Maritime Organization (IMO) and the Danish maritime authorities strongly recommend the use of a specialized pilot on ships passing through the Danish straits with its many islands. Although not obligatory, the recommendation is widely followed by the industry, with pilots being used on 95% of all 196 oil tankers that crossed the Great Belt, the main channel in the straits, last month, per data from the Danish Maritime Authority cited by the Financial Times.However, the EU sanctions against Russian oil exports by sea would in theory ban the provision of EU maritime transportation services to vessels carrying Russian oil, including specialized pilots from Denmark to help navigate the Danish straits. This, if not addressed, could raise the risk of dangerous and environmentally-disastrous oil spills from ships that would not use a specialized pilot or try to go dark and circumvent the sanctions“Failure to comply with the rules and recommendations of the IMO will not only pose an environmental risk to Danish territorial waters. It will also pose a risk to the safety of navigation and the crew members on board the ships,” the Danish Maritime Authority told FT.The authority and the IMO “highly recommend” the usage of pilots on ships traveling through the Danish straits, but still, the Danish Maritime Authority told Bloomberg Opinion columnist Javier Blas earlier this month: “In conclusion, Denmark cannot prevent oil tankers from passing from the Baltic Sea to the high seas.” Analysts believe that there could be a compromise or some sort of solution to this situation because it’s estimated that around 1.5 million barrels per day (bpd) of Russian crude passes through the Danish straits from Russia’s Baltic Sea ports en route to the Atlantic.

Norway, Germany Propose NATO Subsea Asset Surveillance Center - Norway Prime Minister Jonas Gahr Støre and German Chancellor Olaf Scholz agreed to propose that NATO should establish a surveillance center to improve the protection of subsea infrastructure, the Norwegian government has announced. “Chancellor Scholz and I have taken an informal initiative today to improve the protection of subsea infrastructure,” Støre said in a statement posted on the Norwegian government’s website. “We are suggesting that NATO should establish a dedicated surveillance center for this purpose,” he added. In the statement, the Norwegian government said subsea infrastructure is vital for the overall European economy “and for our security” and noted that further action is needed to protect this infrastructure. “Norway feels a special responsibility for security of natural gas supply in Europe. It is vital to maintain gas supplies,” the government said in the statement. “Norway, together with its allies, has taken a number of steps to protect gas infrastructure. However, countries and industries need to share more information, and civilian and military actors should work more closely together,” the government added. In a statement posted on his Twitter page, Scholz said, “the attack on the Nord Stream pipelines in the Baltic Sea showed that our critical infrastructure must be protected more comprehensively”. “NATO should take on more tasks in protecting the critical infrastructure in the sea, Jens Stoltenberg and I agree on that,” he added.

Will Full Gas Stores Save Europe From An Energy Emergency? - The European Union has spent most of this year importing natural gas from any source available, including sanctioned Russia, after it sanctioned it and began preparing for the time when Russia will turn off the gas tap, which it did, on Nord Stream 1, at least, in the summer. The media have spent that time citing politicians, businesspeople, and commentators and fueling fears that winter in Europe this year will likely be harsh, however much gas there’s in storage. But it seems there’s plenty of gas in storage. If only that were enough for comfort Earlier this month, Reuters’ John Kemp wrote in a column that Europe had completed a record-long gas storage refill season, saying storage inputs likely peaked around mid-November. The longest and largest refill season on record, he wrote, was probably over, but over its length, European countries had managed to stock up well on natural gas ahead of winter.That was certainly good news, especially coupled with a mild October and much of November, which meant naturally lower consumption rather than attempts to mandate lower consumption. This week, Kemp wrote another column that cited data showing it pretty likely that Europe might end up coming out of winter with some gas still left in storage—quite a bit of it, in fact. But there are conditions. The mild weather that was a big reason why Europe has the levels of gas in storage it does at this time of year will also be a big reason for Kemp’s forecast to materialize. The problem with the weather is that even if the European winter is mild, it cannot be mild enough in December and January to prompt the same energy consumption in October. Simply put, it’s never as warm in January as it can sometimes be in October. And this means that demand for heating energy will inevitably increase next month and the month after. And this will mean higher gas consumption in countries that rely on it for heating purposes. And this, in turn, will mean storage drawdowns. Yet, with record levels of gas in storage, this should not be a cause for worry, although it seems to be for some German officials. The head of the country’s energy regulator, Klasu Mueller, for instance, warned in early October—when a cold spell pushed energy consumption higher—that “We will hardly be able to avoid a gas emergency in winter without at least 20% savings in the private, commercial and industrial sectors.” “The situation can become very serious if we do not significantly reduce our gas consumption,” he also said, even though Germany was at the time filling up its gas storage facilities steadily and discussing with its fellow EU members emergency measures such as joint gas buying and gas sharing. Then, in November, Reuters quoted Mueller as saying that Germany’s gas storage could empty in a matter of days if the weather gets very cold. “Just a few freezing cold days are enough for a dramatic increase in gas consumption,” he said. When he said it, gas storage levels in Germany had reached 99.3 percent. Indeed, everyone who has spent any amount of time in a temperate climate during the winter knows that when it’s cold, few would have the strength of character to freeze instead of turning up the thermostat. According to Kemp, high prices will be a natural deterrent for gas consumption but, again, when people are cold, the one thing they can think about is getting warm, not what the price of gas is. It’s either that or a lot of people with cold-related health problems all at once. A lower consumption is also among the factors that Reuters’ market analyst notes as necessary for Europe to end winter with a decent level of gas in its storage caverns. So, the natural deterrent of high prices will not be enough to keep consumption low, and that is, as noted above, to be expected. The other condition Kemp sees as necessary for Europe’s gas storage comfort in three months is the continued flow of Russian gas via Ukraine. It seems despite its best efforts, Europe still very much relies on Russian gas.

Hot Air Versus Hot Cash – The Europeans Prefer Russian LNG To US LNG - Since the war began in February, Ursula von der Leyen did not say a true word until November 30, when she announced that Ukrainian military deaths had reached more than 100,000, and civilian fatalities more than 20,000. Within hours these numbers were removed from the published record of her speech. Von der Leyen’s admission implied the war toll of Ukrainian wounded is more than 300,000, and that the sum of military and civilian casualties has already reached half a million. Von der Leyen was confirming Russian estimates and contradicting the Kiev regime’s propaganda.In September von der Leyen announced her support for a price cap on the international trade in exports of Russian pipeline gas and liquefied natural gas (LNG). Last month she said the European Union is “ready to go” with a price cap on Russian oil exports. However, the European and Asian gas and oil trade is not only contradicting what von der Leyen is claiming; it is demonstrating they are profiting from her public lies. In the gas market there is new evidence that the French, Dutch and Belgian governments are allowing the purchase of record volumes of imported Russian LNG, and the re-export of this gas at a profit to other European states, including Germany. The arbitrage – that is, the profit from buying Russian LNG at the Russian selling price and then reselling it at a premium to European consumers – is so lucrative, the Chinese are diverting their contracted volumes of Russian LNG to Europe. Olga Samofalova, the energy market analyst at Vzglyad , reported yesterday on how the markets are defeating the sanctions.While pipeline gas supplies from Russia are under scrutiny, the European Union (EU) is quietly buying up more and more volumes of the other Russian gas – that is, liquefied natural gas (LNG). Europe’s costs of importing Russian LNG have soared to record levels, Bloomberg has discovered. How did Russia start supplying more liquefied natural gas to Europe and, most importantly, why do the Europeans themselves see nothing terrible in this?As you know, Brussels has imposed a Russian coal embargo; an oil embargo will start operating in a week. A number of countries have refused pipeline gas supplies; others have let technical and bureaucratic problems of the “Northern Streams” take their course. They claim not to have noticed the destruction of the Nordstream pipelines or the way in which the Ukraine has been so unaffected by the present situation that it has restored the transit volumes of gas across Ukrainian territory.At the same time, Europe’s costs for importing Russian LNG in 2022 have soared to a record level, according to Bloomberg. The EU has increased the purchase of LNG from Russia by about 40% over this year. The EU spent a record €12.5 billion ($13 billion) on Russian LNG from January to September – five times more than a year earlier. This is a bitter pill for many countries of the bloc, which imposed tough sanctions on the Kremlin in order to deprive it of funds to conduct its military operations in Ukraine, the western news agency writes.

Winter Chill Exposing Europe Gas Shortage - The winter chill is exposing Europe’s structural gas shortages, according to a new report from BofA Global Research. “Winter weather has ushered in seasonal heating demand; more than doubling European gas consumption versus the summer months,” analysts at BofA Global Research stated in the report, which was sent to Rigzone. “Inventories are now in full withdrawal mode and TTF day-ahead gas prices have jumped 7x versus recent lows. Even full European inventories can barely cover two months of peak winter demand alone, emphasising our view that daily flows are of much greater significance to structural market balances,” the analysts added. “Until new LNG supply hits the market in 2025/26, we see little tangible relief, outside of seasonality, to exceptionally tight LNG markets and by virtue higher-for-longer European pricing. We reiterate Buy ratings on Equinor, Shell, TotalEnergies, Harbour and Energean as key gas market beneficiaries,” the analysts continued. In the report, BofA Global Research analysts estimated that Europe will be physically short of around 70 billion cubic meters across 2023 in the absence of demand destruction, “even when maximizing practical LNG import capacity”. “The only balancing item to this is demand destruction in our view, for which persistently high price are required to drive,” the analysts said in the report. In a separate market note sent to Rigzone this week, Rystad Energy Senior Analyst Zongqiang Luo highlighted that European temperatures had continued to decline in the first week of December. The analyst outlined that this development pushed weekly average storage withdrawals “to some 470 million cubic meters per day and LNG imports to a record monthly high of 11.4 million tons”. Luo also highlighted in the note that a new long term LNG deal was signed between Sempra and Ineos, “boosting supply to Europe’s gas market”. In another market note, Rystad’s Senior Analyst Fabian Rønningen said Europe’s cold snap saw a gas demand surge, “with the UK being the highest priced market as wind generation falls”.

Without Russian Gas LNG Market Faces 3 Years Of High Prices |- European winter is looking better than previously hoped, but it’s been at a severe cost of extremely high prices, lower affordability for consumers, and a weakened economy. According to data from Wood Mackenzie, high prices have hit demand hard – down 22% for non-power sectors year-on-year from July to October – and pulled in LNG supplies destined for Asia. This rebalancing, combined with warm weather in recent weeks, has kept storage 93% full which is much higher than the normal 80% for early December. Cold weather is now the principal risk this winter, but WoodMac believes there should be enough gas, barring an exceptionally long and cold winter. But, with absent Russian gas, the market faces three more years of elevated prices and the repeat cycle of refilling storage with alternative sources of imported pipe gas and LNG in the summer, managing demand through the year and hoping for the best each winter. It’s only in calendar 2026 that relief finally arrives with sizeable new supplies of LNG. Until then, there will be a compounding effect of high prices on consumers and economic growth. One of the reasons for this is the fact that the world is in the early stages of an LNG boom cycle. WoodMac claimed that global supply would increase by 45% by 2030. In the last two years, new projects that will deliver 78 mtpa of supply have been sanctioned, and another 90 mtpa will be sanctioned from 2023 to 2025. Around $400 billion in investments is required in liquefaction, shipping, and regasification alone as well as multiples more on upstream gas. Two-thirds of the nearly $200 billion liquefaction spend is destined for plants in North America. The new volumes will relieve the pressure on the system and bring prices down from today’s exceptional levels. There is even some risk of oversupply that could result in very weak prices temporarily as projects ramp up between 2027 and 2029. “The investment in gas infrastructure getting underway across Europe will be critical. New regas capacity and interconnectors should ease the bottlenecks exposed this year and help gas to flow to the right places at the right time. With Europe increasingly dependent on imported LNG in gas and power markets, price volatility is here to stay. Europe will continue to compete with Asia for LNG supply at times of high demand. We expect European gas prices to settle around $9 to $10/mbtu, structurally higher than before the war, to reflect these factors,” Woodmac said. LNG is still a longer-term growth story Gas and LNG will play a critical role in achieving net zero by 2050 by displacing higher carbon-intensity coal in developing economies. But that will only happen if LNG is more affordable than it is today – gas prices must come down. Woodmac expects LNG demand to grow by 200 mtpa, or 50%, over the next 10 years. Asia accounts for two-thirds, much of it in China and India as well as in Pakistan and Bangladesh where the domestic gas supply is declining. In contrast, LNG imports to mature Asian gas markets such as Japan and South Korea are set to decline as they diversify their energy mix towards renewables and nuclear. Europe is still a hot market with LNG demand jumping 60% in 2022 and set for a further 25% growth by 2028. After that though, in the company’s latest view, demand declines quite steeply through the 2030s as the EU accelerates its push to low-carbon energy. There is further downside risk if the EU’s policy achieves its ambitious REPowerEU goals.

European Union officials set Russian oil price cap at $60 a barrel - The European Union on Friday agreed to cap Russian seaborne oil prices at $60 a barrel, after several days of intense negotiations over an appropriate level. The announcement comes after the G-7 group of advanced economies agreed in September to impose a limit on Russian seaborne crude and therefore constrain revenues the Kremlin makes from the commodity. However, details on how the cap would work in practice have been debated and hashed out since that point. Russia, amid its onslaught in Ukraine, has warned that an oil price cap could wreak havoc on the energy markets and push commodity prices even higher. The price limit will be reviewed regularly to monitor its market ramifications, but it should be “at least 5% below the average market price,” an EU document with details of the cap said. Negotiations had been held up by Poland, with ministers in Warsaw scrutinizing but then agreeing to the 5% adjustment mechanism. A formal announcement is expected Sunday. Energy analysts have warned that the G-7 will need support from other major buyers if the cap is to be effective. China and India, for instance, increased their purchases of Russian oil following the invasion of Ukraine to benefit from discounted rates offered by Moscow. Kadri Simson, European commissioner for energy, told CNBC in September that China and India should support the measure. “It is unfair to pay excess revenues to Russia,” Simson said at the time. But there seems to be little appetite from these nations to comply with the cap. India’s petroleum minister, Shri Hardeep S Puri, told CNBC in September he has a “moral duty” to his country’s consumers. “We will buy oil from Russia, we will buy from wherever,” he added.

Russian oil selling at $79/barrel in Asia on Monday, well above price cap - (Reuters) - Russia's ESPO oil blend from the Far Eastern port of Kozmino was selling for around $79 a barrel in Asian markets on Monday - almost a third higher than the price cap imposed on Russian oil by the G7 and European Union - according to Refinitiv data and estimates from industry sources. Russia exports up to 65 million tons of ESPO Blend oil per year via the Eastern Siberia-Pacific Ocean (ESPO) pipeline, including up to 35 million tons through the port of Kozmino.

EU Embargo of Russian Oil and G7’s Price Cap Take Effect - The New York Times -Europe and the United States started enforcing on Monday two of the toughest measures aimed at curbing Russia’s income from oil, the principal source of cash used to fund its nearly 10-month-old war in Ukraine. But there was no drastic impact on oil markets — prices were largely unchanged by late afternoon — and that was by design. The first measure, a price cap initiative led by the United States, sets a top price of $60 per barrel for Russian crude, and was endorsed by the Group of 7 countries, Australia, and the European Union. The second is an embargo that prohibits European Union countries from buying most Russian crude as of Monday. It was a step that the bloc had agreed to months ago but that was phased in with exceptions to prepare member nations. Although some countries like Poland and Estonia were bent on punishing Russia with a far lower price cap — a move that some feared would prompt the Kremlin to slash production — the U.S. approach seeks to gradually limit Russia’s oil revenues while also providing enough financial incentive to keep the crude flowing onto the global market, avoiding oil shocks. The price cap program prohibits firms that play a key role in servicing Russian oil exports — like Greek tanker companies and Europe-based insurers — from dealing with cargoes sold above the $60-a-barrel limit. That cap roughly matches what buyers are said to be paying for Russian crude, a discount of almost $20 a barrel from Brent crude that buyers have demanded since Moscow’s invasion of Ukraine in February. Dig deeper into the moment. Special offer: Subscribe for $1 a week. The bet is that despite bluster from the Kremlin, Russia will keep pumping oil, and major customers for Russian crude, like refiners in China and India, will see a benefit in the combination of low prices and a relatively stable global oil market.

The West just scrambled the oil market. What happens next is up to Russia | CNN – Most Russian crude oil exports to Europe are now banned, marking the boldest effort yet by the West to pile financial pressure on President Vladimir Putin as his brutal war in Ukraine enters its tenth month. The oil embargo, which was agreed upon in late May, took effect in the European Union on Monday. It was accompanied by a new price cap on Russian crude set by G7 countries. That’s designed to limit the Kremlin’s revenues while allowing countries such as China and India to continue to buy Russian oil, provided they don’t pay more than $60 a barrel.What happens next will likely hinge on the response from Moscow, which has vowed not to cooperate with the price cap and could slash its production, rattling global energy markets. Global crude prices were up 2.6% on Monday as investors watched nervously for the next move. The European Union now prohibits Russian crude oil imports by sea, setting up the bloc to have phased out 90% of oil imports from Russia. It’s a huge move given that Europe received roughly a third of its oil imports from Russia in 2021. More than half of Russia’s exports went to Europe 12 months ago.There are a few exceptions. Bulgaria received a temporary carve-out. The embargo also doesn’t target imports via pipeline. That means the Druzhba pipeline can continue to supply Hungary, Slovakia and the Czech Republic. (Germany and Poland are working to end pipeline imports from Russia as soon as possible.)But the embargo is significant. In 2021, the EU imported €48 billion ($50.7 billion) worth of crude oil and €23 billion ($24.3 billion) of refined oil products from Russia. Two-thirds of those imports arrived by sea.A ban on Russian refined oil products, such as diesel fuel, imported by sea will launch in early February.

Tankers seen heading to Russia as oil price cap goes into effect on exports -Two tankers were heading to Russia on Monday expecting to be filled with Russian crude as a price cap on its oil exports from a coalition of Western countries went into affect. On Friday, the European Union agreed to cap Russian seaborne oil prices at $60 a barrel, aiming to limit Moscow’s revenues and curb its ability to finance its invasion of Ukraine. Russian President Vladimir Putin and high-ranking Kremlin officials have repeatedly said that they will not supply oil to countries that implement the price cap. In comments published on Telegram following the cap being agreed upon, Russia’s embassy in the United States criticized what it said was the “reshaping” of free market principles and reiterated that its oil would continue to be in demand despite the measures. But while Russia is moving forward on its vow to not sell its oil to countries that implement the price cap, it is not being deterred in finding buyers for its oil. The G7 price cap will allow non-EU countries to continue importing seaborne Russian crude oil, but it has to be sold for less than the price cap. Trade intelligence firm VesselsValue, which tracks the trade of Russian oil, told CNBC that there has been a substantial decrease in Russian crude as European imports with alternative markets instead being sought out. “This is expected to carry on into December as the strong sanctions begin,” said Peter William, trade product manager at VesselsValue. “Russia has potentially found substitute markets for their crude with both India and China increasing seaborne imports from Russia.” Jacques Rousseau, managing director of global oil and gas at ClearView Energy Partners, told CNBC there is a disconnect between the U.S. Energy Information Administration and OPEC Russian oil production forecasts. “When comparing 4Q 2022 to 1Q 2023, the EIA projects a decrease of ~1.35 MM bbl/d vs. OPEC’s forecast of a ~0.85 MM bbl/d decline,” said Rousseau. “The magnitude of the quarter-on-quarter Russian oil production decline could be the difference between a global balance shortfall or surplus in 1Q 2023, and whether or not OPEC+ needs to reduce its production targets again.” MarineTraffic is seeing two empty tankers heading to Russia. One is the tankers is Minerva Marina, sailing under the Maltese Flag. The other is the Moskovsky Prospect, sailing under the Liberian Flag, and came directly from Bombay, India. Vessel traffic and tanker gridlock AIS data which tracks vessel traffic is showing a number of tankers in the Black Sea, mainly crude and chemical tankers from Russia which are in transit and have listed various locations as their destinations, including India, the UAE, and China, according to a MarineTraffic spokesperson. Meanwhile, tanker gridlock is building as a result of Turkey demanding tankers have proof of insurance to travel through Istanbul in the Bosphorus Strait.

Oil tanker jam forms off Turkey after start of Russian oil price cap – FT - (Reuters) - A traffic jam of oil tankers is forming off the coast of Turkey after the start of the cap on prices of Russian crude, the Financial Times reported on Monday. The report said four oil industry executives said Turkey had demanded new proof of full insurance coverage for any vessels navigating its straits in light of the Russian oil price cap. A $60 per barrel price cap on Russian seaborne crude oil took effect on Monday, the latest Western measure to punish Moscow over its invasion. The agreement allows Russian oil to be shipped to third-party countries using tankers from G7 and European Union member states, insurance companies and credit institutions, only if the cargo is bought at or below the $60 per barrel cap.

Millions of Barrels of Oil Halted Near Turkey - A backlog of oil tankers at the Turkish straits continues to build up as negotiations failed to produce a solution to an insurance glitch caused by sanctions on Russian crude. Twenty six tankers holding more than 23 million barrels of oil from Kazakhstan were unable to pass the Bosphorus and Dardanelles straits as of Wednesday, shipping data compiled by Bloomberg showed. The waterways are vital chokepoints for the flow of crude and other commodities from the Black Sea. Kazakh authorities estimated a smaller backlog. Late last month, Turkey announced that passing tankers would have to provide letters from their insurers proving they were covered to navigate the straits, through which almost 700 million barrels of crude flowed in the past year. Turkey’s move was a response to European Union sanctions against Russia that bar insurance of vessels if the oil they’re carrying costs above $60 a barrel. US and UK officials are pushing for Turkey to reconsider the proof-of-insurance requirement, especially given that cargoes from Kazakhstan are not subject to sanctions. So far they’ve been unsuccessful. The US Treasury Department, which devised the so-called price cap for Russian crude to soften sanctions, said in a statement Wednesday that Deputy Secretary Wally Adeyemo told Turkish Deputy Foreign Minister Sedat Onal that the program only applies to oil of Russian origin and “does not necessitate additional checks.” “Both officials highlighted their shared interest in keeping global energy markets well-supplied by creating a simple compliance regime that would permit seaborne oil to transit the Turkish straits,” the Treasury Department said in the statement. All Kazakh tankers and cargoes have been insured and the companies providing the cover — mainly British insurers - are holding talks with Turkish authorities, news agency Tass reported Thursday, citing Magzum Mirzagaliev, chief executive officer of national producer NC KazMunayGas. He estimated that only eight to 10 of the tankers stuck in the Turkish straits are “related to Kazakhstan.” A local port agent report said that only one laden tanker — the Vladimir Tikhonov — has passed through the straits since Turkey’s new rule entered into force. That ship is thought to have had Russian cover. Until the insurance impasse is resolved, it’s impossible to estimate when the vessels might be allowed through, the agent said. As of Thursday morning local time, the situation remained unresolved, it said. For insurers, issuing the documentary evidence is both an extra piece of bureaucracy, but it also sets a potential precedent that other locations might seek to follow. Tankers often end up waiting a several days at the straits at this time of year anyway because of shortened daylight hours for transit and bad weather.

Russian oil sanctions fuel boom for old tankers (Reuters) - The market for old oil tankers is booming, and it's all down to efforts by Western nations to curb trade in Russian crude.As Western shipping and maritime services firms steer clear of Russian oil to avoid falling foul of sanctions or harming their reputations, new companies have leapt into the void, and they're snapping up old tankers that might normally be scrapped.The European Union banned all seaborne Russian crude imports from Dec. 5, with a fuel import ban to follow in February. It also banned companies and individuals in the bloc from providing financing, brokerage, shipping and insurance services to ship Russian oil elsewhere if the crude was bought above a price cap of $60 a barrel that came into effect on Monday.In recent months, ageing tankers have been sold by Greek and Norwegian owners for record prices to pop-up Middle Eastern and Asian buyers taking advantage of sky-high charter prices for vessels willing to ship Russian oil to India and China.Tanker management companies such as Fractal Shipping, run out of Swiss financial hub of Geneva, are reaping the rewards.In less than a year, Fractal has put together a fleet of 23 oil and fuel tankers bought recently by owners in Dubai. Most are taking Russian crude from Baltic and Black Sea ports to Asia, Refinitiv Eikon ship tracking showed.Chief Executive Mathieu Philippe said he launched the idea for Fractal a year ago, betting that the global tanker fleet was getting stretched and that both the cost of vessels and freight rates would inevitably rise from pandemic lows.

Shipping Costs for Russian Oil Soar - Shipping costs for Russian crude are skyrocketing as more tanker owners shun the trade days before stricter European Union sanctions take effect. Owners who are still willing to load Russian crude are attempting to charge more for the risk. Baltic Sea-to-India rates are being discussed at about $15 million -- or $20 a barrel --- for loadings after Dec. 5 when new EU restrictions kick in, said shipbrokers. That’s a sharp increase from $9 million to $11.5 million before. The surge in costs reflects the challenges faced by suppliers of Russian crude ahead of the deadline when the EU, including some of the world’s top tanker owners in Greece, will stop extending shipping and other services for oil produced by the OPEC+ nation. Fewer available ships and the need for Russian oil to be diverted from traditional buyers in Europe to new ones in Asia and the Middle East are also contributing to higher rates. The exorbitant freight is in turn eroding the value of Russian crudes, such as the flagship Urals grade, at their load port as sellers ensure that the final price of delivered oil remains competitive against alternatives. Exports from the Baltic Sea, where Urals loads, rely on small to mid-size vessels such as Aframax and Suezmax tankers. Participants in the global shipping market are also waiting for details on an oil cap proposed by the Group of Seven countries that could exempt shipments from EU sanctions as long as they trade below the price limit. Members of the 27-nation bloc are closing in on a deal to cap the price at $60 a barrel this week. Russia earlier said that it won’t sell oil and gas to nations that join the cap. The lack of clarity surrounding exemptions is paving the way for a shift to the so-called dark fleet, or tankers held by undisclosed owners who are willing to continue handling Russian oil despite the threat of sanctions. These ships mostly comprise of older vessels and many with a track record of dealing with sanctioned regimes such as Iran. It’s unclear if Baltic-to-India freight rates will hold at around $15 million should Urals crude fall under the price cap, nor is it clear if any bookings have been fully concluded at that level. Meanwhile, some mid-sized tankers typically used to haul cleaner refined fuels are considering a switch to crude to tap the strengthening rates. The EU is set to roll out sanctions targeting logistical, banking and insurance services for Russian oil-product trades in February.

Russian oil cap will work, EU ministers insist, despite Kremlin opposition and broad skepticism — — A price cap on Russian seaborne oil will work, EU ministers told CNBC, despite attempts from the Kremlin to escape sanctions and a broad market skepticism over the measure. The EU, alongside the G-7 and Australia, agreed on Friday to limit the purchases of Russian oil to $60 a barrel as part of a concerted effort to curtail Moscow’s ability to fund its war in Ukraine. The price cap came into force on Monday. In essence, the measure stipulates oil produced in Russia can only be sold with the necessary insurance approval at or below $60 a barrel. Insurance companies are mostly based in G-7 nations. However, Russia has already said it will not sell oil to nations complying with the cap and that it is ready to cut production to maintain its revenues from the commodity. In addition, reports suggested that it has been putting together a fleet of about 100 vessels to avoid oil sanctions. Having its own so-called “shadow fleet” would allow the Kremlin to sell its oil without needing insurance from the G-7 or other nations. When asked if the oil cap can work in reducing Russia’s oil revenues, Irish Finance Minister Paschal Donohoe said, “Yes, it can.” It is “the right message at the right time,” he said in an interview with CNBC on Monday. One of the big open questions is the role of India and China in the implementation of this price cap. Both nations have stepped up their purchases of Russian oil in the wake of the invasion of Ukraine, and they are reluctant to agree to the cap. India’s petroleum minister reportedly said Monday that he “does not fear” the cap and he expects the policy to have limited impact. However, France’s Finance Minister Bruno Le Maire told CNBC on Monday: “I think it’s worth trying.” “Then we will assess the consequences of the implementation of this oil cap,” he added. The level of the cap will be reviewed in early 2023. This revision will be done periodically and the aim is to set it “at least 5% below the average market price for Russian oil,” according to the agreement reached by EU nations last week. European Commission President Ursula von der Leyen said over the weekend that the limit on oil prices will help the bloc stabilize energy prices. The EU has been forced to abruptly reduce its dependence on Russian hydrocarbons due to the Kremlin’s war in Ukraine. Market players, however, remain wary about the integrity of the policy. Analysts at Japan’s Mitsubishi UFJ Financial Group said in a note Monday that the scale of the price cap’s impact “remains ambiguous.” They added, “we have been sceptical on the practicalities of its success.” There is a risk that nations buy Russian oil at the agreed cap but then resell it at a higher price to Europe, for example. This would mean that Russia would still make money from the commodity sales while Europe would be paying more at a time when its economy is already slowing down. “The introduction of the cap on the price will probably not remove all the volume, some will find its way to the markets,” Angelina Valavina, head of EMEA Natural Resources and Commodities at the Fitch Group, told CNBC’s “Street Signs Europe” Monday. Oil prices traded higher Tuesday morning in London.

Europe’s Energy Outlook Imperiled By Policy Myopia - The G7 facilitated price fix on Russian oil exports will likely embolden Moscow to use the illicit markets. The Kremlin could also evade sanctions by leveraging ties to the illicit market or ties with other marginal actors in the global south, but none are likely to result in the scale of the trade needed to offset problems with Europe. There is a precedent for this as Russian oil and gas businesses have hidden behind front companies that are not sanctioned and/or conducted business via third-party nations. Complex ship-to-ship transfer methods and obscure sailing patterns assist in this endeavor, where Russian energy exports are snuck into Europe under the auspices of being sold by a reputable business. Other nations looking to cash in on Russian sanctions will also participate, including India, Turkey, Qatar, and Saudi Arabia. Iran, an already sanctioned nation, will likely play a significant role, helping to facilitate illegal oil shipments through its various subsidiaries. Taken together, these pose a credible threat to the sanction regime. Even if winter temperatures are warmer than normal, Europe must collectively address its energy issues by encouraging technological advancement and productive dialogue at national and union levels. German President Olaf Scholz recently brokered a compromise between the Social Democrat and Green parties, ordering two of the three remaining nuclear German power plants to remain operational until mid-April. Yet, Germany’s stark reliance on Russian gas – up to 55% in 2021, and commitment to phase out the nuclear, should have warranted the diversification of energy sources. Now European energy producers such as Centrica, Fortum, Uniper and EDF are suffering. This deal could have easily included nuclear power, of which Germany derives only 6% of its energy. New nuclear technologies include small modular reactors, SMRs, into which luminaries such as Bill Gates and others are investing. Pebble bed reactor is another innovative technology that encourages higher efficiency electricity production through the use of enriched fuel pebbles in graphite reactor cores. Though capital-intensive, investment in these systems provides safer long-term solutions.Divisions between the far-right and far-left in Europe will impact any attempt at streamlining both energy security and efficiency. Political parties on the margins, especially in France and Germany, have voiced assertions that nuclear energy is unsafe even if crucial to thwarting reliance on Russia. The French anti-Atlanticist left-wing political coalition, led by Jean-Luc Melenchon, has lobbied for heavy nuclear energy restrictions, despite 70% of France’s electricity being sourced from atom-splitting While the United States is going out of its way to assist Ukraine and supply LNG and coal to a Europe facing Russian aggression, the European Union must look within to collectively wrest control of reliance on Russian energy and rethink anti-nuclear energy policies which caused today’s fiasco. Solar and wind are not a panacea due to the lack of storage and intermittency. The technology might catch up, but it would take a couple of decades. Though some may be discouraged by nuclear power or LNG terminal expansion, alternative security scenarios, especially those involving emboldening Russia and China, are far bleaker. Europe needs leadership, level-headed and balanced energy policies, and massive capital investment in the energy sector modernization, making electricity abundant, reliable, and affordable. Above all, it needs to divorce itself from energy and economic dependence on hostile great powers.

Russian Upstream Investments Projected to Plunge - Russian upstream investments are set to plunge by $15 billion this year. That’s according to Rystad Energy, which outlined that sanctions are obscuring the country’s production outlook in a statement sent to Rigzone this week. Before Russia’s invasion of Ukraine in late February this year, upstream investments in Russia were expected to approach $50 billion this year, Rystad noted. This figure is now projected to hit $35 billion, Rystad highlighted. “The financial impact of Western sanctions and the widescale exodus of foreign partners from the Russian oil and gas sector are beginning to materialize,” Rystad said in a company statement. “Investments in Russia’s upstream sector totaled $45 billion last year, rebounding from Covid-19-induced lows of $40 billion in 2020. But as Russia becomes increasingly shut off from the global energy market, investments have sunk well below levels seen in the pandemic-affected years of 2020 and 2021 and will remain subdued until at least 2025,” the company added. The stagnation in investments will lead to a drop in project final investment decisions and force operators to make hard decisions on spending, according to Rystad, which said a significant factor limiting investments is the delay of several large LNG projects. Greenfield investments are set to suffer the largest drop in spending due to the sudden sharp decline in approval activity this year, Rystad noted. Investments in new Russian projects are projected to fall 40 percent from last year - from $13.7 billion to $8 billion. No significant new projects are expected to be sanctioned in Russia next year, but activity will resume in 2024 with the Gazprom-operated Chayandinskoye (Phase 2) gas-condensate field, Rystad outlined. Brownfield investments are expected to drop by 14 percent as oil production has not taken a significant hit, Rystad said. The impact of lower oil demand will be visible next year when brownfield investments will drop by approximately 20 percent compared to 2021, Rystad pointed out.

Petronas Makes Significant Discovery Offshore Malaysia - Petronas Carigali Sdn Bhd (PCSB), a wholly owned subsidiary of Petronas, has announced an oil and gas discovery at the Nahara-1 well in Block SK306, off the coast of Sarawak, Malaysia. The Nahara-1 well was drilled to a total depth of 8,097 feet and encountered hydrocarbons in the Late Oligocene to Middle Miocene aged sedimentary sequences, Petronas revealed, adding that light oil with minimal contaminants was also established after production testing was conducted for the well. “We are excited with this discovery and its impact to the future exploration effort in the surrounding areas,” Petronas Vice President of Exploration, Mohd Redhani Abdul Rahman, said in a company statement. “Nahara-1 is a significant oil discovery by PCSB within the last decade. It is a testament to the vast potential in Malaysia’s prolific basins which remain highly prospective,” he added. “The discovery also reinforces PCSB’s current exploration strategy of renewing focus in its exploration efforts in Malaysia’s basins,” the Petronas vice president continued. PCSB is the operator of the block, with a 100 percent participating interest in its production sharing contract. Last month, Petronas announced its first oil discovery in Brazil’s Sépia Field. The net oil column in the 4-BRSA-1386D-RJS well is one of the thickest ever recorded in Brazil, according to Petronas, which dubbed the find “significant”. In September Petronas announced a new gas discovery in the Central Luconia Province offshore Malaysia. During the same month, the company announced its first oil discovery in Suriname. Petronas outlined that the Malaysia find hit a more than 360-foot gas column in Miocene Cycle IV/V pinnacle carbonate reservoirs, and firmed up more gas resources within Block SK320, and described the Suriname discovery as an important milestone for Petronas in unlocking deepwater hydrocarbon resource from its exploration ventures.

Analyst Looks at Latest Oil Price Moves - After a nine-day downtrend, WTI prices stair-stepped to a three-week high this week on a possible further output cut by the OPEC+ group, Covid-19 lockdown easing in China, a large inventory draw, an expected halt to SPR releases, and a weaker U.S. dollar. Brent crude, however, managed to recover from a 10-month low to a two-week high, aided by the prospect of a cap on Russian oil which could lead to less of the Urals hitting the global market. WTI has risen to as high as $81.50 per barrel recently while Brent approached $89.40. Both grades look to end higher week over week. The only bearish signal of the week appeared to be the continuing increases in gasoline and distillate stocks. This week’s EIA Weekly Petroleum Status Report indicated that inventories of commercial crude fell by a substantial 12.6 million barrels to 419 million, slipping to eight percent below normal for this time of year. The API reported that inventories declined 7.9 million barrels, while the WSJ survey predicted a decrease of 2.1 million barrels. Refinery utilization ticked-up to 95.2 percent vs 93.9 percent the prior week. Total motor gasoline inventories rose by 2.8 million barrels to 214 million barrels, now at four percent below average. Distillates increased 3.5 million barrels to 113 million barrels, rising to 11 percent below normal. Crude oil stocks at the key Cushing, OK, hub fell 415,000 barrels to 24.3 million barrels, or 31 percent of capacity. Imports of crude oil were six million barrels per day, while crude exports were 4.95 million barrels per day, the highest level in several weeks. Exports of refined products were 6.8 million barrels per day, up from 5.7 million barrels per day. Volumes withdrawn from the Strategic Petroleum Reserve were 1.4 million barrels, which dropped the total inventory to 389 million barrels. U.S. oil production held at 12.1 million barrels per day vs 11.6 million barrels per day last year at this time. September oil production, at 12.3 million barrels per day average, was the highest since March 2020. Venezuelan crude may return to U.S. refiners now that Chevron has been cleared to resume oil production in that country. The U.S. government wants to double the inventory of heating oil and crude in the Northeast Home Heating Oil Reserves (NEHHOR) to help lower prices and ensure adequate supplies exist. Currently, there is about one million barrels in storage. The OPEC+ group will meet this weekend with market watchers speculating that additional cuts could be announced if Brent stays below $90 per barrel. The Biden administration has approved the Sea Port Oil Terminal, one of four proposed offshore terminals planned to increase U.S. oil export capacity. Once in service, SPOT will be the country’s largest oil export terminal with a capacity of two million barrels per day. The EU Commission is asking member nations to approve a $60 per barrel price cap on Russian oil. All three major stock indexes are higher on the week while the US Dollar index (DXY) fell to its lowest level in 16 weeks, aiding the oil rally.

OPEC+ to consider deeper oil output cuts ahead of Russia sanctions and proposed price capOPEC and non-OPEC oil producers could impose deeper oil output cuts on Sunday, energy analysts said, as the influential energy alliance weighs the impact of a pending ban on Russia’s crude exports and a possible price cap on Russian oil. OPEC+, a group of 23 oil-producing nations led by Saudi Arabia and Russia, will convene on Sunday to decide on the next phase of production policy. The highly anticipated meeting comes ahead of potentially disruptive sanctions on Russian oil, weakening crude demand in China and mounting fears of a recession. Claudio Galimberti, senior vice president of analysis at energy consultancy Rystad, told CNBC from OPEC’s headquarters in Vienna, Austria, that he believes the group “would be better off to stay the course” and roll over existing production policy. “OPEC+ has been rumored to consider a cut on the basis of demand weakness, specifically in China, over the past few days. Yet, China’s traffic nationwide is not down dramatically,” Galimberti said. Energy market participants remain wary about the European Union’s sanctions on the purchases of the Kremlin’s seaborne crude exports on Dec. 5, while the prospect of a G-7 price cap on Russian oil is another source of uncertainty. The 27-nation EU bloc agreed in June to ban the purchase of Russian seaborne crude from Dec. 5 as part of a concerted effort to curtail the Kremlin’s war chest following Moscow’s invasion of Ukraine. Concern that an outright ban on Russian crude imports could send oil prices soaring, however, prompted the G-7 to consider a price cap on the amount it will pay for Russian oil. No formal agreement has yet been reached, although Reuters reported Thursday that EU governments had tentatively agreed to a $60 barrel price cap on Russian seaborne oil. “The other factor OPEC will need to consider is indeed the price cap,” Galimberti said. “It’s still up in the air, and this adds to the uncertainty.” The Kremlin has previously warned that any attempt to impose a price cap on Russian oil will cause more harm than good.

OPEC+ agrees to stick to its existing policy of reducing oil production ahead of Russia sanctions -An influential alliance of oil producers on Sunday agreed to stay the course on output policy ahead of a pending ban from the European Union on Russian crude. OPEC and non-OPEC producers, a group of 23 oil-producing nations known as OPEC+, decided to stick to its existing policy of reducing oil production by 2 million barrels per day, or about 2% of world demand, from November until the end of 2023. Energy analysts had expected OPEC+ to consider fresh price-supporting production cuts ahead of a possible double blow to Russia’s oil revenues. The European Union is poised to ban all imports of Russian seaborne crude from Monday, while the U.S. and other members of the G-7 will impose a price cap on the oil Russia sells to countries around the world.. The Kremlin has previously warned that any attempt to impose a price cap on Russian oil will cause more harm than good. Oil prices have fallen to below $90 a barrel from more than $120 in early June ahead of potentially disruptive sanctions on Russian oil, weakening crude demand in China and mounting fears of a recession. Led by Saudi Arabia and Russia, OPEC+ agreed in early October to reduce production by 2 million barrels per day from November. It came despite calls from the U.S. for the group to pump more to lower fuel prices and help the global economy.

Oil prices rose as much as 2% on hopes of China's reopening and as OPEC+ maintains output targets - Oil prices climbed as much as 2% on Monday after China signaled a broader relaxation of Covid curbs, OPEC+ announced its decision not to change oil production targets, and a price cap on Russian oil took effect. Both futures rose more than 2% in early Asia hours after OPEC+ agreed to maintain its current policy of reducing oil production by 2 million barrels per day, or around 2% of world demand from November until the end of next year. Both futures have since pared gains, with Brent crude last trading at $86.12 a barrel, and U.S. West Texas Intermediate futures at $80.53 per barrel. The Group of Seven’s price cap of $60 for Russian seaborne oil and a ban on Russian crude kicked in on Monday. However, economists at National Bank of Australia say it’s “unclear what impact this will have on Russian exports and how Russia will respond.” The Kremlin had previously threatened that it will not supply oil to countries setting and endorsing the price cap. “It is the right decision [for OPEC] to hold steady, especially if you don’t know how much, if at all, Russian production is going to fall after today,” said Amrita Sen, head of research at energy consultancy Energy Aspects. Another analyst is of the view that the price caps are “irrelevant” and that oil prices were mainly moving on other factors, such as the prospect of China’s reopening. “There won’t be any impact unless Moscow goes ahead with its threat and says ’we’re not going to export at X amount or whatever reason but so far we don’t think that’s going to happen,” Citi’s global head of commodities research, Edward Morse, told CNBC. Oil prices were also buoyed by optimism on China’s reopening, based on reports signaling that the world’s largest importer is easing its Covid curbs. “The markets’ been moving because of optimism about China opening, and concerns about the U.S. dollar because the Fed might be reducing the pace at which it’s raising rates.” In early Asia hours, Brent crude futures rose as much as 2.37% to $87.60 a barrel, while U.S. West Texas Intermediate futures traded up over 2.27% at $81.84 a barrel.

Oil Futures Chase Equities Lower on Fear of Fed Rate Hikes-- Reversing an early advance triggered by China's easing of COVID-19 quarantine restrictions, oil futures followed equity markets lower Monday afternoon. That sent both the U.S. and international crude benchmarks 3% lower amid fear the Federal Reserve would continue raising interest rates that will eventually steer the U.S. economy into recession. More evidence of a resilient consumer could be found in November services data released Monday morning by the Institute of Supply Management that showed business activity in the service economy strengthened last month despite efforts by the central bank to drawdown excessive demand. The Business Activity Index registered 64.7% in November, a substantial increase of 9% compared to the October reading, with the headline number for Services PMI clocking in at 56.5%. A reading of 50% separates growth from contraction. The accelerated growth in the service economy was realized on the back of increases in business activity but also employment. The employment index climbed out of contraction territory to 51.5% in November, reflecting consistently strong growth in the labor market. Last month, the U.S. economy added a robust 263,000 new jobs, with notable gains occurring in professional and services industries. What's more surprising, hourly wages for all employees spiked 0.6% from the prior month -- double what economists had expected. These data points are bad news for the Federal Reserve as they suggest the central bank has made little progress so far in cooling off a red-hot labor market along with inflation. Following a Nov. 30 speech by Fed Chairman Jerome Powell, investors largely expect the Federal Open Market Committee to agree on a 0.5% hike in the federal funds rate their Dec. 13-14 meeting. That would mark a step down from a series of four straight 0.75% rate hikes. Former Treasury Secretary Lawrence Summers, however, warned that the Federal Reserve will probably need to raise interest rates more than markets are currently expecting. Further weighing on the oil complex, Saudi Arabia on Monday morning lowered most of its oil selling prices for Asia, its key market, in a sign that demand remains fragile amid continued zero-COVID policies in China. State-controlled Saudi Aramco cut its key Arab Light grade for January sales to Asia by $2.20 to $3.25 per barrel (bbl) above the regional benchmark. The move was in line with analysts' calls for a drop of $2.10, according to a Bloomberg survey. Saudi Arabia's fellow OPEC member Kuwait on Friday said that oil customers were reluctant to boost imports into early next year. There have been reports suggesting that Chinese refiners are pulling back on January oil purchases amid regulatory uncertainty surrounding lockdowns. Saudi Arabia also reduced most of its prices for European customers, while leaving those for the United States unchanged. At settlement, West Texas Intermediate January contract fell $3.05 to $76.93 per bbl, and February Brent futures on ICE declined by $2.89 to $82.68 per bbl. January RBOB futures on NYMEX dropped to $2.2019 per gallon, down by $0.0785, and the January ULSD contract tumbled $0.1687 to $2.9998 per gallon.

Crude oil prices rise after price cap on Russian crude, OPEC+ meeting; Brent hits $83.34/bbl – Oil prices edged higher on Tuesday after a G7 price cap on Russian seaborne oil came into force on Monday on top of a European Union embargo on imports of Russian crude by sea. Brent crude futures LCOc1 had risen 66 cents to $83.34 a barrel by 0108 GMT. West Texas Intermediate crude (WTI) CLc1 rose 70 cents to $77.63 a barrel. Futures fell more than 3% in the previous session after U.S. service sector data raised worries that the Federal Reserve could continue its aggressive policy tightening path. The Group of Seven price cap comes as the West tries to limit Moscow's ability to finance its war in Ukraine, but Russia has said it will not abide by the measure even if it has to cut production. The price cap, to be enforced by the G7 nations, the European Union, and Australia, comes on top of the EU's embargo on imports of Russian crude by sea and similar pledges by the United States, Canada, Japan, and Britain. Meanwhile, the Organization of the Petroleum Exporting Countries and its allies including Russia together called OPEC+, agreed on Sunday to stick to their October plan to cut output by 2 million barrels per day (bpd) beginning in November. The Group of Seven (G7) countries and Australia last week agreed on a $60 a barrel price cap on seaborne Russian oil. In China, more cities eased COVID curbs over the weekend, prompting optimism for increased demand in the world's top oil importer. Business and manufacturing activity in China, the world's second-largest economy, have been hit this year by strict measures to curb the spread of the coronavirus.

Oil price dip towards $74, Omicron concerns dominate -- Oil futures prices dropped toward $73 a barrel on Tuesday after the International Energy Agency (IEA) said the Omicron coronavirus variant is set to dent global demand recovery. U.S. data showing producer prices at 11-year highs reinforced market expectations of faster stimulus tapering by the Federal Reserve, which meets this week. This supported the dollar and weighed on oil, which typically move inversely. Brent crude futures fell 69 cents, or 0.9%, to $73.70. U.S. West Texas Intermediate (WTI) crude futures settled down 56 cents, or 0.8%, at $70.73. The U.S. dollar stayed near one-week highs on Tuesday versus a basket of major currencies, bolstered by the producer prices data. “As some accelerated tapering out of the Fed becomes more likely, US interest rates are apt to lift in pushing additional strength into the dollar in forcing price weakness into the oil,” On Tuesday, the World Health Organization said the Omicron variant was spreading at an “unprecedented” rate, prompting markets to edge lower. “The surge in new COVID-19 cases is expected to temporarily slow, but not upend, the recovery in oil demand that is under way,” the Paris-based IEA said in its monthly oil report. Governments around the world, including most recently Britain and Norway, have tightened restrictions to stop the spread of the Omicron variant. The IEA lowered its forecast for oil demand this year and the next by 100,000 barrels per day (bpd) each, mostly because of the expected blow to jet fuel use from new travel curbs. “The skies are darkening for the oversupply outlook again,” The Asian Development Bank on Tuesday trimmed its growth forecasts for developing Asia for this year and next to reflect risks and uncertainty brought on by the variant, which could also hamper oil demand. On Monday, the Organization of the Petroleum Exporting Countries (OPEC) raised its world oil demand forecast for the first quarter of 2022 and stuck to its timeline for a return to pre-pandemic levels of oil use, saying the Omicron variant’s impact would be mild and brief. OPEC+, which includes OPEC and other producers including Russia, plan to boost supply every month by 400,000 barrels per day (bpd) after sharply cutting output last year. Output in the largest U.S. shale basin is expected to surge to a record in January, according to a forecast from the U.S. Energy Information Administration.

WTI Holds Losses Despite Another Huge Crude Draw - Oil prices tumbled further today as growing concern that US interest rates will stay higher for longer has also increased speculation that economic growth will slow and drag down energy demand. Dollar strength also did not help. “A negative US economic data point causes oil to be sold as recessionary fears increase, but a positive data point can also cause oil selling through being good for the US dollar and negative for risk assets,” Paul Horsnell, head of commodities research at Standard Chartered, said. “There is always interplay between those effects, but in the past three weeks oil has tended to fall after both good and bad economic data.” After last week's huge crude draw, all eyes are back on inventory/supply data for any signals that this drawdown in price is over. API:

Crude -6.246mm (-3.884mm)
Cushing +30k - first build in 5 weeks
Gasoline +5.93mm
Distillates +3.55mm

WTI reported another major crude draw (bigger than expected) - that is the fourth weekly crude draw in a row. On the other hand, Products saw significant builds for the fourth straight week... WTI hovered just above $74 ahead of the API print, and inched higher on the crude draw... Brent broke down below $80 for the first time since January... Traders are “fleeing the market” because of the “absurd” price actions oil has recently experienced, Ed Morse, global head of commodity research at Citigroup Inc., said in a Bloomberg Television interview. “We are getting toward the end of the year, and those who made money this year did not want to lose any.” The oil market’s structure has also been in freefall, with one gauge of US trading at its weakest level in two years, pointing to ample near-term supply.

WTI Slides After Huge Product Builds, Crude Production Rise -- After an ugly slide as Europe opened, oil prices have rebounded as China's rollback of some COVID-19 measures boosted the outlook for energy demand and traders are optimistic that the official inventory data this morning matches API's big crude draw. "Traders have been looking for more positive news when it comes to China's zero-tolerance COVID policies," said Naeem Aslam, chief market analyst at AvaTrade, in a market update. And now "we have heard from the officials about a further easing of those measures," providing support to investor sentiment. Oil's swings overnight have left WTI trading right where it was before the API data. DOE:

Crude -5.186mm (-3.884mm)
Cushing -373k
Gasoline +5.319mm (+2.9mm exp) - biggest build since July 2022
Distillates +5.159mm (+1.9mm exp) - biggest build since May 29, 2020

The official data confirmed API's reporting with a fourth straight week of sizable crude draws and fourth straight week of significant and growing product builds... Gasoline inventories continue to soar amid weak demand heading into the holidays. The four-week moving average of product supplied has plunged by 400,000 barrels a day over the last three weeks. Coupling that with ultra-high refinery utilization has finally given fuelmakers the chance to restock crude product inventories.The four-week rolling average of distillates demand fell to its lowest seasonal level since 2015. US Crude production rose to cycle highs at 12.2mm b/d... WTI was hovering around $74.50 ahead of the official data and slipped lower on the big product builds.. Concerns about the global growth outlook, alongside a soft physical market and falling liquidity have weighed on prices, but Francisco Blanch, head of commodity and derivatives research at Bank of America said in a Bloomberg TV interview that "inventories remain quite low, spare capacity is tight,” “All the demand growth that we forecast for next year is coming from emerging markets.” Traders are “fleeing the market” because of the “absurd” price actions oil has recently experienced, Ed Morse, global head of commodity research at Citigroup Inc., said in a Bloomberg Television interview. “We are getting toward the end of the year, and those who made money this year did not want to lose any.” The oil market’s structure has also been in freefall, with one gauge of US trading at its weakest level in two years, pointing to ample near-term supply.Finally, we note that gasoline pump prices have largely fallen to parity with where they were a year ago, yet demand has continued to lag.

Oil Erodes to 12-Month Lows After EIA Data Fuels Demand Fears - Oil futures settled lower for the fourth straight session on Wednesday, with both crude benchmarks erasing all their gains made this year. The losses came after the weekly inventory report from the Energy Information Administration showed continued soft demand and growing stocks of refined fuels, feeding into concerns over a weakening economy. More evidence of demand destruction could be found in this week's EIA inventory report, showing four-week average distillate consumption in the U.S. dropped a full 9% below last year's level to 3.7 million barrels per day (bpd). Distillate fuel supplied to the U.S. market -- a measure of demand -- remained firmly below 4 million bpd for the fourth straight week through Dec. 2. It must be noted that distillate demand correlates closely with economic activity, particularly in energy-intensive industries. Although the service sector of the U.S. economy regained momentum in November, manufacturing activity posted its first contraction since May 2020, led by a sharp decline in new orders and production capacities. Further details of the EIA's report show demand for motor gasoline stalled for the third consecutive week at 5% below last year's level at 8.3 million bpd despite the beginning of the holiday season. As a result, stocks of gasoline and distillate fuels rose by a massive 11.5 million barrels (bbl) during the week ended Dec. 2, with a 6.2-million-bbl build realized in distillate stocks alone. Supporting elements of the report could be found in crude statistics, with commercial inventories having tumbled 5.3 million bbl in the week ended Dec. 2 to 413.9 million bbl. This marked the fourth consecutive weekly drawdown from commercial oil inventories. Since mid-November, commercial crude inventories have declined by a hefty 26.9 million bbl amid gradual slowdown of a yearlong program of oil sales from Strategic Petroleum Reserves, while refiners reduce stock levels ahead of ad valorem taxes on inventory held at year's end in Texas and Louisiana. The large crude draw was realized as the national refinery run rate increased 0.3% to 95.5% of capacity, the highest utilization rate since August 2019. Crude inputs at refineries increased 53,000 bpd to 16.6 million bpd, a nearly five-month high. Domestic oil production, meanwhile, increased by 100,000 bpd from the previous week to 12.2 million bpd, according to EIA figures. January West Texas Intermediate futures declined $2.24 to $72.01 per bbl -- the lowest settlement on the spot continuous chart since Dec. 21, 2021. February Brent futures on ICE fell $2.18 to settle at $77.17 per bbl -- a 2022 low on a spot continuous basis. January RBOB futures slid to a $2.0772-per-gallon 11 1/2-month low on the spot continuation chart, down $0.0719, and the January ULSD contract declined $0.1350 to an 11-month low $2.7805 per gallon.

Oil Rebounds As China Eases Strict COVID Curbs - Oil rebounded from 2022 lows on Thursday, as China began implementing a more relaxed version of its strict "zero COVID" policy and reports emerged that some tankers carrying Russian oil are facing delays in crossing to the Mediterranean from Russia's Black Sea ports after a G7 price cap came into effect. Benchmark Brent crude futures rose 0.7 percent to $77.71 a barrel, while WTI crude futures were up 1.1 percent at $72.81. Both contracts hit 2022 lows on Wednesday, giving up all of the gains since Russia's invasion of Ukraine, after data from Energy Information Administration (EIA) showed a sharp increase in gasoline inventories in the week ended December 2nd. Recession worries also hurt markets after top U.S. banks warned of a recession in 2023 and China reported weak trade balance figures for November. Three years into the pandemic and following widespread protests last month, many Chinese embraced newfound freedoms today after the country dropped key parts of its tough zero-COVID regime.

Oil Falls on Weakening Demand, Shrugs off Keystone Closure (Reuters) - Oil settled lower for a fifth straight session on Thursday as traders shrugged off the closure of a major Canada-to-U.S. crude pipeline, focusing instead on concerns that global economic slowdowns would slash fuel demand. Brent crude settled at $76.15 a barrel, losing $1.02, or 1.3%. U.S. West Texas Intermediate (WTI) crude settled at $71.46 a barrel, shedding 55 cents, or 0.8%. Canada's TC Energy said it shut its 622,000 barrel-per-day Keystone pipeline, which is the primary line shipping heavy Canadian crude from Alberta to the U.S. Midwest and Gulf Coast, after a spill into a Kansas creek. The line has had several spills since it began operating in 2010. Oil prices rose after the company announced the closure, but the rally dissipated as analysts noted that the U.S. Gulf is likely to have enough inventory to handle short-term outages. Several analysts also said the section of the line that goes to Midwest refiners could be restarted soon. TC Energy has not announced when the pipeline would reopen. "I would tend to think that, any minute here, you're going to see a headline hit the tape that's going to say that Keystone is going to be back sooner rather than later," . The energy markets are weighed down by fears of an economic slowdown, weakening fuel demand amid the prospect of more U.S. interest rate hikes, with the Federal Reserve widely expected to raise interest rates by 50 basis points next week. While U.S. crude inventories fell last week, gasoline and distillate inventories surged, adding to concern about easing demand. Limiting losses was an announcement by China on Wednesday detailing the most sweeping changes to its strict anti-COVID regime since the pandemic began, while at least 20 oil tankers faced delays in crossing to the Mediterranean from Russia's Black Sea ports. The 14-day relative strength index for Brent was below 30 on Thursday according to Eikon data, a level taken by technical analysts as indicating an asset is oversold and could be poised for a rebound. Both Brent and U.S. crude hit 2022 lows on Wednesday, unwinding all the gains made after Russia's invasion of Ukraine exacerbated the worst global energy supply crisis in decades and sent oil close to its all-time high of $147. Western officials were in talks with Turkish counterparts to resolve the tanker queues, a British Treasury official said on Wednesday, after the G7 and European Union rolled out new restrictions aimed at Russian oil exports.

Oil bounces on pipeline shutdown but heads for weekly loss on demand woes -- Oil prices bounced higher on Friday as closure of a major Canada-to-U.S. crude pipeline disrupted supplies, but both benchmarks were headed for a weekly loss on worries over slowing global demand growth. Brent crude futures were at $76.73 a barrel, up 58 cents, or 0.76%, at 0716 GMT, after dropping 1.3% on Thursday. U.S. West Texas Intermediate crude rose 52 cents, or 0.73%, to $71.98 a barrel, having settled 0.8% lower in the previous session. News of an accident closing Canada's TC Energy's Keystone pipeline in the United States prompted a brief rally on Thursday, but prices finally eased as the market took a view that the closure would be brief. More than 14,000 barrels of crude oil spilled into a creek in Kansas, making it one of the largest crude spills in the United States in nearly a decade. Previous spill-induced outages are typically rectified in about two weeks, RBC Capital analyst Robert Kwan said, although the latest outage may prove longer given that it involves a spill into a creek. Oil prices are set to post their biggest weekly drop in months, since traders expect it will be some time before China easing its COVID controls feeds through to demand. And surging infections will likely depress China's economic growth in the next few months, bringing a rebound only later in 2023, economists said. "The market lacks conviction in calling a bottom to crude despite the strong losing streak of the past several sessions," said Vandana Hari, founder of oil market analysis provider Vanda Insights. Thursday's price slump despite two major crude supply disruptions is a bit bewildering, she said. "It is likely exacerbated by thinning trading activity, wherein the few remaining actors are playing it safe by continuing to sell and steering clear of the long side." Also on the downside, the U.S. economy is heading into a short and shallow recession over the coming year, according to economists polled by Reuters who unanimously expected the U.S. Federal Reserve to go for a smaller 50 basis point interest rate hike on Dec. 14. The European Central Bank will also likely lift its deposit rate by 50 basis points next week to 2.00%, another Reuters poll found, despite the euro zone economy almost certainly being in recession, as it battles inflation running at five times its target.

Oil drops in volatile trade, records biggest weekly slump in months - Oil price settled lower in volatile trading on Friday, with both benchmarks recording their biggest weekly declines in months, as growing recession fears negated any supply woes after weak economic data from China, Europe and the United States. U.S. West Texas Intermediate crude settled 44 cents lower at $71.02 a barrel, a new low for 2022. Brent crude settled 5 cents lower at $76.10 per barrel. “Any concerns about supply are secondary to worries about the economy,” Oil prices had found some support and risen more than 1% earlier in the session after Russian President Vladimir Putin said the world’s biggest energy exporter could cut output in response to a price cap on its crude oil exports. However, a slightly higher-than-expected rise in U.S. producer prices in November, and news of a partial restart on the Keystone Pipeline undid those gains and pushed the benchmarks more than a dollar lower. Keystone shut earlier this week after a 14,000 barrel oil leak in Kansas. The U.S. producer prices index (PPI) rose slightly more than expected in November amid a jump in the costs of services, according to a report from the U.S. Labor Department. The increase may make it more likely that the Federal Reserve will “step on the accelerator” on interest rate hikes, furthering fears of a looming recession, Yawger said. Both crude benchmarks posted weekly losses of around 10% each. It was the biggest weekly decline since April for the U.S. WTI futures, and since early August for Brent. Both Yawger and Walter Zimmerman warned that if U.S. crude falls below $70 per barrel, it could enter a freefall and hit the low $60s range over the upcoming sessions. The market structure for WTI contracts switched to trade in contango over the next year for the first time since Nov. 2020, with contracts for near-term delivery cheaper than one year later . Brent contracts have also switched to trade in contango over the next six months. A market in contango suggests less worry about the current supply situation due to weakened demand, and encourages traders to put barrels in storage. In China, surging COVID-19 infections will likely depress economic growth in the next few months despite some restrictions being eased, economists said. Economists polled by Reuters forecast the U.S. economy will hit a short and shallow recession in the coming year. Forecasters expect the U.S. Federal Reserve to raise rates by 50 basis points (bps) on Dec. 14. The European Central Bank will also likely lift its deposit rate by 50 bps next week to 2%, even as the euro zone economy is believed to already be in recession.

Oil has worst week since March amid what Putin calls 'stupid' price cap -- Vladimir Putin showed his irritation on Friday with the West’s price cap on Russia’s oil, calling it “a stupid proposal” among other things. The market seemed to think otherwise though. After a brief and slight pop on the Russian president’s comments, crude prices settled down for a sixth day straight day in a week where the front-month contracts swung as much as $4 a barrel a day on supply uncertainties spawned by the price cap and on recession fears in the United States and Europe. “The short-term crude demand outlook has deteriorated significantly as no one has a strong handle on how bad a recession will hit the U.S. economy,” WTI, or New York-traded West Texas Intermediate crude for January delivery settled down 44 cents, 0.6%, at $71.02 per barrel. The U.S. crude benchmark ended the week down $9.28, or 11.6%, making it its worst week since the week ended March 25. WTI’s session low was $70.11 — a bottom not seen since Dec 21, 2021 and practically a dime above the key $70 support. London-traded Brent crude for February delivery settled down 5 cents, or 0.07%, at $76.10. For the week, the global crude benchmark down more than $9.47, or 11.%. Brent’s intraday low was $75.14 — a trough not seen since Dec 23, 2021 and less than cents above the key $75 support. As of Friday, WTI was down 4.8% for all of 2022. In comparison, the U.S. crude benchmark was up 73% in March when it traded just shy of $130 a barrel. Brent was off 1.4% on the year, after being up 80% in March when it rose to just short of $140 a barrel. The oil trade, meanwhile, was bracing for more volatility in 2023 as the West’s price cap on Russian oil and headwinds to global growth offset potential demand surges and supply crunches. The past two sessions were a perfect example of the price swings that could come ahead in oil. In Thursday’s business, crude initially rallied on reports of a tanker pile-up in Turkish waters, with authorities there apparently checking one vessel after another for oil of Russian origin. The U.S. Treasury then issued a statement, saying there was no need for Turkish authorities to do checks beyond the declaration made by shippers. It also said the government in Ankara was working quickly to resolve the issue and that Turkey shared U.S. interests in maintaining a well-supplied oil market. Crude prices fell after that as it became clear that there were no supply snafus due to the price cap. Thursday’s swings in oil were exacerbated by the closure of the gigantic 622,000 barrel-per-day Keystone pipeline after an oil spill. The pipeline carries heavy Canadian crude from Alberta to the U.S. Midwest and Gulf Coast. Its shutdown in principle put a hefty amount of crude back into the market at the same time that global economic slowdowns raised fuel demand fears. Sentiment remained bogged down in Friday’s session by worries that the U.S. Federal Reserve and the European Central Bank could resort to longer rate hikes through 2023 despite both signaling lately that their aggressive monetary tightening in recent months could be headed for a pivot. Friday’s U.S. Producer Price Index data for November grew at a faster-than-expected rate, disappointing policy-makers counting on weaker price pressures that would allow them to ease up on monetary tightening that could hurt growth. On the price cap front, Putin said Russia might retaliate with production cuts, although it would have to discuss that first with its allies in the OPEC+ global oil producers led by Saudi Arabia. "We are thinking about this, there are no solutions yet,” the Russian president said, referring to the price cap and Moscow’s likely response, that could include production cuts. He added that “concrete steps” will be outlined in a presidential decree “that will be released in the next few days”. Since Monday, the Group of Seven, or G7 club of rich nations, along with the European Union and other allies have imposed a $60 selling price limit on Russian oil. The move has had traders scratching their heads to figure out a landing price for Urals — the reference for Russian oil, which is one of the world’s more important benchmarks for crude other than the Dubai Light and the ubiquitous WTI and Brent. In theory, the price cap shouldn’t matter much as it does now as Urals on their own were quoted at around $60 per barrel just before the limit announced by the West. In practice though, the cap matters a lot — to Putin at least. "This will lead to the collapse of the industry itself, because the consumer will always insist that the price be lower,” Putin said. “The industry is already under-invested, under-funded, and if we listen only to consumers, then this investment will be reduced to zero.” "All this will lead at some stage to a catastrophic surge in prices and to the collapse of the global energy sector. This is a stupid proposal, ill-conceived and poorly thought-out." Putin doubled down on Friday on his Ukraine mission, dismissing Western attempts to squeeze Russia’s oil earnings via the price cap in order to slow down its war machinery. Putin alluded to the $60-per-barrel limit set by the West as proof that Russia’s finances won’t be hurt, saying that it corresponded with the level that Russia was currently selling its oil at.

Speculative Oil Positioning Now as Bearish as In Early Weeks of Pandemic - Speculative positioning in oil is currently as bearish as during the early weeks of the pandemic, according to Standard Chartered. “Speculative positioning in crude oil has been unremarkable through most of 2022, but this has changed in recent weeks,” analysts at the company stated in a new report sent to Rigzone. “Our crude oil money-manager positioning index compares net longs across the four main New York and London-based crude contracts relative to open interest and historical norms; this index is currently more negative than those for all other commodities in our sample,” the analysts added. “The crude oil index stands at -70.3, the lowest since mid-April 2020, about a week before WTI prices settled at a negative price. The index has fallen by 57.4 over the past three weeks; this is the largest three-week fall since February 2020, just before the temporary collapse of the OPEC+ agreement,” the analysts continued. In the report, the analysts noted that oil market fundamentals are far more supportive than they were in early 2020, highlighting that demand is not collapsing due to a pandemic and producers are not engaged in a price war. “However, oil has tended to be caught in the backwash from top-down macro trades,” the analysts said. “A negative U.S. economic data point causes oil to be sold as recessionary fears increase, but a positive data point can also cause oil selling through being USD-positive and negative for risk assets. There is always interplay between those effects, but in the past three weeks oil has tended to fall after both good and bad economic data,” the analysts stated. “Sentiment had been buoyed by hopes of China reopening, but as timescales dragged many traders preferred to make that trade in metals markets instead. We think many of the new shorts are relatively weak and will soon be covered, helping to shore up oil’s downside; however, in the short term the market is likely to accentuate the negative,” the analysts continued. At the time of writing, the price of Brent is trading at $78.11 per barrel, while the price of WTI is trading at $73.49 per barrel. Both commodities have seen a notable drop since early November, when Brent closed above $98 per barrel and WTI closed near $92 per barrel. The first cases of novel coronavirus were first detected in China in December 2019, with the virus spreading rapidly to other countries across the world, WHO notes on its website, adding that this led the organization to declare a Public Health Emergency of International Concern on January 30, 2020, and to characterize the outbreak as a pandemic on March 11, 2020. As of December 7, 5.28pm CET, there have been 642.37 million cases of Covid-19, with 6.62 million deaths, according to the latest figures from WHO. As of December 5, a total of 12.99 billion vaccine doses have been administered, WHO shows on its site. China’s weekly Covid-19 case numbers increased in the week commencing November 28 after seven consecutive weeks of declines, according to WHO, which showed that there were 146,141 confirmed cases last week. The weekly Covid-19 case peak for China was seen in the week commencing May 23, at 576,367 cases, WHO outlines on its site.

China's Xi on 'epoch-making' visit to Saudi as Riyadh chafes at U.S. censure (Reuters) - Chinese President Xi Jinping began a visit to Saudi Arabia on Wednesday that Beijing said marked its biggest diplomatic initiative in the Arab world, as Riyadh expands global alliances beyond a long-standing partnership with the West.The meeting between the global economic powerhouse and Gulf energy giant comes as Saudi ties with Washington are strained by U.S. criticism of Riyadh's human rights record and Saudi support for oil output curbs before the November midterm elections. The White House said Xi's visit was an example of Chinese attempts to exert influence, and that this would not change U.S. policy towards the Middle East. "We are mindful of the influence that China is trying to grow around the world," White House National Security Council spokesperson John Kirby told reporters. China, the world's biggest energy consumer, is a major trade partner of Gulf oil and gas producers. Bilateral ties have expanded under the region's economic diversification push, raising U.S. concerns about growing Chinese involvement in sensitive infrastructure in the Gulf. Energy Minister Prince Abdulaziz bin Salman on Wednesday said that Riyadh would remain a "trusted and reliable" energy partner for Beijing and that the two countries would boost cooperation in energy supply chains by establishing a regional centre in the kingdom for Chinese factories.Saudi Arabia is China's top oil supplier and Xi's visit takes place while uncertainty hangs over energy markets after Western powers imposed a price cap on sales of oil from Russia, which has been increasing volumes to China with discounted oil.

Focus on Fracking

Sunday, December 11, 2022

US oil supplies at 36½ year low, refinery utilization at 40 month high, biggest build of distillates supplies in 29 months

US oil supplies now at a 36½ year low, Strategic Petroleum Reserve at a 38½ year low; highest refinery utilization rate in 40 months, biggest build of distillates supplies in 29 months

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