US commercial crude supplies at a ten month low even with oil imports' four week average at a fifty month high; gasoline production at 6 month low
oil prices rallied to a one year closing high of $93.68 a barrel on Wednesday after the EIA reported US oil supplies had fallen more than expected and that inventories at the Cushing Oklahoma depot were the lowest in 15 months, but after touching $95 early Thursday, they pulled back to finish the week just 0.8% higher at $90.79 a barrel, as traders took profits ahead of an OPEC meeting next week, and as US government funding was set to expire at midnight Saturday and a shutdown seemed imminent....
with that new one year high, we're including a graph below to show daily oil prices over the past two years...while short term price moves are obscured with the shrunk down graph, you can see how the recent rally has lifted prices to their highest since Aug 30 of last year...note that the two spikes to over $120 last year coincided with the outbreak of the war in Ukraine and then later with subsequent sanctions on Russian oil exports
natural gas prices also finished higher, but most of the apparent increase was due to the expiration of trading in the contract for gas to be delivered in October and the subsequent quoting of the higher priced November contract...after inching up on Monday and Tuesday, the natural gas contract for October rose 10.8 cents to expire at $2.764 per mmBTU on Wednesday on a drop in daily output and forecasts for more demand over the next two weeks than had been expected...at the same time, the price for November natural gas settled 5.4 cents higher at $2.899 per mmBTU...with November gas being quoted thereafter, the price of natural gas finished the week at $2.929 per mmBTU, an apparent 11.1% increase from last week's closing price of $2.637 per mmBTU, which was quoting October gas....however, the price of natural gas for November had finished last week at $2.879 per mmBTU, so it was only up 5 cents or 1.7% on the week...
below we have a chart of natural gas prices over the last 20 years, which i mistakenly copied without the dates...you can still tell what they are, though, because each vertical graphing line represents two years....i copied 20 years of prices to illustrate how low todays prices are vis a vis the historical norms...note that since the 20 year graph was only able to display prices monthly, the last price on this graph is for August 31st...
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending September 22nd indicated that even after a big increase in our oil imports and an even bigger decrease in our oil exports, we had to pull oil out of our stored commercial crude supplies for the ninth time in eleven weeks, and for the twentieth time in the past 40 weeks, essentially due to a rare increase in demand that the EIA could not account for....Our imports of crude oil rose by an average of 711,000 barrels per day to 7,229,000 barrels per day, after falling by an average of 1,065,000 barrels per day the prior week, while our exports of crude oil fell by 1,055,000 barrels per day to average 4,012,000 barrels per day, which combined meant that the net of our trade in oil worked out to a net import average of 3,217,000 barrels of oil per day during the week ending September 22nd, 1,766,000 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 unchanged at a forty-two month high of 12,900,000 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 16,117,000 barrels per day during the September 22nd reporting week…
Meanwhile, US oil refineries reported they were processing an average of 16,065,000 barrels of crude per day during the week ending September 22nd, an average of 239,000 fewer barrels per day than the amount of oil that our refineries were processing during the prior week, while over the same period the EIA’s surveys indicated that an average of 346,000 barrels of oil per day were being pulled from the supplies of oil stored in the US. So, based on that reported & estimated data, the crude oil figures provided by the EIA for the week ending September 22nd appears to indicate that our total working supply of oil from storage, from net imports and from oilfield production was 397,000 barrels per day mmore than what our oil refineries reported they used during the week. To account for that difference between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a [ -397,000 ] 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 was an error of that magnitude in the week’s oil supply & demand figures that we have just transcribed.... Moreover, since last week’s “unaccounted for crude oil” figure was at [+1,735,000] barrels per day, that means there was a 2,132,000 barrel per day difference between this week's oil balance sheet error and the EIA's big 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, and therefore nonsense...however, since most oil traders react to these weekly EIA reports as if they were accurate, and since these weekly figures therefore 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 reliable 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)….(NB: there is also a more recent twitter thread from an EIA administrator addressing these errors, and what they had hoped to do about it)
This week's 346,000 barrel per day decrease in our overall crude oil inventories came as an average of 310,000 barrels per day were being pulled out of our commercially available stocks of crude oil, while an average of 96,000 barrels per day were being pulled out of our Strategic Petroleum Reserve, the first weekly decrease in the SPR after seven consecutive injections. Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports rose to a fifty month high of 7,229,000 barrels per day last week, which was 8.2% more than the 6,492,000 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 unchanged at a forty-two month high of 12,900,000 barrels per day because the EIA's rounded estimate of the output from wells in the lower 48 states was unchanged at a forty-two month high of 12,500,000 barrels per day, while Alaska’s oil production was 3,000 barrels per day higher at 418,000 barrels per day but still added the same 400,000 barrels per day to the EIA's rounded national total as it did last week...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 1.5% below that of our pre-pandemic production peak, but was 33.0% 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 89.5% of their capacity while processing those 16,065,000 barrels of crude per day during the week ending September 22nd, down from their 93.7% utilization rate of two weeks ago, a decline in refinery utilization that is fairly normal during the weeks right after Labor Day.. The 16,065,000 barrels per day of oil that were refined this week were 2.0% more than the 15,751,000 barrels of crude that were being processed daily during week ending September 23rd of 2022, but 2.3% less than the 16,513,000 barrels that were being refined during the prepandemic week ending September 20th, 2019, when our refinery utilization rate was at 89.8%, also down sharply from the September 6th week of that year...
With decrease in the amount of oil being refined this week, the gasoline output from our refineries was also lower, decreasing by 572,000 barrels per day to a six month low of 9,139,000 barrels per day during the week ending September 22nd, after our refineries' gasoline output had increased by 499,000 barrels per day during the prior week. This week’s gasoline production was 5.0% less than the 9,625,000 barrels of gasoline that were being produced daily over the same week of last year, and 10.8% less than the gasoline production of 10,240,000 barrels per day during the prepandemic week ending September 20th, 2019. On the other hand, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 150,000 barrels per day to 4,932,000 barrels per day, after our distillates output had decreased by 229,000 barrels per day during the prior week. Even with that increase, our distillates output was 0.5% less than the 4,958,000 barrels of distillates that were being produced daily during the week ending September 23rd of 2022, and 1.4% less than the 5,000,000 barrels of distillates that were being produced daily during the week ending September 20th, 2019...
Even with this week's decrease in our gasoline production, our supplies of gasoline in storage at the end of the week rose for the 10th time in thirty-two weeks, increasing by 1,027,000 barrels to 220,503,000 barrels during the week ending September 22nd, after our gasoline inventories had decreased by 831,000 barrels during the prior week. Our gasoline supplies rose this week even though the amount of gasoline supplied to US users rose by 209,000 barrels per day to 8,619,000 barrels per day because our exports of gasoline fell by 330,000 barrels per day to 814,000 barrels per day, and because our imports of gasoline rose by 199,000 barrels per day to 710,000 barrels per day ....Even after twenty-two gasoline inventory decreases over the past thirty-two weeks, our gasoline supplies were 3.9% more than last September 23rd's gasoline inventories of 212,188,000 barrels, while about 2% below the five year average of our gasoline supplies for this time of the year…
Meanwhile, with this week's increase in our our distillates production, our supplies of distillate fuels increased for the fourteenth time in twenty-nine weeks, rising by 398,000 barrels to 120,064,000 barrels over the week ending September 22nd, after our distillates supplies had decreased by 2,867,000 barrels during the prior week. Our distillates supplies rose this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, fell by 194,000 barrels per day to 3,972,000 barrels per day, and because our imports of distillates rose by 31,000 barrels per day to 104,000 barrels per day, and because our exports of distillates fell by 91,000 barrels per day to 1,017,000 barrels per day....With 40 inventory increases over the past seventy-one weeks, our distillates supplies at the end of the week were 5.0% above the 114,359,000 barrels of distillates that we had in storage on September 23rd of 2022, but were also about 13% below the five year average of our distillates inventories for this time of the year...
Finally, even with our oil imports higher and our oil exports lower, our commercial supplies of crude oil in storage fell for 17th time in twenty-five weeks and for the 27th time in the past year, decreasing by 2,169,000 barrels over the week, from 418,456,000 barrels on September 15th to a ten month low of 416,287,000 barrels on September 22nd, after our commercial crude supplies had decreased by 2,136,000 barrels over the prior week. With this week's decrease, our commercial crude oil inventories slipped to about 4% below the most recent five-year average of commercial oil supplies for this time of year, but were still 26% above the average of our available crude oil stocks as of the fourth weekend of September over the 5 years at the beginning of the past decade, with the big difference between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels. After our commercial crude oil inventories had jumped to record highs during the Covid lockdowns of the Spring of 2020, then jumped again after February 2021's winter storm Uri froze off US Gulf Coast refining, but then fell in the wake of the Ukraine war, only to jump again following the Christmas 2022 refinery freeze offs, our commercial crude supplies as of this September 22nd were 3.3% less than the 430,559,000 barrels of oil in commercial storage on September 23rd of 2022, were 0.5% less than the 418,542,000 barrels of oil that we still had in storage on September 24th of 2021, and were 15.5% less than the 492,426,000 barrels of oil we had in commercial storage on September 25th of 2020, after early pandemic precautions had left a lot of oil unused…
This Week's Rig Count
in lieu of our usual detailed rig count coverage, we are again just including below a screenshot of the rig count summary pdf from Baker Hughes...in the table below, the first column shows the active rig count as of September 29th, the second column shows the change in the number of working rigs between last week’s count (September 22nd) and this week’s (September 29th) count, the third column shows last week’s September 22nd 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 30th of September, 2022...
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ODNR chief shrugs off claims of disputed pro-fracking comments as state weighs drilling parks - – The head of the Ohio Department of Natural Resources defended the decision to neither independently investigate nor remove from the official record disputed, pro-fracking public comments after more than 150 people said their names were used on the letters without their knowing permission.ODNR Director Mary Mertz said she was first made aware via grassroots activists in mid-July of Ohioans saying they didn’t knowingly allow anyone to attach their names to comments urging the Ohio Oil and Gas Land Management Commission to open two state parks and two protected wildlife areas to oil and gas exploration.Cleveland.com and The Plain Dealer have previously identified more than 64 people who say their names were used without their knowing permission on the letters. Save Ohio Parks, a grassroots advocacy organization organized to oppose fracking in state parks, has identified an additional 84 names. The Dayton Daily News reported it identified 10 Dayton-area peoplewho say their names were used in public comments without permission.All the letters mention Salt Fork State Park, a Guernsey County recreational area that was previously the subject of a nearly $2 billion leasing offer.ODNR itself has received at least 10 emails from people whose names appeared on public comments asking that they be taken down. Mertz downplayed the accusations as “handfuls” and minimized their relevance as to the state’s decision on whether to lease mineral rights to the parks.“In terms of internally, finding an investigator to track this down, no, not my intention at this point,” she said in an interview Monday.“So far we have heard from not huge numbers of people. At this point, it seems like it’s more handfuls of folks this has happened to. We take that into account and we’re happy to take their names off the rolls. But no, no further investigation at this point.”On Sept. 10, Cleveland.com and The Plain Dealer reported that 28 people claimed their names were used without knowing consent, promptingAttorney General Dave Yost to open an investigation into the origins of the comments. That figure included three people who emailed the commission alleging their names were used without consent.
Ohio Oil and Gas Land Management Commission can – and should – deny fracking in our public lands - By Cathy Cowan Becker, et al of Save Ohio Parks -- Ohio’s Oil and Gas Land Management Commission met Sept. 18 to discuss the fate of our beloved state parks, wildlife areas, and public lands. At issue were nine applications, called “lease nominations,” by unidentified oil and gas companies to frack Salt Fork State Park, Wolf Run State Park, Valley Run Wildlife Area, and Zepernick Wildlife Area. Filling the room were Ohio citizens opposed to oil and gas extraction on the public lands we own, use, and want to preserve for future generations. Many of us held signs that said things like “Deny All Nominations” and “It’s Not Nice to Frack Mother Nature.” We rallied, spoke, and sang songs written for this movement by Ohio singer-songwriter Jenny Morgan. This meeting took place after thousands of Ohioans had submitted public comments asking the commission to deny nominations to frack our parks — and on the heels of a bombshell report showing that hundreds of pro-fracking comments were apparently fake. Yet instead of listening to the people, the commissioners seemed mainly to do the work of the fracking industry. Repeatedly Commission Chair Ryan Richardson said the commission had been directed to open our public lands for oil and gas extraction, that the legislature had made its intent clear, that the commission did not have the authority to deny fracking on public lands. Here’s the catch — that’s not true. The commission has full legal authority to deny fracking in our state parks, wildlife areas, and public lands — and they should. The relevant statute, ORC 155.33, says the commission can “approve or disapprove” lease nominations on the basis of nine considerations, including economic benefit, environmental impact, geological impact, impact on visitors, and public comments and objections. Further, HB 507’s amendment of the statutory language to “shall lease” is no longer in effect. That language reverted back to “may lease” once the administrative rules governing how the commission operates were approved May 28. Once the commission began taking lease nominations, our all-volunteer group Save Ohio Parks started issuing action alerts that have resulted in more than 3,600 public comments submitted by Ohioans opposed to fracking in our state parks and wildlife areas.Hundreds of other people independently wrote to the commission to oppose fracking in our public lands, including former First Ladies Hope Taft and Frances Strickland. Meanwhile, other than two sets of form letters, there were less than a dozen comments in support of fracking our public lands — and as reporting by Jake Zuckerman of the Cleveland Plain Dealer showed, almost 150 people whose names were on the pro-fracking form letters said they did not write them. Most of the others could not be reached.Given that the chair of the commission deciding the fate of our state parks and wildlife areas has falsely stated several times that the commission cannot deny lease nominations, it appears the outcome of this process was determined before it began. If the commission had no choice but to allow our parks to be fracked, why did we go through a public commenting process for months, only to ignore the vast majority of the submitted comments? The fact is, this commission does have a choice. They should listen to the overwhelming majority of Ohioans whose tax dollars pay for our state parks and wildlife areas, and deny all fracking in, near, or under Ohio public lands.
Legal Strategies: Will Drilling Come Back? - Youngstown Business Journal – I am constantly asked, “Will the oil and gas shale boom ever come back to Mahoning County?” Alas, it depends on a number of tricky factors. As with any business, oil and gas drillers look for maximum profit. Just as a farmer wants to plant the most profitable crop, oil and gas companies evaluate drilling opportunities in terms of the bottom line. So, the first thing a driller considers is the price of hydrocarbons. When the value of oil is high, operators will drill in “oily” areas. When natural gas trades up, they will move into dry gas territory.The chart below illustrates the last four years of commodities pricing pursuant to New York Mercantile Exchange and WTI [Western Texas Intermediate] historical records. The natural gas liquid composite price is derived from Bloomberg’s daily spot price.Wells that came online with lots of oil in 2022 were a driller’s dream. However, hydrocarbon prices are notoriously volatile. No one, not even top executives in the oil and gas industry, can perfectly predict future commodities prices.Last summer because of the war in Ukraine, natural gas prices were in the $9 range. Because of the warm winter in the United States and Europe, natural gas prices have recently sunk to $2.60.Second, drillers also look for areas with built-in infrastructure in the form of pipelines and roads sturdy enough to support heavy drilling rigs. Back in 2010, there were few large pipes in eastern Ohio.Over the last 12 years, however, thousands of miles of pipelines have been installed in our state. Now big collection lines crisscross Harrison, Jefferson, Carroll, Belmont, Noble and Monroe counties, moving gas from wells to treatment plants and then on into larger interstate pipes.These huge lines have been laid in both directions across the state: from central eastern Ohio up through Toledo and on to Canada, and down through Cincinnati and into the Gulf of Mexico.A number of treatment plants have been built in eastern Ohio to remove natural gas liquids, such as ethane, from the gas stream. An enormous Shell ethane cracker plant has been built along the Ohio River near Monaca, Pa. Having the plant handy greatly improves the economics of Ohio shale drilling.Back in 2012, most Utica Shale drillers considered Mahoning County and most of Columbiana County to be in the “wet gas window,” believing that Utica Shale wells drilled here would produce a lot of natural gas liquids. Early wells include Halcon’s Davidson (North Jackson) and Grenamyer (North Jackson) wells; and CNX’s Cadle (North Jackson) and Hendricks (Ellsworth) wells, among others. At the time of publication, all wells were still producing, but not in the massive quantities that wells further south have produced. The Grenamyer Well, for example, has produced 26,302 barrels of oil and 824,357 MCFs of natural gas since it was drilled nine years ago. Compare that to Encino’s 2020 Williams Well in Carroll County. In only three years it has produced 138,386 barrels of oil and 1,794,993 MCFs of gas.Perhaps the comparison isn’t fair, though, because drilling technology has progressed substantially in the years between 2014 and 2020. This has caused companies to take a fresh look at areas that did not look promising in the early years of the shale play. In Columbiana County, Hilcorp continues to drill in Fairfield, Unity and Elk Run townships, while Encino has started to lease in the western townships. Importantly, one of Ohio’s biggest Utica Shale drillers, EOG Resources, through its subsidiary, R&S Operating LLC, has quietly acquired over 395,000 acres of leases on the western, oily side of the play, including rights in Mahoning County. The acquisition involved deep rights under old Clinton sandstone leases.
Analysis Shows Utica has Years More of Inventory than Marcellus -- Marcellus Drilling News - According to a recent analysis by Enverus Intelligence Research, the cost of supply for North American shale producers is expected to continue rising. The remaining top-tier shale drilling inventory across North America *could be* in shorter supply than previously estimated, says Enverus. Rampant cost inflation from the Bidenistas and declining well productivity across the U.S. shale patch are making drilling wells much more expensive. What about the situation here in the Marcellus/Utica?
Federal Court In Ohio Rules That Driller Must Establish Marketability of Each Gas Product Under Market Enhancement Clause - JD Supra -- Let’s assume you own 95 acres in Greene County, Pennsylvania. In 2019, you signed an oil and gas lease with ABC Exploration. During the negotiations, you agreed that only those post-production costs which actually “enhanced” the value of the raw gas could be deducted from your royalty. In 2023, you receive your first royalty statement from ABC Exploration. You are pleased that there are no deductions for the cost to gather, compress or dehydrate the gas. However, you are shocked that significant processing costs are being deducted from your royalty. You contact ABC Exploration for an explanation. They claim that the costs incurred to process and fractionate the natural gas liquids (“NGLs”) are deductible because they “enhanced” the value of the raw gas. According to ABC Exploration, the individual NGL purity products, such as propane, butane and pentane, do not exist until the gas is processed and fractionated at a downstream processing plant. ABC Exploration contends that all costs incurred to process and fractionate the gas, and thereby create the “new” NGL purity products, must necessarily “enhance” the value of the raw gas. You are frustrated, angry and confused. Your 2019 Lease says no costs can be deducted unless such costs enhance “the value of the marketable oil, gas or other products …” Aren’t the NGLs a separate and distinct “product” that must first be marketable before any deductions are allowed? A recent decision by the Federal District Court in Ohio suggests that ABC Exploration cannot deduct the processing and fractionation costs. This is good news for landowners with Market Enhancement Clauses. Before we address the substance of District Court’s decision, a brief primer on Market Enhancement Clauses is warranted. Many Pennsylvania oil and gas leases have what is commonly known as a “market enhancement” royalty clause (“MEC”). These MEC leases typically prohibit the deduction of any post-production costs that are incurred transforming the raw gas into a marketable product. Once gas is in a marketable form, the MEC generally allows the driller to deduct further costs only if those costs actually enhance the value of the gas product. The enhancement costs must also result in the driller obtaining a “better” price for the raw gas. In other words, the driller cannot deduct the cost of dehydrating the raw gas and then moving the gas 165 miles away to a distant buyer unless the final net sales price at that location is better than the price the driller would have received selling the gas locally. The driller must show that the purported enhancement cost resulted in a better sales price for that volume of marketable gas. See, Net-Back Method Does Not Result In Better Pricing To Justify Deductions Under Market Enhancement Clause (October 16, 2021). This makes sense. Incurring costs and receiving a “worse” price makes no sense. The key is that no post-production costs are deductible until the gas product is marketable. Despite this clear language, drillers often deduct all post-production costs regardless of whether the gas is in marketable form and regardless of whether the downstream costs actually enhanced the value of the gas product.
Pincushion America revisited: The legacy of fracking on our drinking water -Eleven years ago, I wrote about the how millions of holes drilled deep into American soil were already destined to pollute groundwater across the United States, making many areas uninhabitable to humans who rely on such water. I warned that the so-called shale oil and gas boom would make this problem dramatically worse. Now that problem has reached the news pages of southern Ohio, and this will likely just be the beginning of coverage of fracking-related damage to the country's groundwater supplies. (There has been much coverage of studies that suggest such harm is inevitable and likely happening from fracking. But, we are now shifting into the stage where the actual harm will start to be discovered—almost certainly too late to prevent contamination in many cases.)The main culprit (for now) is not the oil and gas wells themselves, but the injection wells used to dispose of huge volumes of water laced with toxic chemicals that have been injected into wells under great pressure to fracture underground rocks containing oil and natural gas in shale deposits. A lot of that water comes back to the surface and so must be disposed of. One of the easiest ways to do that is to pump it deep underground—many thousands of feet down—where it can supposedly be safely deposited away from the surface and far below drinking water aquifers used by us humans. The trouble is—as I pointed out in my piece 11 years ago—the injected wastewater doesn't necessarily stay put. And, that's the problem in southern Ohio. In the Ohio case, "the [Ohio] Division of Oil and Gas Resources Management found that waste fluid injected into the three K&H [waste injection] wells had spread at least 1.5 miles underground and was rising to the surface through oil and gas production wells in Athens and Washington counties."This is why a former EPA scientist referenced in my 2012 piece believes that groundwater practically every there is any kind of drilling will become contaminated within the next 100 years as toxic fluids migrate from working and abandoned oil and gas wells and wastewater injection wells into fresh drinking water aquifers.Part of the problem is the piecemeal regulation of oil and gas operations and wastewater injection. States do the regulation and currently face large and powerful oil and gas companies and the companies that haul their toxic fracking wastewater away. The states have a difficult time monitoring what these companies are dumping, not least of all because the composition of the fluids used to fracture shale oil and gas deposits is considered a trade secret. States cannot easily pry open the files of these companies to find out exactly what is in these fluids.The fact that companies which use hazardous chemicals that can easily get into the drinking water supply are not obliged to divulge publicly the formulas for the mixtures they inject underground ought to shock the public. But unless Congress fixes some or all of the exemptions from federal disclosure laws enjoyed by the oil and gas industry, the public will continue to be in the dark about the makeup of the waste fluids from oil and gas drilling, especially in shale oil and gas fields, and associated injection of toxic fluids deep into the Earth.Without crucial information about contaminants which threaten public drinking water supplies, regulators and the public will be shadow-boxing their oil and gas industry foes. My guess is that if companies were obliged to release their fracking formulas and be subject to analysis of the actual fracking fluids and every community was by law informed of this information and its implications for public health, regulation of these practices would be far stricter and some current practices, such as injection of wastes underground, would be banned.
Fracking Fallout: Is America’s Drinking Water Safe? by Yves Smith - After many years, concerns about the impact of fracking on aquifers are finally going mainstream.A predictable outcome of fracking, which is contamination of aquifers, may be happening on a big enough scale to get out of the so-called progressive media into the mainstream. I recall years ago photos of dirty yellow and brown water coming out of taps in parts of Pennsylvania, and even some being able to get ignition when they held a lighter near the water stream, presumably due to high methane concentrations.I would like to know where in “southern Ohio” the water problems are. Cobb links to an article in Athens County Independent from earlier in the month which also came up in a quick search. lists Athens and Washington counties in southern Ohio as afflicted areas:Four fracking waste injection wells in Athens County have temporarily suspended operations by order of the Ohio Department of Natural Resources, which says the wells present an “imminent danger” to health and the environment.On May 1, ODNR Division of Oil and Gas Resources Management ordered the suspension of a Class II injection well in Rome Township on grounds that its operator, Reliable Enterprises LLC, violated an Ohio Administrative Code section that bars operators from contaminating or polluting surface land and surface or subsurface water. In late June, three wells in Torch operated by K&H Partners were suspended on the same grounds.Applications for new Class II injection wells from both Reliable Enterprises and K&H were denied because of the suspensions. K&H’s application for a fourth well at its $43 million facility in Torch generated controversy when it was proposed in 2018.Class II wells are used to contain toxic waste from oil and gas production thousands of feet underground. The wells are intended to isolate the waste water, known as brine, from groundwater.However, the Division of Oil and Gas Resources Management found that waste fluid injected into the three K&H wells had spread at least 1.5 miles underground and was rising to the surface through oil and gas production wells in Athens and Washington counties. Note that a May article, Ohio Environmentalists, Oil Companies Battle State Over Dumping of Fracking Wastewater, describes fracking water contamination in a different Ohio county, Coshocton County.
The Sickening Toll of Fracking in Pennsylvania - Stomach-churning smells. Mysterious rashes. Never-ending headaches and nausea. Faucets that produce brown, sludgy water; water that erupts into flames at the touch of a lighter. Anxiety, uncertainty, anger, fear. These have become parts of everyday life for families living near fracking operations. And while lawmakers and regulators should be protecting these communities, they’ve bowed to powerful corporations instead. Since the start of the fracking boom, Southwestern Pennsylvania has been a hotspot for gas. Fracking companies flooded in, promising jobs, tax revenue, and community investment. But as problems mount, the truth has become clearer. Fracking threatens families’ health, wellbeing, and lives, and we need leaders to join our fight against it. In 2019, the Pittsburgh Post-Gazette reported on a devastating anomaly. Over the past decade, Southwestern Pennsylvania saw rates of Ewing sarcoma three times higher than normal. In human terms, that meant 27 people were diagnosed with this rare bone cancer in a small four-county area. Six lived in a single school district.The report drew attention to what folks in the region already knew — something was horribly wrong. And many community members suspected that fracking was involved.For more than a year, families and organizers called for the state to investigate. In 2020, the governor’s office finally funded two major studies. The findings were published in August. Even given all we know about fracking, the results were shocking. The study linked fracking to worse asthma attacks, lower infant birth weights, and lymphoma, a rare type of cancer. It found that children living within a mile of a fracking well are five to seven times more likely to develop lymphoma than those living further from wells. Over the years, research has linked fracking to a long list of health problems. For almost a decade, Concerned Health Professionals of New York have gathered peer-reviewed studies on fracking and health. Most recently, it counted 2,239 studies that find evidence of harm.Much of fracking’s dangers come from the fracking fluids injected deep underground to help pull trapped gas to the surface. This toxic cocktail includes water, sand, and various harmful chemicals. Out of the ones we know, over three-fourths of these chemicals harm the skin, eyes, and other organs. They also wreak havoc on our hormones, brain, heart, and more. Moreover, at least 55 chemicals used in fracking are known to cause cancer.But companies keep many of their fracking chemicals secret, as allowed by federal law. They’re considered “trade secrets”; the logic is that making them public may give competitors a business advantage. This is a prime example of lawmakers putting profit over people. We deserve to know what chemicals may be getting into our water and poisoning our air. For example, the wastewater that fracking produces not only contains fracking fluids; it’s been found to contain heavy metals and radioactive material. This waste is usually transported to a new site and “disposed of” by injecting it into wells deep underground. It’s often carried in trucks that can and havespilled, and it’s been spread on roads to deice them in the winters. The injection process and wells themselves can leak, creating yet more pathways for toxic, radioactive wastewater to contaminate the environment and threaten our health.
EPA approves permit for fracking wastewater disposal well in Plum Borough - CBS Pittsburgh (KDKA) -- The U.S. Environmental Protection Agency has approved a permit for a new fracking injection well in Plum Borough after a lengthy review of the proposed project and dozens of public comments. Tucked away off Old Leechburg Road in Plum Borough sits Penneco Environmental Solutions' wastewater disposal facility. The EPA approved a permit for a conventional natural gas well at the site to be converted to a commercial disposal injection well, named SEDAT 4A. It will be the second injection well at the site. The new permit was approved despite opposition from people who live in Plum, some borough officials and environmental groups. "I wasn't surprised that the EPA approved it. Oftentimes the EPA's process is really narrowly focused on the Safe Drinking Water Act, so they are not accounting all of the local issues that we've seen on the ground with this well," said Gillian Graber, the executive director of Protect PT, a community group. People who live near the site don't want another well in their backyard. "The people that live near this site have experienced heavy air pollution events, where they have this acrid chemical smell when they open up the tanks that wafts down onto their property," Graber said. Protect PT has been voicing concerns over the wells for years. Graber said they question the integrity of the well casings and they're worried about possible water pollution. "Regionally, the biggest concern is drinking water. I think locally, the people that live on that street and live near the site, the contaminated air and truck traffic is huge. I mean, this is a rural road and there are hundreds of trucks going to and from the site," she said. According to the final permit, the well will inject into the Murrysville sandstone formation. The EPA reviewed the plans submitted by Delmont-based Penneco Environmental Solutions and there was a review of public comments, which were made in 2022. Penneco's Senior Vice President, D. Marc Jacobs, told KDKA-TV on Monday, "Penneco and the regulating authorities take very seriously the concerns of residents and borough officials" and that the "EPA has addressed all of the public concerns and inherent operational safeguards in their responsiveness summary to public comments." The EPA's response summary can be found here. The Pennsylvania Department of Environmental Protection still has to give approval on a change of use permit and a waste transfer station permit.
'Ezell: Ballad of a Land Man' performance about fracking and belonging coming to Pittsburgh - A touring production about the complex issues around fossil fuel extraction is coming to western Pennslyvania. The story, presented by Kentucky-based Clear Creek Creative, delves into the themes of domination and resilience in Appalachia.“Ezell: Ballad of a Land Man” is described as an outdoor, eco-cultural theater, music and meal experience. It’s coming to Tree Pittsburgh’s campus along the Allegheny River from September 28 through October 1.The Allegheny Front’s Kara Holsopple spoke with artist Greg Manley of local organization Friends of the Riverfront, who helped bring the production to Pittsburgh, and Bob Martin, writer and lead performer of the title character.
- Kara Holsopple: Who is Ezell Parsons, and where did he come from?
- Bob Martin: Ezell is somebody whose family has lost their land. It’s a story that’s common to many people. Parents, family members have gotten sick, so in hard times, families had to sell off the land. And Ezell has been removed from that place of his upbringing and has been trying to find a way to get back to that place or that feeling of being connected to land, of home place, of belonging.Ezell has taken a job as a land man, a land rights speculator. As the fracking boom has come into his area and local companies are forming to try to grab land rights, oil and gas rights in anticipation of a larger commodity, Ezell, as a land man, is using his knowledge of the place and of the people who live there to try to support them in not having to sell off their land.At the same time, he’s using the money from this job to buy back his family’s land in hopes of reviving it. However, this idea of Ezell buying back his family’s land while trying to get neighbors to sell off their mineral rights is a catch-22. It’s something where the land might be destroyed despite his best intentions.
Pa. gas prices, drilling falls between April-June 2023, report says - Natural gas prices in Pennsylvania have fallen steeply, after spiking last year. In a recent report, the state’s Independent Fiscal Office said the average price for natural gas from April to June of this year fell to $1.45 per million British thermal units.That’s down from $2.25 per MMBtu in the previous quarter, and from $6.70 at the same time the previous year.And the price continues to fall. Data from July and August shows the average price was $1.16 per MMBtu.The IFO says the drop is due to the mild winter leaving a glut of gas inventory.The amount of impact fees the state collects from drillers depends on both the number of wells drilled and the price of gas. Communities where drilling happens use the money to offset the effects of the industry.The IFO said there’s been a significant slowdown in new unconventional well drilling since the middle of last year.In the 2nd quarter of 2023, companies drilled 94 wells. That’s a 29% decrease from the same period in 2022, when 133 wells were spud.Pennsylvania operators ramped up drilling last year as prices spiked and following disruptions related to the COVID-19 pandemic.But the rate of production growth has not kept pace with the new wells.Between April and June, drillers pulled 1,859 billion cubic feet of gas from the ground, an increase of 0.3% from the previous year. It was the first quarter without a year-over-year production decline since the 2nd quarter of 2022.
Appalachian gas production sinks as in-basin prices dip below $1 -- Natural gas production in the Appalachian Basin is coming under pressure as waning autumn demand in the Northeast pushes prices there to their lowest since last November. Assuming the market follows a pattern seen in recent years, though, output could see a rebound by the fourth quarter.In September, production from the Marcellus and Utica shales has averaged just under 35.1 Bcf/d – down from a nearly two-year high at 35.3 Bcf/d in August, data from S&P Global Commodity Insights showed.The downturn in Northeast gas production in recent weeks comes as no surprise to seasoned observers.Over the past three years, producers in the Appalachian Basin have dialed back output in September. In 2020 and 2021, the early autumn drop was followed by a rebound in October and continued gains through the fourth quarter. Last year, though, output dropped consecutively in September and then October before rebounding in November and dropping again in December, S&P Global data showed.This fall, as in years past, the downturn in output comes as producers in Appalachia take a hit from cooling temperatures, falling gas demand and cratering prices.Since mid-September, gas demand in the Northeast has averaged just 15.9 Bcf/d – down from over 18.5 Bcf/d in August. In addition to weaker seasonal demand, the Northeast market is also coping with added supply from an ongoing annual maintenance at Cove Point LNG. Since Sept. 20, feedgas demand at the terminal has averaged just 15 MMcf/d – down from a prior 30-day average at nearly 760 MMcf/d. Based on the facility's maintenance history, the outage could last anywhere from 21-27 days.As supply overwhelms demand, spot gas prices at Appalachia's benchmark upstream hub, Eastern Gas South, have come under increasing pressure recently, hitting lows not seen since November. On Sept. 22, cash prices there traded as low as 77 cents/MMBtu before rebounding to around $1.20 in the days following. On Sept. 28, prices there were down nearly 50 cents, or almost 40%, on the day to trade at just 80 cents, data from the Intercontinental Exchange and S&P Global showed.Over the next seven days, weaker demand will likely keep pressure on Appalachian gas prices – and, potentially, production as well. According to a week-ahead forecast, Northeast demand should average about 15.6 Bcf/d followed by a slight drop below that level in the eight- to 14-day outlook.In the forward market, traders are already anticipating more price pain ahead. Earlier this month, the October gas contract at Eastern Gas South settled as low as 99 cents/MMBtu. More recently, October prices have rebounded, settling Sept. 27 at $1.25/MMBtu, Platts M2MS forwards data showed.In October, Northeast gas demand should rebound as feedgas flows return at Cove Point LNG and as residential-commercial heating ramps up late month amid colder weather. Despite the expected gains in demand, a forecast from S&P Global shows output holding flat-to-slightly weaker in October, followed by incremental gains in November and December.
Major U.S. Shale Drillers Hedged 2H23 Gas Production Avg. $3.35 | Marcellus Drilling News - According to an analysis by S&P Global Commodity Insights, large U.S. shale gas drillers (namely Marcellus/Utica drillers) have hedged (pre-sold at a specific price) an average of 50% of anticipated shale gas production for the second half of 2023. The average price of the hedges is $3.35/Mcf, far above the average NYMEX Henry Hub price that has been bumping along between $2.25 and $2.75. CNX Resources is the top hedger, hedging 80% of its production in 2H23 at $3.04/Mcf.
A Drop in Emissions, and a Jobs Bonanza? Critics Question Benefits of a Proposed Hydrogen Hub for the Appalachian Region. - —As the federal government nears a decision on which of the nation’s proposed “hydrogen hubs” will share up to $8 billion in startup money, critics of the idea in the Appalachian region are asserting that the program would do little to curb greenhouse gas emissions or create jobs, while increasing electricity prices for consumers and businesses.The U.S. Department of Energy plans to fund six to 10 regional hydrogen hubs to produce, store and use hydrogen as an alternative fuel for industry, transportation and power generation. Two rival proposals for the Appalachian region are still in the running, with separate support from the Pennsylvania and West Virginia state governments.But at a meeting this month in Pittsburgh, detractors argued that the economic and environmental benefits of building the hubs had been overstated. “The risk that we run is pushing hydrogen and carbon capture into applications where it’s not cost-effective,’’ said Sean O’Leary, a senior researcher at the Ohio River Valley Institute, the research nonprofit that sponsored the Sept. 11 forum. He warned that the program, known as Regional Clean Hydrogen Hubs, or H2Hubs, would siphon resources from more effective efforts to arrest climate change. The adopters would be “causing ourselves to pay far more money for a half measure—something that would cost a great deal more than other solutions and do a much worse job of reducing carbon emissions without any significant economic development to accompany it,’’ O’Leary said.The hubs would generate so-called blue hydrogen, using natural gas to heat water that would then be separated into hydrogen and oxygen. Carbon generated from the gas combustion would then be captured and buried in underground spaces that would be fed by a pipeline network.Advocates of the process say it would significantly reduce carbon dioxide emissions from major sources such as power plants and transportation while creating thousands of jobs. A regional hub would particularly benefit communities suffering from the long declines in the coal and steel industries, they add, which have traditionally dominated the economies of Pittsburgh and the Appalachian region. When approached by Inside Climate News, neither of the two public-private initiatives proposing to build a hub in the Appalachian region supplied projections of the hoped-for economic impact, however. And some analysts say the Department of Energy has not only exaggerated the benefits of the program but also risks worsening greenhouse gas emissions through leakage of the methane involved in burning and distributing the natural gas—and through the escape of hydrogen itself.“The reality is that blue hydrogen is neither clean nor low-carbon,” the nonprofit Institute for Energy Economics and Financial Analysis, or IEEFA, declared in a report released the day after the Pittsburgh event. Equally worrying, it said, “pursuing it will waste substantial time that is in short supply and money that could be more wisely spent on other, more effective investments for reducing greenhouse gas emissions in the immediate future.”
Inside the race to clean up America's abandoned oil wells -- The rig operator was stumped. He’d been making good progress, but now something blocked the way forward. Above the hole, Mong’s rig, which towered 50 feet into the air, suspended a vertical ramrod. When it dropped, the ramrod only shot 17 feet into the ground before slamming to a stop. Earlier, Mong had managed to reach more than 500 feet deeper into the well. Then this obstruction, whatever it was, sent him back to the start. Clearing it — prime suspects included metal casing, rocks, or a tree branch — would allow him to send cement and pea gravel into the hole, which reached hundreds of feet into Appalachian rock formations. Once an active oil well, now it was an environmental nuisance and the target of an ambitious federal cleanup program. The well needed to be decommissioned, along with at least 21 more spread across woodlands and fields in McKean County, Pennsylvania. The job fell to Mong and other employees of an oil service outfit called Plants & Goodwin, which specializes in plugging so-called orphan wells. Oil and gas companies are supposed to plug and clean up wells that they’ve drilled, but if they go bankrupt or otherwise disappear, that responsibility falls to the state, which then contracts with companies like Plants & Goodwin. If left festering, these wells can leak contaminants into surrounding groundwater or release methane, a greenhouse gas at least 25 times more powerful than carbon dioxide at trapping heat in the atmosphere. Uncorking a well in this part of Appalachia reveals a blend of oil and gas that has a nauseous maté color and gurgles like witch’s brew. After generations of drilling, the remnants of both vernacular backyard digs and professional oil operations pockmark the land. Since drillers operated for more than a century with little regulatory oversight, documentation of well locations is scarce and cleanup quality is inconsistent. “Until the 1970s there were no strong plugging standards in place,” said Luke Plants, who heads Plants & Goodwin. “People just shoving tree stumps down a well to plug it, or a cast iron ball or something like that.” The exact number of orphan wells nationwide is unknown. In late 2021, The Interstate Oil and Gas Commission, a multi-state organization, had more than 130,000 orphan wells on record but estimated that anywhere between 310,000 and 800,000 remained unidentified. That year the federal government took notice, folding $4.7 billion into the Infrastructure Investment and Jobs Act to help states handle their orphan well inventories. The first batch of that money has trickled down to states and has been distributed to contractors like Plants & Goodwin. It’s easily the most funding ever spent to address the problem, but both states and pluggers are now facing hurdles as they begin to identify and plug wells.
Siren Song of Geothermal Calls to PA Conventional & Shale Drillers -Marcellus Drilling News- As far back as July 2021, MDN began to cover the issue of geothermal energy, which uses the same technology (drilling rigs, horizontal drilling) to drill holes in the ground to circulate and warm (or cool) water underground as a “green” energy source. Geothermal is an area of interest for Marcellus/Utica shale drillers as a potential new source of revenue (see our geothermal stories here). More recently, we’ve reported on an experiment by West Virginia University and Northeast Natural Energy drilling an experimental geothermal well in WV (see WVU & NNE Drilling Test Well for CCS, Geothermal Energy). Pennsylvania is also sniffing around the geothermal concept (seePenn State Suggests Reusing Old O&G Wells for Geothermal Energy). Now comes word of a nonprofit called Project InnerSpace attempting to convince PA drillers to leave drilling for natural gas behind and enter the new nirvana of geothermal drilling instead.
Sempra's Port Arthur LNG Phase 2 Receives FERC Approval --The Port Arthur LNG Phase 2 expansion project in Texas has received permit approval from the Federal Energy Regulatory Commission. Image by Fahroni via iStock Sempra Infrastructure LLC’s Port Arthur LNG Phase 2 expansion project in Jefferson County, Texas, has received permit approval from the Federal Energy Regulatory Commission (FERC). Sempra Infrastructure said the permit is a major regulatory milestone for the project, which includes the addition of two liquefaction trains, trains 3 and 4, that are capable of producing up to 13 million metric tons per annum (mtpa) of liquefied natural gas (LNG), the company said in a recent news release. The Port Arthur LNG Phase 2 project is under active marketing and development and “could help meet future demand for US LNG supplies expected to serve European, Asian and other global markets as countries look to enhance energy reliability and security, and displace coal in power production”, the company said. Phase 1 of the Port Arthur LNG project is currently under construction and is designed to include two natural gas liquefaction trains, two LNG storage tanks, and associated facilities. The second phase would increase the total liquefaction capacity of the facility from approximately 13 mtpa to approximately 26 mtpa. The proposed project is also expected to include an additional LNG storage tank and marine berth and would benefit from some of the common facilities currently under construction that were previously approved as part of the Port Arthur LNG Phase 1 permitting process, Sempra Infrastructure said. "Sempra Infrastructure is committed to investing in infrastructure opportunities that help enable a cleaner and more secure energy future", Sempra Infrastructure CEO Justin Bird said. "Today's FERC order is a significant step in our ability to advance the global energy transition, creating an opportunity to double the amount of secure and reliable U.S. natural gas that Port Arthur LNG can help deliver to global markets”. Sempra Infrastructure said it continues to evaluate opportunities to develop the entirety of the Port Arthur site while also exploring potential projects to reduce the carbon intensity of its LNG, aiming to position Port Arthur as a flagship hub for the energy transition. The company is leveraging the integrated capabilities of its business segments to develop the proposed Port Arthur Pipeline Texas Connector project and the proposed Post Arthur Pipeline Louisiana Connector project, and develop new gas storage facilities, all of which would serve the Port Arthur LNG facility. To further the advancement of the Port Arthur Energy Hub, the company recently acquired 38,000 acres of pore space and relevant surface rights to support the proposed Titan Carbon Sequestration project, which is near the Port Arthur LNG facility. The project targets capturing carbon from the Port Arthur LNG Phase 1 and 2 projects, and has the potential to unlock other net-zero energy infrastructure opportunities, according to the release.
FERC Wants Action to Prevent Cold Weather Grid Failure Risk | Engineering News-Record -- At its Sept. 21 meeting, the Federal Energy Regulatory Commission approved four natural gas projects, while deferring two others—reinforcing an apparent impasse among agency commissioners over how they should consider greenhouse gas emissions and climate change in project review. Observers speculate that the issues spurred FERC to drop the project approvals from the agenda of its July meeting, without comment. Set to move forward is a second two-train LNG project, estimated at $13-billion, at the existing Sempra Infrastructure export terminal site in Port Arthur, Texas. Also approved was a boost in export capacity for the Calcasieu Pass LNG project in Louisiana and small increases in existing pipelines in the state and in Minnesota. The meeting also included lengthy discussion by FERC commissioners and others of action needed, including new and upgraded infrastructure, to prevent a repeat of the near-failure of some eastern U.S. electric and gas systems during extreme cold weather last December. It included those of Consolidated Edison Inc., the largest utility in New York state. During that weather event, 90,000 MW of generation was out at the same time, which represents 13% of the entire eastern interconnection—the grid system that covers two-thirds of North America (see map). Con Edison, which serves the New York City metropolitan area, took emergency action by tapping into available LNG. Gas-fired capacity accounted for 63% of the outages, followed by coal and lignite at 23%, oil at 4%, wind at 4% and nuclear, solar and hydroelectric at 1% each, according to details shared by FERC staff of a soon-to-be released outside analysis. About 10 GW of gas-fired outages occurred when gas supplies were curtailed by pipeline operators, staff said. In a statement, FERC and nonprofit North American Electric Reliability Corp. (NERC), the report author, said natural gas pipeline pressures “dropped largely because of freeze-related production declines” of Marcellus and Utica shale gas. Con Edison “faced reliability-threatening low pressures on its delivery pipelines, forcing it to declare an emergency and use its own liquefied natural gas facility to maintain service,” FERC and NERC officials said. The U.S. power system has become more reliant on natural gas, with gas-fired capacity growing 11% to 564.2 GW in mid-2023 from 508.2 GW in mid-2016, said FERC. A failure “would have been catastrophic,” Willie Phillips, the agency's acting chairman, told attendees. In a statement, the office of New York Gov. Kathy Hochul noted “very high reliability standards and safety requirements for our gas distribution system.” Jim Robb, NERC president and CEO, called for urgent action on the interdependence between bulk electric and natural gas systems, “including need for sufficient and reliable gas and electric infrastructure to sustain energy reliability.” Its analysis of the cold-weather event, including details not previously disclosed, listed 11 recommended actions to help prevent future risks. The problem is linked to the “gas/electric” conflict, said Mark Christie, a FERC commissioner. He noted that gas systems set up for retail customers are now used heavily to generate electricity. “Of course, we need more infrastructure, but the question is how to get more pipelines,” he said. Commissioner James Danly said the NERC report indicates the U.S. has failed to build enough natural gas infrastructure, largely due to agency roadblocks. Both are Republican appointees.
East Tennessee Natural Gas Looking to Support TVA’s Potential Coal-to-Gas Switch -Enbridge Inc.’s East Tennessee Natural Gas LLC (ETNG) is proposing to build a 122-mile natural gas pipeline that could add 300,000 Dth/d of firm transportation capacity to support Tennessee Valley Authority’s (TVA) long-range plan to reduce its coal fleet. FERC issued a notice of intent to prepare an environmental impact statement (EIS) for ETNG’s Ridgeline Expansion Project. The proposed project as designed would include a 14,600 hp compression station in Hartsville. A meter and regulating station would be added to receive supply from Columbia Gulf Transmission Station LLC, and ENTG plans modify existing stations that receive gas from Texas Eastern Transmission LP and Midwestern Gas Transmission Co. ENTG also plans to build 30- and 24-inch diameter pipelines across 122...
North American Natural Gas Demand Said ‘Approaching Its Peak,’ with Storage Needs Also Slipping - Natural gas demand in the United States and Canada is expected to peak in the next year, even as production remains strong and LNG exports are projected to increase through 2050, according to consultancy firm DNV.The independent risk management expert’s Energy Transition North America 2023 provides an outlook for natural gas, oil, coal and renewables to midcentury. “Currently, fossil fuels account for around 80% of energy supply in the U.S. and Canada, but this will drop to less than 50% by 2050,” the DNV researchers said. Natural gas demand in North America is set to drop by 40% by 2050, with oil down by 75% and coal consumption falling by 86%.
US weekly LNG exports down to 21 shipments - LNG Prime - US liquefied natural gas (LNG) exports declined in the week ending September 27 compared to the week before, according to the Energy Information Administration. The agency said in its weekly natural gas report that 21 LNG carriers departed the US plants between September 21 and September 27, down by seven cargoes compared to the week before.Moreover, the total capacity of these LNG vessels is 79 Bcf, the EIA said, citing shipping data provided by Bloomberg Finance.Average natural gas deliveries to US LNG export terminals decreased by 9.1 percent (1.2 Bcf/d) week over week, averaging 11.8 Bcf/d, according to data from S&P Global Commodity Insights.Natural gas deliveries to terminals in South Louisiana decreased by 3.2 percent (0.3 Bcf/d) to 7.8 Bcf/d, while deliveries to terminals in South Texas decreased by 7.4 percent (0.3 Bcf/d) to 3.7 Bcf/d.The agency said that natural gas deliveries to terminals outside the Gulf Coast decreased by 67.6 percent (0.6 Bcf/d) to 0.3 Bcf/d, while natural gas deliveries to the Cove Point LNG terminal in Maryland fell to zero this week. The Cove Point LNG facility, operated by Berkshire Hathaway’s unit BHE GT&S, has started its annual maintenance on September 20.Cheniere’s Sabine Pass plant shipped eight cargoes and the company’s Corpus Christi facility sent three shipments during the week under review.Sempra Infrastructure’s Cameron LNG terminal sent four LNG cargoes, while the Freeport LNG terminal and Venture Global’s Calcasieu Pass each shipped three cargoes during the week under review.The Elba Island LNG terminal did not send LNG cargoes this week.The price of the 12-month strip averaging November 2023 through October 2024 futures contracts declined 1 cent to $3.220/MMBtu, it said.The agency said that international natural gas futures increased this report week.Bloomberg Finance reported that weekly average front-month futures prices for LNG cargoes in East Asia increased 80 cents to a weekly average of $14.63/MMBtu.Natural gas futures for delivery at the Dutch TTF increased $1.32 to a weekly average of $12.61/MMBtu, the highest weekly average since late April, the agency said.In the same week last year (week ending September 28, 2022), the prices were $39.77/MMBtu in East Asia and $53.45/MMBtu at TTF, the EIA said.
QatarEnergy and ExxonMobil provide update on Golden Pass LNG construction - QatarEnergy and ExxonMobil released the latest construction update for their giant Golden Pass LNG export plant on the US Gulf Coast near Sabine Pass, Texas, as they work to launch the first train next year. State-owned QatarEnergy owns a 70 percent stake in the Golden Pass project with a capacity of more than 18 mpta and will offtake 70 percent of the capacity, while US energy firm ExxonMobil has a 30 percent share. A joint venture of Chiyoda, McDermott, and Zachry is building the tree Golden Pass trains worth about $10 billion next to the existing LNG import terminal. Golden Pass LNG Terminal and Golden Pass Pipeline said in the newest construction report filed with the US FERC that Golden Pass is continuing to carry out Phase I and Phase II activities, such as storm water protection, levee construction, stockpiling of material, and piling. Golden Pass and its contractors progressed installation of piping and steel in process and utilities areas, continued piping and vessels insulation activities and helical piles and piping installation for the ground flares, while concrete foundation pours continued in Train 2 and Train 3. In addition, Golden Pass progressed setting various vessels on respective foundations and progressed brownfield tie-ins. The firm also continued LNG tank tops modifications and progressed cable tray installations and cable pulling activities, and continued pipe pneumatic/hydrostatic testing program. As per the pipeline expansion project, Golden Pass continued civil and construction activities supporting milepost (MP)01 Compressor Station, Sabine Spur, Natural Gas Pipeline (NGPL) Interconnect improvements, and associated facilities.
NextDecade secures $356 mln loan for Rio Grande LNG Phase 1 (Reuters) - NextDecade said on Wednesday it has received a loan worth $356 million from a group of lenders to finance a portion of the Phase 1 of its Rio Grande liquefied natural gas (LNG) export facility in Texas. The LNG firm said the full amount was disbursed on Sept. 15, leading to lowering of its existing loan commitments for Phase 1 to under $10.8 billion from $11.1 billion. Located at Brownsville, Texas, the Rio Grande LNG export facility has been in development for several years, suffering repeated delays. The facility, with a capacity to produce 27 million tonnes per annum of LNG, received a positive final investment decision to construct the first three liquefaction trains (Phase 1) in July. The $18.4 billion committed for Phase 1 is the largest greenfield energy project financing in U.S. history.
Judge blocks government plan to scale back Gulf oil lease sale to protect whale species (AP) — A federal judge has ordered the Interior Department to expand next week’s scheduled sale of of Gulf of Mexico oil and gas leases by millions of acres, rejecting a scaled-back plan announced last month by the Biden administration as part of an effort to protect an endangered whale species. The Biden administration on Friday asked the 5th U.S. Circuit Court of Appeals in New Orleans to block the order issued Thursday night in Lake Charles, Louisiana, by U.S. District Judge James David Cain Jr. Environmental groups represented by the Earthjustice organization also appealed. As originally proposed in March, the Sept. 27 sale was would have made 73 million acres (30 hectares) of offshore tracts available for drilling leases. That area was reduced to 67 million acres (27 hectares) in August when Interior’s Bureau of Ocean Energy Management announced final plans for the sale. Cain’s injunction restores the original coverage area. BOEM’s revision also included new speed limits and requirements for personnel on industry vessels in some of the areas to be leased — also blocked by Cain’s order.
Appeals Court Blocks Biden Bid to Limit Oil Drilling Auction --A federal court left in place an order forcing the Biden administration to expand an upcoming sale of offshore drilling rights in the Gulf of Mexico, while giving the government more time to hold the auction. The decision by the Fifth Circuit Court of Appeals in New Orleans late Monday was a blow to environmental groups who’d sought to swiftly reinstate auction limits they argued are essential to protect the endangered Rice’s whale. The three-judge panel ordered the auction take place no later than Nov. 8 but otherwise left in place a lower court order forcing the Interior Department to sell more territory for potential oil development. Under that order, the agency must include 6 million acres it previously had pulled off the auction block and scrap planned vessel traffic limitations in an area that may provide habitat for the species. Louisiana and representatives of the oil industry, including the American Petroleum Institute, units of Chevron Corp., and Shell Plc, had challenged the limitations, with Chevron saying they could raise the costs and time to complete projects in the region. “We are pleased that the Fifth Circuit upheld the district court’s decision to compel the Department of the Interior to reinstate the removed acreage and remove the burdensome stipulations, but this administration has once again found a way to delay oil and gas lease sales,” said Ryan Meyers, API senior vice president and general counsel. Environmentalists, who had joined the Biden administration in appealing the lower court ruling and seeking a stay of the lower court’s order, argued that oil and gas activities in the northern Gulf of Mexico pose a serious threat to the continued survival of the Rice’s whale, given estimates there are just 51 remaining. Although the Fifth Circuit panel directed the Interior Department to take “necessary actions” to implement the order and warned there would be no extension of the Nov. 8 sale deadline, the extra time allows for the court to consider the environmental groups’ appeal on its merits. “Today’s ruling denies the oil industry’s frantic attempt to rewrite the rules of the game just as the clock runs out,” said Earthjustice lawyer Steve Mashuda. “We’ll continue this fight to protect the nearly extinct Rice’s whale from needless harm from the oil industry.” A spokeswoman for the Interior Department declined to comment Monday night.
Federal Court Reinstates Six Million Acres Slashed from Upcoming GOM Natural Gas, Oil Auction - An offshore oil and gas lease sale scheduled for Wednesday (Sept. 27) in the Gulf of Mexico’s (GOM) Outer Continental Shelf (OCS) must proceed as originally planned with all 73 million acres on offer, following a preliminary injunction granted by the U.S. District Court for the Western District of Louisiana. The Department of the Interior’s (DOI) Bureau of Ocean Energy Management (BOEM) announced a preliminary notice of sale for Lease Sale 261 in March. Upon publishing the final notice in August, however, BOEM said it had withdrawn six million acres from the process, citing concerns about possible impacts on the endangered Rice’s whale. In response, the State of Louisiana, the American Petroleum Institute (API) and Chevron USA Inc. filed a lawsuit and a motion for.
BOEM Complying with Gulf of Mexico Lease Sale Court Order -The U.S. Department of the Interior’s (DOI) Bureau of Ocean Energy Management (BOEM) has announced that it is taking steps to comply with an order issued by the U.S. District Court for the Western District of Louisiana regarding Gulf of Mexico Outer Continental Shelf Oil and Gas Lease Sale 261. “The United States is seeking an emergency stay of this order to allow time for a more orderly lease sale process,” BOEM said in a statement sent to Rigzone over the weekend. “In the event such relief is not granted, Lease Sale 261 will be conducted on September 27, 2023, and in accordance with the court’s order, BOEM will include lease blocks that were previously excluded due to concerns regarding potential impacts to the Rice’s whale distribution in the Gulf of Mexico,” it added. “BOEM will also remove portions of a related stipulation meant to address potential impacts to Rice’s whale from the lease terms for the leases that may be issued as a result of Lease Sale 261,” BOEM continued. In the statement, BOEM said it is extending the bid submission period to 3pm CST on September 26, 2023. The U.S. District Court for the Western District of Louisiana, Lake Charles Division, revealed in a document released on September 21 that government defendants were ordered to proceed with Lease Sale 261, absent challenged terms, by September 30, 2023. Motions for preliminary injunction seeking to halt the addition of a term to Lease Sale 261 by the BOEM, and the withdrawal of six million acres from that sale, were granted by the court, the document showed. Commenting on the preliminary injunction granted by the court, Ryan Meyers, the American Petroleum Institute’s Senior Vice President and General Counsel, said in a statement posted on the API website, “we are pleased that the court has hit the brakes on the Biden Administration’s ill-conceived effort to restrict American development of reliable, lower-carbon energy in the Gulf of Mexico”. “[The] decision will allow Lease Sale 261 to move forward as directed by Congress in the Inflation Reduction Act, removing the unjustified restrictions on vessel traffic imposed by the Department of the Interior and restoring the more than six million acres to the sale,” he added. “This decision is an important step toward greater certainty for American energy workers, a more robust Gulf Coast economy and a stronger future for U.S. energy security,” Meyers continued. Also commenting on the preliminary injunction, Erik Milito, the President of the National Ocean Industries Association (NOIA), said in a statement sent to Rigzone, “the injunction is a necessary and welcome response from the court to an unnecessary decision by the Biden administration”. “The removal of millions of highly prospective acres and the imposition of excessive restrictions stemmed from a voluntary agreement with activist groups that circumvented the law, ignored science, and bypassed public input,” he added. “In a period when inflation is increasing expenses for Americans, particularly in terms of gasoline prices, we must fully harness America's energy production capabilities, particularly those offshore. Our leaders should stop ignoring the vast benefits that U.S. offshore oil and gas production provides to Americans,” he continued. “This includes an abundance of energy resources, high-paying job opportunities, environmentally responsible low carbon output, support for coastal resilience and restoration, and enhanced national security, among numerous other benefits,” Milito went on to state. Prior to the release of BOEM’s statement on the court order, Rigzone asked the DOI, the U.S. Department of Energy (DOE), and the White House for comment on the API and NOIA’s statements, and on the preliminary injunction itself. A DOI spokesperson told Rigzone that it was reviewing the decision, the DOE referred Rigzone to the U.S. Department of Justice (DOJ), and the White House has not yet responded to Rigzone’s request at the time of writing. Rigzone has since contacted the DOJ asking for comment on the API and NOIA statements and on the preliminary injunction. A spokesperson for the Justice Department’s Environment and Natural Resources Division declined to comment.
Biden OKs new offshore oil leases, and faces hits by both sides - The Biden administration said Friday it will approve just three offshore oil and gas lease sales through 2029 — the smallest offshore oil drilling plan in history and one designed to narrowly comply with limits set by a divided Congress.The decision reflects how Biden is grappling with the realities of divided government and his own climate agenda, including his 2020 campaign pledge to end new offshore oil projects. In a heavily negotiated landmark climate bill last year, Congress tied the fate of offshore wind development — a Biden priority — to approval of new oil leases.With its announcement Friday, the administration argued it was meeting its legal mandates while still furthering the transition away from fossil fuels.In a statement, Secretary of the Interior Deb Haaland said the plan represents “the smallest number of oil and gas lease sales in history.” She added that it sets a course “to support the growing offshore wind industry and protect against the potential for environmental damage and adverse impacts to coastal communities.”The plan will delay any new oil lease sales until 2025, leaving as much as a two-year gap between sales that historically have been scheduled for several times a year. The Interior Department will also lease only in the Gulf of Mexico — dismissing proposed sales for Alaska’s Cook Inlet — as the administration seeks to limit fossil fuel production and zero out U.S. greenhouse gas emissions by 2050, according to an announcement from the Interior Department.Administration officials said they couldn’t go further because of provisions Congress approved last year that require offshore oil leasing in order for Interior to do offshore wind leasing. A maximum of three sales — one each planned for 2025, 2027 and 2029 — are the fewest the Interior Department said it could do under the law and keep expanding its offshore wind program as it intended through 2030.
Biden administration approves more offshore drilling in bid to expand wind energy — The Biden administration announced Friday it is planning as many as three new oil and gas drilling lease sales in federal waters over the next five years – a move that could anger Republicans, pro-industry groups and climate advocates alike and that will likely prompt legal challenges.But the plan, which the Interior Department was required by law to create, comes with a trade-off: It allows officials to offer more federal waters for clean wind energy.The five-year drilling plan “represents the smallest number of oil and gas lease sales in history,” Interior Secretary Deb Haaland said in a statement. The administration had previously proposed more drilling areas – up to 11 possible sales.The three sales would all take place in the Gulf of Mexico, scheduled for 2025, 2027 and 2029. The plan nixed the possibility of lease sales off Alaska’s Cook Inlet. The plan “sets a course for the Department to support the growing offshore wind industry and protect against the potential for environmental damage and adverse impacts to coastal communities,” Haaland said. The Inflation Reduction Act required the Interior Department to propose a certain number of oil and gas leases in federal waters in exchange for the ability to propose clean offshore wind energy projects. Three was the lowest number that would allow it to move forward with offshore wind lease sales around the country, the department said, given the requirements of the law. Tying clean wind energy to fossil fuel drilling was a key demand of Sen. Joe Manchin, the West Virginia Democrat who wrote much of the bill.
U.S. Oil And Gas Production Growth Accelerates Despite Higher Costs --Oil and gas production in the U.S. expanded at a faster pace during the third quarter of the year despite still rising costs, the latest Dallas Fed Energy Survey has shown.Costs have now been on the rise for 11 quarters in a row, the Dallas Fed said, with the situation particularly difficult for oilfield service providers.Even with rising costs, optimism in the industry increased over the third quarter, likely thanks to rising oil prices, which also probably motivated the increase in production. The optimism was evident in respondents’ input despite expectations of still higher costs next year.Speaking of prices, the respondents in the Dallas Fed survey forecast a WTI price of $87.91 per barrel on average for the final quarter of the year. This compares with an average price forecast of $77.48 in the previous quarter’s survey edition.Asked about what the effects of the energy transition would be on the industry, about a third of respondents said they expected the transition to push the price of oil higher. Another third predicted the transition will push the price of oil significantly higher. Just 9% expect the transition to make oil cheaper.These expectations suggest highly resilient oil demand in the face of EVs and other electrification efforts that are part of the transition push.Another interesting take from the survey concerned oil consumption now and in 2050. Some 28% of respondents saw oil consumption in 2050 slightly higher than current levels while 25% saw it as substantially higher. Another 25% saw 2050 oil consumption as slightly lower than current levels and only 8% expected it to be significantly lower than current levels.These expectations are particularly interesting in the context of recent reports from the International Energy Agency and other forecasters saying that peak oil demand will happen before 2030 as EVs displace internal combustion engine cars.
12,100 New Jobs in Texas Oil and Gas This Year So Far -The Texas upstream oil and natural gas industry has added 12,100 jobs in 2023, Texas Oil and Gas Association (TXOGA) noted in a media release, citing newly-released data from the Texas Workforce Commission (TWC). In August alone, employment in the sector rose by 1,200 jobs, TXOGA highlighted. “The oil and natural gas industry serves as a major driver of the Lone Star State’s robust economy,” said Todd Staples, president of TXOGA. “The 1,200 jobs reported in August add to already strong job growth numbers for this year, continued evidence of the strong demand for these irreplaceable resources both at home and abroad,” he added. In its review of the August Current Employment Statistics (CES) report from the U.S. Bureau of Labor Statistics (BLS), the Texas Independent Producers and Royalty Owners Association (TIPRO) said that Texas upstream employment for August 2023 totaled 208,500 jobs. Since the COVID-low point of September of 2020, industry has added 51,500 Texas upstream jobs, averaging growth of 1,479 jobs a month, TXOGA pointed out. At 208,500 upstream jobs, compared to the same month in the prior year, August 2023 jobs were up by 18,200, or 9.6 percent, over August of 2022, TXOGA said. Months with an increase in upstream oil and natural gas employment have outnumbered months with a decrease by 30 to five, according to TXOGA. Oil and natural gas jobs pay among the highest wages in Texas with employers paying an average salary of approximately $115,000 in 2022, the association said. The upstream sector involves oil and natural gas extraction and excludes other industry sectors such as refining, petrochemicals, fuels wholesaling, oilfield equipment manufacturing, pipelines, and gas utilities, which support hundreds of thousands of additional jobs in Texas, TXOGA outlined. The employment shown also includes “Support Activities for Mining,” which is mostly oil and gas-related but also includes some small amount of other types of mining, the association revealed.
Natural Gas Recapturing Process Promises Waste Reduction — but Questions Linger - A trio of major oil and gas producers are testing a new-to-New Mexico process to keep natural gas in the ground when it can’t be transported, sold or otherwise shipped through a pipeline. Instead of flaring or venting natural gas or completely shutting down wells when a midstream pipeline operator has an issue, the three producers — EOG Resources, Inc., Occidental Petroleum Corp. and Chevron Corp. — can now re-route backed-up gas into closed-loop gas capture systems, or CLGC, where it is re-injected into an active oil well. It then can be taken out later when a pipeline again has enough capacity. The New Mexico Oil Conservation Division regulates the state’s oil and gas field operations and issued the orders allowing the state’s pilot CLGC wells. Dylan Fuge, the division’s director, said he expects the process will help reduce venting and flaring. “Overall, CLGC systems result in less waste due to an increase [in] an operator’s gas capture,” he said. Producers want to capture this gas rather than flare it because they can sell it later. Plus, Fuge said, flaring the captured gas would not make sense given the cost and effort to set up the wells. Occidental was the only one of the three companies to respond to questions about CLGC systems. “CLGC is part of Oxy’s overall strategy to reduce greenhouse gas emissions,” said Jennifer Brice, the company’s director of communications and public affairs. She said the process minimizes flaring when third parties are unable to handle the gas [i.e. during mechanical breakdowns], and “keeps production online, and conserves natural resources when produced gas is stored rather than flared.” So far, New Mexico’s CLGC projects are small, and their promise hasn’t panned out in the oil and gas fields. EOG, Occidental and Chevron operate nine pilot CLGC projects in New Mexico. A review of venting and flaring records the three companies submitted to OCD showed that flaring amounts for EOG rose nearly twentyfold in the past year. Occidental and Chevron reported flaring nothing at all. At the same time, the “waste” Fuge referred to — natural gas lost in production, often due to leaks between a wellhead and a pipeline — spiked for all three companies in recent months, though inconsistencies in Chevron’s numbers leave that somewhat inconclusive. (Chevron reported processing more gas than it pulled from the ground in January and April.) EOG reported losing enough natural gas in June alone to equal the greenhouse gas emissions of 100 cars driven for a year. That’s four times what it burned in emergency flaring the previous year and far more dangerous to the climate. Given that murky picture, it’s not clear how much the pilot CLGC systems may be helping reduce emissions, much less mitigate contributions to climate change.
Energy Transfer LP Shuts Ruptured Oil Pipeline In Permian - -Energy Transfer LP shuttered its Centurion Pipeline on Monday after it was struck by a road worker, the pipeline company said in an email to Bloomberg. Energy Transfer LP acquired the pipeline earlier this year when it acquired the previous owner, Lotus Midstream for $1.4 billion. The Centurion Pipeline runs from New Mexico, ending in Cushing, Oklahoma, with laterals that extend to Crane, McCamey, and Colorado City in Texas. As of Monday afternoon, Energy Transfer LP was working “as quickly as possible to stop” the oil leaking from the pipeline. “We have shut in the line, however, there is residual product coming out of the line. We are working quickly as possible to stop the leak. We have dispatched specialized crews to contain the product that is out of the line and begin the cleanup process. All regulatory notifications have been made. We will provide updates as information becomes available,” Energy Transfer said in a note. It was not clear when the pipeline repairs would be complete and when the pipeline would resume normal flows. The whole Centurion pipeline system acquired from the Lotus deal has a capacity of almost 1.5 million bpd. The leak happened in a segment of pipe on the north side of Oklahoma City, about 70 miles southwest of Cushing, Oklahoma, known as the pipeline crossroads of the world. Cushing is the largest onshore oil storage hub in the world. Analysts have been watching the crude oil inventory levels at Cushing, Oklahoma, for weeks as the levels in storage at the facility have been falling on a fairly steady trajectory since June, with current levels now below 23 million barrels. It is Cushing’s lowest level since the summer of 2022.
Oil spews into the air in Oklahoma City after line hit during construction – ‘Black Gold’ spewed into the air for hours Monday, causing environmental concerns and a big mess in northwest Oklahoma City. ‘Texas tea’ shot into the sky, near NW 178th and Portland around 10:45 a.m. Monday “For me, this is a first,” said Chief Andrew McCann with OKC Fire Dept. The Oklahoma Corporation Commission said the crude oil line runs from Midland, Texas, to Cushing.The line, at a neighborhood under development, was hit by a bulldozer working on a new road. The oil ran off into a culvert and some into a storm drain. “It’s probably blowing thirty feet in the air,” said Steve Taylor. Taylor lives across the street. He saw the breaking news on the television and went outside to get a better vantage point.“I was concerned at first, because it was flowing towards my house, but then when I got up on the mound of dirt and saw that they had built quite a dike around it,” said Taylor. “I knew then that they had it under control.”Oklahoma City fire crews said they couldn’t even begin to estimate how much oil was spilled.“All I can say is it is very significant,” said McCann.Trucks came in to suck out as much oil as possible, while crews worked to turn off valves several miles away.“Once the process does get shut off, it will take time for the system to bleed down and the excess oil to flow through the through the leak,” said McCann.The city said the nearby neighborhood and drinking water will not be affected. Their main concerns are environmental and infrastructure.“It’s going to be have a negative impact to the environment, not just the ground and into the storm water, but also to the wildlife,” said McCann.They added the clean up will take days.“I imagine it will be a lot of soil recovery and some flushing of the storm drainage system,” said OKC Environmental Protection Superintendent, Derek Johnson.“They will have to come in here and literally mitigate the soil and take it out and put back fresh soil,” said McCann.The Oklahoma Corporation Commission sent News 4 the following statement:The oil transportation line struck today in North Oklahoma City runs from Cushing to Midland Texas. It is a large line, 16 inches in diameter. As it is an interstate line, it is under the jurisdiction of the Pipeline and Hazardous Materials Safety Administration (PHMSA), a federal agency. The line is still blowing down, so there is no estimate yet on the amount spilled. It is our understanding that the line was hit by an excavation operator working on a new road for a development under construction. The Oklahoma Corporation Commission Pipeline Safety Department is investigating from the standpoint of Oklahoma regulations regarding excavation and pipeline damage. The Corporation Commission‘s Oil and Gas Conservation Division is responsible for ensuring the area is remediated properl. The company that owns the pipeline also sent KFOR the following:A contractor for the developer of the subdivision hit one of our crude lines this morning and caused a leak. We have shut in the line, however, there is residual product coming out of the line. We are working quickly as possible to stop the leak. We have dispatched specialized crews to contain the product that is out of the line and begin the cleanup process. All regulatory notifications have been made. We will provide updates as information becomes available.
Crews Work To Cleanup Oil Spill In Northwest Oklahoma City --Crews are focused on cleaning up the mess an oil geyser made Monday in northwest Oklahoma City. Officials say more than 80,000 gallons of oil spilled out onto the ground, creating a 30-foot geyser that spewed for multiple hours.Sam Coury, a nearby landowner, was not too worried with the oil that made its way onto his land.“We did catch some oil and some contamination,” Coury said. “We’re oil country. We have pipelines all across the state. From time to time, we’re going to have mishaps like this.”One thing to thank for the containment of the spill was the quick response of crews.“It’s been very efficient,” Coury said. “They were on it all night. They’re down now, probably removing the dirt, and that’s it.”Removing the dirt is the first step, according to Matt Skinner with the Oklahoma Corporation Commission.“The contaminated soil is dug up and taken to a facility that is licensed to deal with such products,” Skinner said.The same goes for the oil that leaked into the storm water drainage system.“You flush it out with fresh water and then vacuum it up. That also goes to be disposed of in the proper facility,” Skinner said.Skinner says Oklahoma law is clear on who is responsible for the cleanup efforts, regardless of liability.“An operator, be it an operator of an oil and gas well, a pipeline, or anything of that sort, is responsible for the product,” Skinner said.Energy Transfer is the oil company that is in charge of the cleanup effort, with the OCC’s oversight.Officials say we won’t know the extent of the long-term environmental impact, if any, until the cleanup is done.
OKC mitigating damage of 88,000-gallon oil spill, one of the state's worst since 2010 --Frontend loaders, backhoes and tractor-trailers carrying tanks and vacuum equipment buzzed across dusty ground next to a housing addition and a busy highway in northwest Oklahoma City on Wednesday as workers attacked potential environmental issues posed by an 88,000 gallon crude oil spill that occurred Monday.The work being done by Energy Transfer, operator of the line near NW 184 and Portland Avenue, and contractors it hired were expected to remain on site for at least the next several days, officials said Wednesday.Tasks involved in the cleanup include recovering small lakes of spilled crude, removing or remediating contaminated dirt and flushing city-owned storm drains with fresh water to prevent any polluted water from flowing into a pond or nearby Bluff Creek.The drain flushing isn't expected to end until water captured at the end of the flows is clean, while work to remove contaminated soil at the spill location is expected to continue until what remains is oil-free. Making sure all the oil is removed matters.If any resulting pollution were to make it to Bluff Creek, it eventually could flow into Deer Creek and ultimately the Cimarron River. Oklahoma City's water supply in Lake Hefner, which is upstream from the spill site, was never in any danger, the city's environmental superintendent told The Oklahoman.The cleanup work is being overseen by the Oklahoma Corporation Commission's oil and gas division and Oklahoma City's storm water quality division. No lasting environmental impacts on the surrounding area are expected, representatives of both agencies said this week.The breach happened about 10:30 a.m. Monday as a road builder cleared ground at the site, creating a geyser of oil that could be seen by passing motorists until Energy Transfer was able to shut it down.The 16-inch line that was hit is one of two that carry crude oil between Cushing and Midland, Texas. When operational, the lines have a capacity of thousands of barrels per day. A barrel of oil contains 42 gallons.Known as the “pipeline crossroads of the world,” Cushing has more than 430 oil storage tanks spread out along the southern and northern edges of town. Cushing, which sits about 70 miles northeast of Oklahoma City, was once home to 53 refineries, but the last one was closed by Kerr-McGee in 1987.However, a Texas company is set to build a $5.6 billion “next generation” refinery in Cushing that will be one the country’s largest, processing 250,000 barrels of light crude daily.
As cleanup continues for oil spill in northwest Oklahoma City, who's liable remains unclear — Cleanup continued in a northwest Oklahoma City neighborhood after a pipeline was hit on Monday, causing 80,000 gallons of oil to spill for hours. Despite the amount of oil that leaked onto a construction site near a neighborhood at 178th Street and Portland Avenue, there have been no reports of impacts to wildlife or the city's water source, according to a report from the Oklahoma Corporation Commission. Crews remained in the area Thursday to clean up the spill. "It has to be put back to the way it was before this happened," said Matt Skinner, the spokesperson for the Oklahoma Corporation Commission. A contractor struck the pipeline and was trying to clear a road during construction. "Under our rules, any operator – be it the operator of an oil well, the operator of a pipeline – they're responsible for their product, regardless of how it got out. They are responsible for cleaning it up," said Skinner. The pipeline company has been cleaning up and scooping contaminated soil. The Corporation Commission said they oversee the process to make sure everything is done properly. "There's a difference between who’s responsible for a cleanup and who has liability. We do not decide liability by any means," said Skinner. They said that can be worked out between the pipeline company and the contractor, or it can be decided in court. They are also looking into if the pipeline was properly marked when it was struck. But neighbors still have concerns. "It's seeping into the ground, but hopefully, they'll get it cleaned up quick, and it doesn't release any fumes in the air," said homeowner Troop Holden. "That's a concern as well."
US oil, gas rig count falls seven to 694 on the week; most basins lose rigs or are unchanged - The US oil and natural gas rig count fell by seven to 694 on the week ended Sept. 20, an analysis by S&P Global Commodity Insights showed, as most basins lost rigs or stood still. The decline came from oil-focused rigs, which dropped by 11 to 568, the Sept. 28 analysis showed. All were vertical rigs that generally are used by private upstream operator in smaller plays. On the other hand, gas-directed rigs rose by four to 126, largely from horizontal rigs. Except for a recent adjustment of the total rig count for the week ended Aug. 23 from 703 to 698, the current week was the first time the rig count dipped below 700 since the final week of December 2021, according to S&P Global data. The elusive rig count bottoming, which has been talked up nonstop around the sector during the last few months, seems to be just about arrived – but at this point the figures aren't firm enough to call it. During August and September, the S&P Global rig count has see-sawed, ticking up and down week to week. For the week ended Sept. 20, the Bakken Shale posted the largest number of rig additions of the eight unconventional that S&P Global tracks – namely, five, making a total 37 rigs in that play. Also, the Haynesville Shale gained two rigs, for a total 51. But all other basins lost rigs or were unchanged. The Permian Basin shed the most rigs – four, leaving 319. That is the fewest number of Permian since early September 2022. The Eagle Ford Shale and DJ Basins were each down one rig, leaving 51 and 17 respectively, while the Marcellus Shale, SCOOP-STACK and Utica Shale were all unchanged, leaving 27, 26 and 10 respectively. The SCOOP-STACK has not been close to 50 rigs since early December 2021. Also, the week ended Sept. 20 is the Utica's fourth consecutive week at 10 rigs. As third-quarter 2023 draws to a close and quarterly upstream and oilfield service company conference calls loom in late October, industry thinking revolves around stronger commodity prices going forward as well as a tighter oilfield service market and cost deflation that is a bit less than earlier anticipated, investment bank Tudor Pickering Holt said.
Fracking For Oil and Gas Is Devouring American Groundwater - Today, the insatiable search for oil and gas has become the latest threat to the country’s endangered aquifers, a critical national resource that is already being drained at alarming rates by industrial farming and cities in search of drinking water.The amount of water consumed by the oil industry, revealed in a New York Times investigation, has soared to record levels. Fracking wells have increased their water usage sevenfold since 2011 as operators have adopted new techniques to first drill downward and then horizontally for thousands of feet. The process extracts more fossil fuels but requires enormous amounts of water.Together, oil and gas operators reported using about 1.5 trillion gallons of water since 2011, much of it from aquifers, the Times found. Fracking a single oil or gas well can now use as much as 40 million gallons of water or more.These mega fracking projects, called “monster fracks” by researchers, have become the industry norm. They barely existed a decade ago. Now they account for almost two out of every three fracking wells in Texas, the Times analysis found.“They’re the newcomers, a new sector that burst onto the scene and is heavily reliant on the aquifers,” said Peter Knappett, an associate professor in hydrogeology at Texas A&M University, referring to fracking companies. “And they could be pumping for several decades from aquifers that are already over-exploited and already experiencing long-term declines.” Fracking, which is shorthand for hydraulic fracturing, has transformed the global energy landscape, turning America into the world’s largest oil and gas producer, surpassing Saudi Arabia. Supporters say it has strengthened America’s national security and created valuable jobs.But fracking has long been controversial. The process of cracking the bedrock by injecting chemical-laced water into the ground can lead to spills and leaks and can affect the local geology, sometimescontributing to earthquakes. Critics of fracking say it is an irony that so much water is being diverted to produce fossil fuels, given that the burning of fossil fuels is causing climate change, further straining freshwater resources.The Times documented the surging water usage by examining an industry database in which energy companies report the chemicals they pump into the ground while fracking. But the database also includes details on their water usage, revealing the dramatic growth.The problem is particularly acute in Texas, where the state’s groundwater supply is expected to drop one-third by 2070. As the planet warms, scientists have predicted that Texas will face higher temperatures and more frequent and intense droughts, along with a decline in groundwater recharge. Some experts have warned that water issues could even constrain oil and gas production.In the western portion of the Eagle Ford, one of the state’s major oil-producing regions, aquifer levels have fallen by up to 58 feet a year, a 2020 study by researchers at the University of Texas at Austin found, and fracking’s water demands could result in further regional declines of up to 26 feet.Since 2011, BP has dug at least 137 groundwater wells in Texas for its oil and gas operations and reported using 9.1 billion gallons of water nationally during the past decade. EOG, one of the country’s largest frackers, consumed more than 73 billion gallons of water for fracking at the same time. Apache Corporation, Southwestern Energy, Chevron, Ovintiv and other major operators also have intensified water usage, the Times analysis found.
Fracking emissions count toward Colorado's air pollution goals --Colorado likely will need to rewrite its plan to reduce ozone pollution after a federal appeals court this week determined it was illegal for the state to ignore emissions from oil and gas fracking operations as it tries to improve air quality.The ruling by the 10th U.S. Circuit Court of Appeals is a win for environmentalists who have argued that the oil and gas industry is among the largest polluters in Colorado and that state and federal air regulators need more stringent permitting rules in place to limit the toxic fumes coming from the industry.“Colorado ignores pollution from oil and gas wells when fracked,” said Robert Ukeiley, an attorney for the Center for Biological Diversity. “We think that’s a big reason why we are in a severe area when it comes to ozone.”Colorado’s Air Quality Control Commission approved the state’s air-quality improvement plan in December without requiring fracking emissions to be considered when determining whether an oil and gas drilling site needed an air pollution permit. That allowed oil and gas operators to release unlimited amounts of toxic chemicals while digging a well and then fracking the site, Ukeiley said.The Environmental Protection Agency approved the state’s plan, and that’s when Ukeiley’s organization filed a challenge in the federal courts.Already, state regulators knew their air quality plan was flawed after those who drafted it admitted they had miscalculated future emissions from the oil and gas industry.On Monday, the 10th Circuit agreed with the Center for Biological Diversity that the EPA was wrong to approve the plan without limits on emissions from fracking, according to an opinion published by the court.The various agencies involved in the court’s decision were still digesting the ruling on Tuesday and it was unclear what’s next for the state.The American Petroleum Institute, which represents the oil and gas industry, signed onto the case with the EPA to argue Colorado’s plan was valid.
Nikki Haley and Ron DeSantis tangle on fracking in second GOP debate - Former U.N. ambassador Nikki Haley and Florida Gov. Ron DeSantissparred over fracking at the second Republican primary debate Wednesday, with each making some questionable — and in some cases false — claims about DeSantis’s record on the subject.Haley tried to frame DeSantis as opposed to American energy independence because as governor he directed state environmental officials to oppose fracking, the process of injecting pressurized liquid into bedrock to extract oil or gas.On the presidential campaign trail, DeSantis has reversed course and expressed support for fracking in states that allow it.“Ron DeSantis is against fracking. He’s against drilling,” Haley said. “He always talks about what happens on day one, you better watch out because what happens on day two is when you’re in trouble. Day two in Florida, you ban fracking, you ban offshore drilling.”DeSantis’s actions on fracking have been more nuanced than Haley’s attack suggests. In his 2018 campaign for governor, he promised “to pass legislation that bans fracking in the state.”“With Florida’s geological makeup of limestone and shallow water sources, fracking presents a danger to our state that is not acceptable,” he wrote on his 2018 campaign website.That November, Florida voters passed an amendment to the state constitution to ban offshore oil and gas drilling under Florida’s waters. The amendment did not mention fracking.Two days after his inauguration, on Jan. 10, 2019, DeSantis signed an executive order implementing the change. Among other things, the sweeping order instructed the state’s Department of Environmental Protection to “take necessary actions to adamantly oppose all off-shore oil and gas activities off every coast in Florida and hydraulic fracturing in Florida.”Effectively, according to PolitiFact, no permits have authorized fracking in Florida while DeSantis has been in office.During Wednesday’s debate, DeSantis tried to deny Haley’s assertion that he had banned fracking as governor: “That’s not true,” he replied. DeSantis pointed to the constitutional amendment to explain his executive order. He went on to argue that he supports increased drilling in west Texas and would force gas prices down as president.
Exxon Barred From Trucking Oil From California Offshore Platform - Exxon Mobil Corp. won’t be able to revive oil platforms off the California coast by relying on trucks to ship crude to refineries on shore. Three offshore platforms, known as Exxon Mobil’s Santa Ynez Unit, have been shut down since 2015 when a pipeline ruptured and created the worst coastal oil spill in the state in 25 years. Exxon Mobil figures it’ll probably take five more years to repair or replace the pipeline. The company estimates it spends tens of million of dollars to maintain the facilities and pays $1 million annually in taxes while SYU is shut down. US District Judge Dolly M. Gee in Los Angeles on Wednesday denied Exxon Mobil’s request to overturn a 3-2 decision by the Santa Barbara County Board of Supervisors to reject the oil company’s trucking plan in 2022. The judge said while Exxon Mobil has every right to operate its offshore oil platforms, it doesn’t have a right to truck the crude. “The Board’s decision in this case does not permanently implicate Exxon’s vested right to use its SYU facilities, but only halts its proposed ‘restart’ which itself was a temporary fix to a bigger problem: the lack of viable pipeline transport,” Gee wrote. “That is a problem not caused by the Board’s decision.” Exxon Mobil didn’t immediately respond to a request for comment. “It’s time for Exxon to accept that the community won’t support drilling and transporting oil in their backyard,” Liz Jones of the Center for Biological Diversity said in a statement. “The costs of oil spills are too high to risk, and this decision is a well-deserved win for the community, ocean life and ecosystems.”
Argentina’s output falls in July, cabinet launches favourable dollar rate for oil, gas exporters (ICIS)–Argentina’s economic output fell by 1.3% in July, year on year, but posted an increase of 2.4% compared with June, the country’s statistics office Indec said this week. Agriculture, still reeling from a historic drought which hit Argentina’s grain exports hard, and manufacturing posted falls in output in July, year on year, of 14.0% and 3.7%, respectively. Month on month, however, economic activity rose by 2.4%. July’s economic indicators come after Indec confirmed earlier this month the economy contracted by 4.9% in the second quarter, year on year. While Argentina’s economic woes continue rising the Argentinian government launched this week the ‘Vaca Muerta dollar’ to let the country’s key oil sector enjoy more favourable peso exchange rates for the next two months. Vaca Muerta is Argentina’s vast oil and gas field in Patagonia. With the measure, the state would also increase its revenue by around $1.2bn, said Massa, as the country is in dire need of dollar reserves. The experiment would follow the example of the ‘soy dollar’, which also allowed agricultural exporters to have more favourable exchange rates. With inflation running at nearly 125%, Argentina has tight control of the official exchange rates, but it can also favour certain economic sectors. For the next two months, oil and gas exporters will be able to exchange 25% of the value of their exports using the cryptocurrency CYCLEAN (CCL) exchange rate to convert their dollars into pesos. The CCL rate offers the oil sector about 763 pesos per dollar, or more than double the value of the official rate, which stands at around 350 pesos per greenback. “We made the decision to recognise 25% of what [energy companies] export and bring to Argentina to invest using the CCL value so that they increase investment levels over the next 60 days in the oil and gas sector,” said Argentina’s economy minister, Sergio Massa, the candidate of the governing party for the general election on 22 October
Equinor’s Brazilian Natural Gas Development Could Supply 15% of Country’s Demand - Norway’s Equinor ASA is set to develop a massive natural gas project offshore Brazil. The company submitted a declaration of commerciality for the BM-C-33 concession in Brazil’s Campos Basin to oil and gas regulator Agência Nacional de Petróleo, Gás Natural e BiocombustÃveis (ANP). The $9 billion Raia Manta and Raia Pintada projects on the deepwater concession are expected to be natural gas-rich additions to Brazil’s energy mix once they are up and running in 2028. “The developments have the potential to meet 15% of the total Brazilian gas demand when in production,” said Veronica Coelho, Equinor’s country manager in Brazil. “This will contribute to Brazil’s energy security and economic development, enabling significant new job opportunities at local...
European Natural Gas Prices Rally on Extended Norwegian Supply Outages – LNG Recap - Global natural gas prices ticked higher on Monday driven partly by ongoing supply fears as winter approaches. Norwegian exports to the rest of Europe continue to gradually ramp back up. Nominations were at 254 million cubic meters (MMcm) on Monday and closer to normal levels of over 300 MMcm. That’s up from 175.9 MMcm a week prior as maintenance work offshore has lasted longer than expected. Equinor ASA said last Thursday it would take a few days to return to full production after finishing planned modifications at a production platform in the massive Troll field. Norwegian grid operator Gassco shows the outage lasting until Oct. 6, while work at the Skarv field is also expected to stretch into next week.
France Expected to Boost Europe’s LNG Imports with FSRU Arrival - The recent arrival of France’s first floating regasification and storage unit (FSRU) at the port of Le Havre comes as high gas stocks and a rebound in nuclear power output have limited the country’s need for natural gas. “Given the current healthy gas stock situation and improved nuclear availability in France, we would expect the country’s liquefied natural gas demand to be limited in the months ahead,” Kpler analyst Rhyana Rasidi told NGI. “However, the new FSRU could definitely support demand from November, when heating requirements typically rise.” France also continues to play a key role as an entry point and transit country for natural gas for the rest of Europe as the continent continues working to replace Russian gas imports.
What is known about the Nord Stream gas pipeline explosions - – One year on from explosions that damaged the Nord Stream gas pipelines under the Baltic sea between Russia and Germany, the question of who was behind them is unresolved. On Sept. 26, 2022, Swedish seismologists registered several blasts, some 17 hours apart off the Danish island of Bornholm that ruptured three out of four lines of the Nord Stream system, sending plumes of methane into atmosphere. Russia’s Gazprom said about 800 million cubic metres of gas, equivalent to about three months of Danish gas supplies, had escaped. It took several days for the gas to stop leaking. Since the blasts occurred in the exclusive economic zones of Sweden and Denmark, both countries are investigating, as well as Germany, where the pipes land. The multibillion-dollar infrastructure project was built by Russia’s Gazprom in two stages – Nord Stream 1 and Nord Stream 2. Each stage consists of two concrete-coated steel pipelines of about 1,200km in length and more than 1m in diameter, laying at a depth of around 80-110m. Nord Stream pipelines had a total capacity of pumping some 110 billion cubic metres (bcm) of natural gas per annum, more than a half of Russia’s total export capacity. Gazprom owns 51% of Nord Stream 1, while Germany’s E.ON and Wintershall Dea have 15.5% each, while French Engie and Dutch Gasunie hold 9% each in Nord Stream 1. The Western owners have written off all their investments. Nord Stream 2, fully owned by Gazprom and operated by Nord Stream 2 AG, was completed in September 2021 at a cost of $11 billion, but was never put into operation because Germany had cancelled Nord Stream 2’s certification days before Russia’s invasion of Ukraine on Feb. 24, 2022. Western companies – Shell, Germany’s Wintershall Dea and Uniper, French Engie and Austria’s OMV covered 50% of the NS2 construction costs. All five have also written off their full financing of NS2, each of about 1 billion euros. Washington and NATO called it an act of sabotage, while Moscow said it was an act of international terrorism. Sweden found traces of explosives on several objects recovered from the explosion site, confirming it was a deliberate act. In July, Germany told the U.N. Security Council that it found traces of subsea explosives on a sailing yacht that “may have been used to transport the explosives”. Germany told the U.N. that trained divers could have attached explosives at the points where the damage occurred to the pipelines at about 70 to 80 meters deep. So far, no one has taken responsibility for the blasts. Russia and the West have pointed fingers at each other. U.S. investigative journalist Seymour Hersh alleged in a blog post in February that the operation was carried out by U.S. navy divers with assistance of Norway but Washington dismissed the report as “utterly false and complete fiction”, while Norway said the allegations were “nonsense”. Russia has asked the U.N. Security Council for an independent investigation but failed to win support, except from China and Brazil.
Samsung Heavy develops high-speed welding robot for LNG carriers - South Korean shipbuilder Samsung Heavy Industries said it had developed a laser high-speed welding robot to speed up the construction of liquefied natural gas (LNG) carriers. SHI said in a statement that the new robot, first such technology in the industry, would substantially improve the speed of joining membrane panels in the cargo holds of LNG carriers. According to the shipbuilder, the new laser high-speed welding robot is up to five times faster than the existing method of plasma arc welding (PAW). When welding a 2-meter-long membrane panel, PAW takes about five minutes, while laser welding takes only one minute, SHI claims. SHI said that the length of membrane panel welding for four cargo holds on a 174,000-cbm LNG carrier is about 60 kilometers, which is equivalent to a straight line from Seoul to Pyeongtaek.
Worley bags carbon capture gig from QatarEnergy LNG - Australian engineering firm Worley has secured a contract from QatarEnergy LNG, previously known as Qatargas, to provide front-end engineering design (FEED) services for the latter’s CO2 sequestration project in Ras Laffan, Qatar. Worley said in a statement on Monday that its teams in Qatar and Australia will develop the FEED study and engineering, procurement and construction (EPC) scope of work. The Australian firm said it will complete the project next year, but it did not provide the price tag of the contract. Once completed, the sequestration facility will be capable of capturing 4.3 million tonnes of CO2 every year, helping to further reduce QatarEnergy LNG’s environmental impact across the LNG value chain by reducing emissions from its seven LNG trains at QG North and three LNG trains at QG South. Worley said the facility will capture CO2 from the trains, compress it, and inject it into the new injection wells. New compression trains and pipelines need to be installed after FEED is completed. Drawing in on expertise from its CCUS centers of excellence, the project team will aim to prove the pre-FEED concept by modelling the CO2 capture process, Worley said. This high-level technical approach aims to further instill confidence to expand the CO2 sequestration technology in the future to include the remaining trains at Qatargas South and North, it said.
Iran begins developing new gas field in northeast - Tehran Times – The first phase of the development project of the Tous Gas field in northeastern Iran was started in an official ceremony on Sunday, Shana reported. Located in Khorasan Razavi Province, Tous Gas field is going to produce three million cubic meters of gas on a daily basis in the first phase and the production of the field is going to be increased to five million cubic meters per day in the second phase. The inauguration ceremony of the mentioned project was attended by the Head of the National Iranian Oil Company (NIOC) Mohsen Khojasteh-Mehr. According to Khojasteh-Mehr, in total, eight wells are going to be dug to develop this field and $200 million will be invested to complete the project.
Gas projects to save Iraq over $8bln a year -- Gas projects unveiled by Iraq over the past months will allow the OPEC member to become a gas exporter and save money on imports, the country’s Prime Minister Mohammed Al-Sudani was reported on Monday as saying. Sudani, speaking at a weekend seminar in New York, said Iraq is losing $4-5 billion annually because of gas flaring while it is saddled with an Iranian gas import bill of $4 billion. “We are importing nearly one billion cubic feet of gas from Iran, with an import bill standing at nearly $4 billion per year…we are also losing $4-5 billion due to flaring of associated gas,” he said in comments published on Monday by the official Iraqi news agency. Sudani said Iraq’s gas resources are massive but have not been exploited by most previous governments, adding that concessions being awarded to foreign companies would largely boost recoverable gas in the OPEC member. “We are undertaking large projects in the gas sector with the help of foreign firms, including TotalEnergies…these projects will turn Iraq into a gas exporter in the future,” he said, referring to the recent $27 billion agreement signed with the French energy giant. “We are a country which is producing 4.65 million barrels-per-day of oil…imagine the large quantities of associated gas which are being wasted…but my government is working to establish the right basis for utilising these resources and stopping this waste.”
LNG deals ramp up amid green transition - China has been stepping up its natural gas purchases as well as facilitating construction in recent years, as part of efforts to ensure sufficient energy supply amid its green transition, said industry experts. The country is looking to sign more deals to avoid future shortages and reduce dependence on spot deliveries, with 33 percent of global long-term liquefied natural gas volumes going to China, according to Bloomberg’s calculations. China is on track to become the top importer of LNG worldwide in 2023, as Chinese companies agree to buy more on a long-term basis than any single nation for the third straight year, data compiled by Bloomberg reveal. An analyst said as China heavily depends on imports for natural gas, the country must diversify its imports among various countries as a cushion against geopolitical disruptions and uncertainties. “Energy security has always been a priority for China, as the country is making efforts to avoid energy shortages while seeking to fuel economic growth,” said Luo Zuoxian, head of intelligence and research at the Sinopec Economics and Development Research Institute. China’s natural gas consumption rose steadily in the first seven months of 2023 amid efforts to achieve green development, with apparent consumption of natural gas during the January-July period standing at 227.1 billion cubic meters, up 6.5 percent year-on-year, according to the National Development and Reform Commission. In July alone, apparent consumption of natural gas increased 9.6 percent year-on-year to 32.49 bcm, data from the country’s top economic regulator showed. According to Luo, State-owned enterprises have played a key role in ensuring sufficient natural gas supply in recent years. State-owned China National Petroleum Corp recently sealed a 27-year deal with Qatar with a stake in the latter’s massive expansion project, while ENN Energy Holdings also inked a decades-spanning contract with US developer Cheniere Energy. Supplies from both contracts are slated to begin as soon as 2026. Companies including CNOOC, Zhejiang Provincial Energy Group and Beijing Gas Group are also in search of similar deals. As Chinese companies are signing more contracts, they are gaining more control over the global LNG supply, with China playing a key role in balancing the market, Luo said. According to Li Ziyue, an analyst at BloombergNEF, long-term contracts, with a relatively steady price compared to the spot market, help China to secure LNG supply in an increasingly volatile gas market, with large fluctuations in spot prices. China’s efforts will, in turn, help support global export projects, while Beijing’s influence on the market is also set to increase, she said. China’s LNG imports could rise to as high as 138 million metric tons by 2033, nearly double the current levels, according to Norwegian consultancy Rystad Energy. Alexei Miller, chief executive officer of Russian gas giant Gazprom, was quoted by Reuters as saying that the company accounts for more than half the increase in China’s gas imports this year, without providing figures. The Chinese gas market is growing. China’s gas imports increased over the first eight months of this year and more than half of the increase in the supplies imported to the Chinese market was provided by Gazprom, he said. Russia supplies gas to China via the Power of Siberia pipeline. Exports through the route reached 15 bcm last year, with a planned rise to 22 bcm in 2023, according to the company. Experts predict that China’s natural gas consumption will peak before 2035 and account for 10 percent of energy consumption by 2060, primarily used for power generation and peak load regulation. China’s natural gas consumption is expected to exceed 600 bcm around 2035, constituting 15 percent of the primary energy consumption, said Huang Weihe, an academician at the Chinese Academy of Engineering. According to Huang, China will focus on power generation and industrial fuels before 2040 for the development of natural gas, to facilitate the transformation and upgrading of industrial and energy structures. “The ongoing urbanization process in China is among the primary drivers behind the sustained growth in urban natural gas consumption,” he said. “As China’s urbanization accelerates, the urban population continues to expand, leading to an increase in the number of gas consumers, which rose to approximately 413 million by 2020, a growth rate of nearly 45 percent compared with 2013.” By reducing dependence on fossil fuels, increasing the share of nonfossil energy sources and promoting the development and application of natural gas, China can achieve a transformation and upgrade of its energy structure. This will help lower carbon emissions, drive sustainable development, and provide a stable and reliable energy supply for economic growth, he said. Source: China Daily
Gazprom rushes with new pipeline to secure stable gas supplies to China --Russian gas giant Gazprom has revealed the first steps to avoid a potential failure to meet a 30-year supply contract with China National Petroleum Corporation (CNPC), with plans to build a connector pipeline to carry volumes from Russia’s far east. Gazprom had agreed to supply Chinese state company CNPC with 38 billion cubic metres per annum of gas for 30 years, with the Russian company originally planning to send volumes from the Kovykta gas field in East Siberia via the Sila Sibiri 1 pipeline. However, according to a partner in Moscow-based energy consultancy RusEnergy, Mikhail Krutikhin, reserves downgrades at Kovykta following the start-up of commercial production have led Gazprom executives to conclude that it might not be able to maintain the contracted volumes. Russian state news agency Tass this week quoted Gazprom’s projects and investment director Andrey Chekansky as saying the company has started engineering research work to gauge options for building a connector between Sila Sibiri 1 and the Sakhalin-Khabarovsk-Vladivostok pipeline. However, one major hurdle in building the connector is the difficult terrain and almost total lack of infrastructure along the 600-kilometre route. Sila Sibiri 1 started operations in 2019 and carried untreated gas output from the Chayanda and Kovykta fields towards the Russia’s border with China in the Amur region. Gazprom is still building a major gas treatment facility at Amur to remove off-spec contents from the gas stream before it is sent across the border to China, with construction of the facility 89% complete in July. The Amur facility has to be in operation before Gazprom can increase gas exports via Sila Sibiri 1 to the annual contracted volume of 38 Bcm due in 2025. Meanwhile, the connector between Sila Sibiri 1 and the Sakhalin-Khabarovsk-Vladivostok pipeline may enable Gazprom to divert some gas flows from Sakhalin Island via Sila Sibiri 1 and onwards to China to compensate for possible shortfall from Kovykta, Krutikhin suggested. A key supplier to the Sakhalin-Khabarovsk-Vladivostok pipeline is the offshore South Kirinskoye gas field, which holds reserves of over 800 Bcm of gas. However, development of South Kirinskoye has been on hold because of slack domestic gas demand in Russia’s far east, and because of international sanctions prohibiting the supply of Western-manufactured subsea production templates for the project that Gazprom hoped to order from the US. Gazprom is working to extend the Sakhalin-Khabarovsk-Vladivostok pipeline to export gas to eastern China after agreeing in February 2022 to supply another 10 Bcm per annum of gas. It is also possible that the proposed connector could operate in the reverse direction, taking treated gas from Amur to Russia’s far east, from where it can be sent to China if South Kirinskoye’s output does not increase as expected, Krutikhin suggested.
EU imports of petroleum oil from Russia in Q2 2023 down 82% y/y – - Petroleum oils imports into the European Union from Russia fell from a monthly average of 8.7 million tons in the second quarter of 2022 to 1.6 million tons in the second quarter of 2023, a decrease of 82 per cent, EU statistics agency Eurostat said on September 25. In contrast, the imports from the non-EU partners with the exception of Russia increased by 5.8 million tons, from 31.5 million to 37.3 million tons, Eurostat said. Russia’s shares in the EU imports of petroleum oils and natural gas have been decreasing continuously over time since the second quarter of 2022, the statistics agency said. Following a strong increase in energy imports in the EU between 2021 and 2022, the scenario is different in 2023, with imports dropping for the second quarter in a row when compared with the same period in the previous year. In the second quarter of 2023, compared with the same quarter of 2022, EU imports decreased by 39.4 per cent in terms of value and 11.3 per cent in terms of net mass (weight expressed in tons). These results follow declines of 26.5 per cent and 6.1 per cent, respectively, in the first quarter of this year. Russia’s share in total EU imports of petroleum oils was four per cent in the second quarter of 2023, a staggering difference from the 21.6 per cent share recorded in the same quarter of 2022. EU imports of natural gas dropped significantly (-17 per cent in terms of net mass) in the second quarter of 2023, compared with the same quarter in 2022. This reduction could have been triggered by the EU reduction plan, where EU countries committed to reducing gas consumption, Eurostat said. Natural gas imports from Russia fell from a monthly average of 5.1 million tons in the second quarter of 2022 to 2.5 million tons in the second quarter of 2023. Russia’s war of aggression against Ukraine led the EU to implement several packages of sanctions, which directly and indirectly affected the trade of oils and natural gas. “The impact is now visible in a growing diversification of energy suppliers,” Eurostat said.
Russia still No.1 oil source for India despite fall -Russia remained the top supplier of crude oil to India in July as it exported crude oil worth $3.37 billion during the month, showed data from the ministry of commerce and industry. However, compared to June, the imports from Russia declined 11.4% in terms of value. In June, India had imported crude oil worth $3.80 billion. The month-on-month decline comes in the backdrop of narrowing discounts on the Russian oil and with supply cuts by the country in tandem with Opec+ decision, analysts said. India imported crude oil worth $8.96 billion and Russian supplies constituted 37.62% of the overall imports in value terms. Russia has emerged as a major supplier of oil to India in the past 18 months as the country offered discounted oil amid sanctions from the West in reprisal for its invasion of Ukraine. In FY22, Russian oil accounted for only 2% of India’s total oil imports; in FY23, it made up around one-fourth of the 235.52 million tonnes of crude oil imported by India. India’s overall oil import bill fell $10.01 billion in June 2023 to $8.96 billion in July, the data showed. On a year-on-year basis imports, Russian oil imports continued to witness growth as imports from the country rose 42.54% from $2.36 billion in July 2022. For April-July this year, import of crude from Russia stood at $15.74 billion, nearly 127% higher than $6.93 billion during the corresponding period of the last fiscal. This rise of Russia as the top oil supplier to India comes with Opec members losing their market share in India. Iraq, which is traditional oil supplier to India, has witnessed a decline of 38.6% on a YoY basis in its supplies to India during the April-July period at $6.9 billion. Saudi Arabia, the second largest oil producer in the world, sold oil worth $6.90 billion during the first four months of the fiscal, down nearly 27% from the corresponding period of the last fiscal. On a month-on-month basis, too, Iraq and Saudi Arabia witnessed a decline of 6.5% and 5.3%, respectively, as their supplies to India in July stood at $1.76 billion and $1.41 billion. India and China are among the top oil consumers in the world and the West Asian countries would not want to lose these markets, according to analysts. In order to tap these the key Indian market, Iraq has also offered discounts in the past several months and Saudi Arabia has lowered the Asian Premium charged on the oil selling price.
Russian oil sold to India at 30% above Western price cap, traders say (Reuters) - Russia is selling oil to India at nearly $80 per barrel, some $20 above the Western price cap, traders said and Reuters calculations showed, as tight global oil markets help Moscow generate strong appetite for its exports. Russia's main export grade Urals has been trading above the $60 per barrel Western price cap since mid-July amid output cuts by OPEC+ producers, including Saudi Arabia and Russia. India, which is the world's third biggest oil importer, has become the top buyer of seaborne Russian oil, mainly Urals, since 2022 after Western sanctions against Moscow. Calculated Free on Board (FOB) estimates for Urals cargoes loading from Baltic ports in October were close to $80 per barrel on Thursday for Indian customers, according to traders' data and Reuters calculations. "Russia has low inventory levels and their production is also cut," said an official at an Indian refiner that regularly buys Russian oil, explaining the latest jump in prices. Cuts have helped narrow discounts for Urals at Indian ports to $4-$5 per barrel versus dated Brent from $6-$7 per barrel two weeks ago, four trading sources involved in the operations said and Reuters calculations showed. The traders referred to prices for cargoes loading in late October. "Urals prices are on the rise again. Alternatives are much more expensive and not easily available," a trader familiar with the Russian oil market said. Indian refiners did not respond to Reuters' emails seeking comments. Russian Urals oil typically gives higher yields of diesel, which accounts for about two-fifths of India's overall refined fuel consumption. Meanwhile, Russia's decision to ban diesel and gasoline exports added to the appeal of Urals crude, amid a looming shortage of the products globally. The Western price cap on Russian oil allows buyers to use Western services such as shipping and insurance in the event that crude trades below $60 per barrel.
Russia Sells Urals Oil To India At $20 Above The Price Cap - Tightening global crude supply and rising international prices have raised the price at which Russia’s crude is being sold to India at about $20 per barrel over the G7 price cap of $60, traders have told Reuters. The Russian flagship crude grade, Urals, is being sold to one of Moscow’s top customers, India, at nearly $80 per barrel now, or around 30% above the price cap set by the G7 and the EU if Russian crude shipments to third countries outside the EU are to use Western insurance and financing.Data from traders and Reuters calculations showed that free on board (FOB) Urals cargoes to load from Russia’s western ports on the Baltic Sea in October were nearly $80 a barrel for Indian refiners as of Thursday. The tightening global supply, especially crudes from the Middle East which have high diesel yields, have made Russia’s Urals more attractive, due to the discount at which the Russian grades trade relative to the international benchmark Brent. In India, where diesel is the number-one fuel in terms of consumption, Urals is in high demand, despite being much more expensive compared to the first half of this year.But other similar grades, if available at all, are costlier than Urals.“Urals prices are on the rise again. Alternatives are much more expensive and not easily available,” one trader with knowledge of the Russian oil market told Reuters.The price of Urals breached the G7 price cap in July and has averaged well above the ceiling since then.Urals prices averaged $74 per barrel in August, slightly down from August 2022, but way above the G7 price cap of $60 and higher than the July average of $64.37 a barrel, data released by the Russian Finance Ministry showed in early September. Between January and August 2023, the average price of Urals was $56.58 per barrel, compared to an average of $82.13 a barrel for the same period of 2022.
Russia’s Oil Export Revenues To Rise This Year As It Evades The G7 Price Cap -Russia is set to generate higher revenues from oil exports this year despite the price cap imposed on the country by the G7 and EU in response to the country’s invasion of Ukraine.Analysis of shipping data cited by the Financial Times shows that Russia is now shipping three-quarters of its oil overseas without Western insurance—one of the tools the G7 and the EU used to enforce the cap of $60 per barrel.Meanwhile, prices are on the rise and Russian crude is no exception. Urals crude is trading at close to $79 per barrel and ESPO, the Far Eastern blend, is trading at over $88 per barrel.This spring, the FT noted, citing Kpler data, Russia was moving half of its export oil without Western insurance, which suggests “Moscow is becoming more adept at circumventing the cap”.The revelations come amid repeated assurancesfrom the U.S. Treasury Department that the price cap was working as intended.“In just six months, the price cap has contributed to a significant decline in Russian revenue at a key juncture in the war,” Deputy Treasury Secretary Wally Adeyemo said in June.In August, Acting Assistant Secretary for Economic Policy Eric Van Nostrand said that he was “confident that the price cap is achieving its twin goals of restricting Russian revenues while helping stabilise energy markets”. Yet the FT cited the Kyiv School of Economics as estimating that Russia is going to see its revenues from oil exports rise by $15 billion this year thanks to circumvention of the G7 and EU price cap.Critics of the price cap said from the start that enforcing it would be a challenge while circumventing it would be relatively easy. Indeed, Russian, Chinese, and Indian insurers have stepped in to replace Western majors and what media call a “dark fleet” of tankers was built to ship Russian crude around the world without the participation of Western companies.In spite of all that, the price cap and sanctions regime have had a significant effect since Russia’s invasion of Ukraine, costing Russia an estimated $100 billion in oil exports since February 2022.
Russia using European tankers for oil transport despite price cap: report --Despite a Western ban on insuring tankers carrying oil above a set price, Russia continues to use European and “shadow” tankers. -Russia is still using tankers owned by European nations to transport oil despite their price cap, a report has found. According to the Centre for Research on Energy and Clean Air (CREA), 24% of total Russian crude oil exports were moved by tankers owned or insured by price cap-implementing countries. In December 2022, Western nations placed a price cap of $60 per barrel on Russian oil in an attempt to minimise Moscow’s revenue streams after the Russian invasion of Ukraine. The price cap prohibits shipping, insurance and re-insurance companies from handling cargoes of Russian crude around the globe, unless it is sold for less than the price cap. In August 2023, 50% of tankers that were subject to the oil price cap transported crude oil from Russia. Moreover, Russia has assembled a fleet of “shadow tankers” operating without insurance or outside the jurisdiction of countries imposing sanctions. Isaac Levi, CREA’s team lead for Europe-Russia policy, said in a statement on Tuesday: “More than just by use of ‘shadow’ tankers, the impact of the oil price cap has been undermined by a failure of the participating governments to fully enforce the price cap and punish violators.” CREA has recommended lowering the oil price cap, increasing monitoring and enforcement of sanctions, and banning hitherto unsanctioned fossil fuels such as liquefied natural gas, liquefied petroleum gas and pipeline fuels that are allowed into the EU. According to the researchers, these measures will more effectively constrict the Kremlin’s war chest. Off the back of higher oil prices, Russia’s oil revenues rose by 7% in July. Furthermore, Russia’s crude oil exports increased in volume by 50% in the spring, as the state used trade routes with countries without sanctions.
Russia Still Heavily Using European Shipping for Its Oil: Think Tank -Russia is still relying on European shipping to transport its oil even as the country’s supplies exceed Group-of-Seven price caps, according to a researcher. Roughly two-thirds of Russian crude and petroleum products is being transported by vessels insured or owned in nations implementing price caps imposed by the G-7 and its allies, the Helsinki-based Centre for Research on Energy and Clean Air said. That shows Moscow is still heavily using the European shipping industry, it said. The cap was designed to keep enough oil flowing to the world while crimping the Kremlin’s revenue. But as well as still using Western vessels, Russia has assembled a so-called shadow fleet of tankers operating outside jurisdictions of countries imposing sanctions. They tend to carry oil over shorter distances where the same amount of capacity can move more supply, the CREA said. “More than by the use of ‘shadow’ tankers, the impact of the oil price cap has been undermined by a failure of the participating governments to fully enforce the price cap and punish violators,” Isaac Levi, the CREA’s team lead for Europe-Russia policy and energy analysis, said in a statement Tuesday. The G-7 and its allies imposed a cap on Russia’s crude oil exports in December and on refined fuels like gasoline and diesel in February. Russian crude has been trading above the price cap of $60 a barrel since mid-July. Some of the country’s supply sold in Asia has started fetching a premium to benchmarks, and with Brent crude trading near $95 certain Russian grades are trading closer to $100 than $60. Russian crude can exceed the cap if no Western services are involved. About three-quarters of all shadow fleet trips were dedicated to transporting Russian crude, the CREA said.
Fuel exports rebound to a 5-month high but demand woes linger -- With fears of a global slowdown impacting exports, India’s ability to continue as one of the top exporters of fuel, especially to newer markets like the US and Europe, would be a key factor in limiting the country’s widening trade gap. India is the third largest consumer of oil in the world and imports around 85 percent of its requirements from key trading partners. After witnessing a slowdown in the past couple of months, India’s petroleum product exports came in at a five-month high, jumping nearly 41 percent in August 2023 compared to the month before owing to a surge in crude oil prices. But New Delhi may struggle to continue the current run rate on outbound shipments of fuel due to limitations emerging from several areas, ranging from refining capacity, and windfall tax, to diminishing discounts from Russia. A closer look at the data reveals that despite a sequential uptick, the value of India’s fuel exports fell 23 percent year-on-year in the first five months of the current financial year as crude oil prices declined from the elevated levels of July 2022, data from the government's NIRYAT portal showed. "Nearly half the decline in exports so far this year has been driven by the decline in petroleum prices. Though export volumes of petroleum products were up 6 percent, prices are 27 percent lower than a year ago," commerce ministry officials had said on September 15. But a decision by Saudi Arabia and Russia to extend production cuts till the end of 2023 has propelled oil prices higher of late. Brent crude jumped to a 10-month high and breached $94/barrel in mid-September. This was followed by Moscow’s decision to temporarily ban fuel exports, which further exacerbated worries over tight supply, keeping prices elevated.
CNOOC Starts Up Two Oil Projects Offshore China - - CNOOC Ltd. announced Monday the start of production at two oil development projects offshore China, part of efforts to raise full-year production to up to 660 million barrels of oil equivalent (MMboe). The bigger of the two, Lufeng 12-3, is expected to reach a peak production of about 29,000 barrels of crude per day next year, the majority state-owned company said in a press release. "Lufeng 12-3 Oilfield is the largest jointly-developed oilfield in the South China Sea in the past decade", CNOOC said. "It will provide stable energy supply for the Guangdong-Hong Kong-Macao Greater Bay Area and contribute to the high-quality development of local economy". Located in the eastern South China Sea with an average water depth of 787.4 feet (about 240 meters), the project plans to put 13 wells into production. Lufeng 12-3's main production facilities include one wellhead platform and one newly built 100,000-metric ton intelligent floating production, storage and offloading vessel (FPSO), according to CNOOC. In the other project, called Bozhong 28-2 South Oilfield Second Adjustment, CNOOC expects a peak production of 7,600 barrels of petroleum a day in 2024. In Bozhong 28-2 CNOOC plans to commission 21 development wells, consisting of 13 production wells and eight water injection wells, according to the news release. Located in the southern Bohai Sea with an average water depth of 68.9 feet (around 21 meters), the project's main production facilities include one central platform and one water injection subsea pipeline. CNOOC operates the Bozhong 28-2 South Oilfield Second Adjustment with a 100 percent stake, while SK Earthon Co. Ltd. is the operator of Lufeng 12-3 with a 39.2 percent interest, though CNOOC is the majority shareholder with a 60.8 percent interest. The two projects are among several CNOOC has planned for this year, during which it aims to produce 650-660 MMboe net. The company plans to meet 70 percent of the target through domestic production and 30 percent through its overseas operation, according to CNOOC's capital budget announcement January 11. "Net production is expected to reach 690 million to 700 million BOE in 2024 and 730 million to 740 million BOE in 2025", the announcement said. CNOOC has scheduled nine oil and gas projects for startup this year. Besides Bozhong 28-2 and Lufeng 12-3, these include China's Bozhong 19-6 Condensate Gas Field Phase I Development Project and Enping 18-6 Oilfield Development Project, as well as Brazil's Buzios5 Project and Mero2 Project and Guyana's Payara Project, as named in the capital budget announcement.
Uganda seeks Chinese funding for oil pipeline project --Uganda is in the final stages of negotiations with Chinese financiers to help fund a controversial pipeline project after some Western partners pulled out, a senior official said Wednesday. "We are having final discussions with our Chinese partners to provide about half of the finances required for the construction of the EACOP (East African Crude Oil Pipeline)," Irene Bateebe, permanent secretary at the energy ministry, told AFP. "We should be concluding the arrangements with the Chinese financiers this coming month (October)," she added. French energy giant TotalEnergies is leading a multi-billion dollar project to develop Ugandan oilfields and ship the crude through a 1,445-kilometre (900-mile) pipeline to a port in Tanzania. But the scheme has come under fire from human rights groups and environmental campaigners who say it will harm fragile ecosystems and the livelihoods of tens of thousands of local people. The government has vowed to plough ahead despite the opposition, and TotalEnergies says those displaced by the project have been fairly compensated and measures have been taken to protect the environment. "This is a critical project for Uganda," Bateebe said. "Some of our international partners from Europe were forced to pull out from financing this project and as a country, we sourced for other friendly partners to finance the balance of the financing and we are on course."
Iraq approves $1.26bln for Basra oil pipeline project --Iraq’s cabinet has approved around $1.26 billion for a major oil pipeline project that will largely boost the export capacity of the Southern oil hub of Basra. The cabinet, which met under Prime Minister Mohammed Al-Sudani on Tuesday, instructed the Finance Ministry to unlock funds for the project which also involves development of a nearby oil export terminal, Aliqtisad News and other newspapers said. The funds cover the costs of the construction of two pipelines 4 and 5 as part of the ‘Sealine 3’ project that also includes rehabilitation of Khor Al-Amaya oil export terminal and the construction of a new marine platform in Basra Port. Officials said this month the projects would allow Iraq to increase oil production by 500,000 barrels per day (bpd) and avert the loss of two million bpd if these projects are not executed. The Iraqi cabinet in July approved the funds for the “Sealine 3” subsea oil export pipeline project, to be carried out by Dutch firm Boskalis, but the funds remained locked by the Finance Ministry.
Two vessels detained over oil spill in Labuan waters -The Environment Department (DOE) here has detained two vessels in connection with an oil spill near Labuan Shipyard Engineering (LSE) jetty and in Patau-Patau 1 waters. Labuan disaster management committee chairman Rithuan Ismail said the detention of the vessels was carried out in accordance with Section 38 (1)(C) of the Environmental Quality Act 1974. "I have been briefed by the DOE director on the situation, and at present, investigations are under way at five sampling locations to determine the extent of the oil spill in the affected area. "Samples collected are also slated for immediate analysis at the Kota Kinabalu Chemistry Department,” Rithuan said on Monday (Sept 25). He said the findings would help determine and identify the responsible party and bring the case to court. "Clean-up and containment efforts for the oil spill in the affected area were concluded as of Friday (Sept 22),” he said. Rithuan said while much of the oil had naturally decomposed, the DOE is set to issue a Notice of Instruction to LSE to conduct marine water monitoring and sampling to assess the quality of water both immediately after the incident and one week later. The oil spill, which extended across a 1.5km area encompassing the waters around LSE jetty, Patau-Patau 1, and the Maritime Enforcement Agency (MMEA) jetty, was initially reported to the MMEA on Thursday (Sept 21) following a notification from the Labuan Fishermen's Association.
Mideast-Asia oil shipping rates rebound, capped by OPEC+ supply cuts --The cost of chartering a supertanker to load Middle Eastern crude oil for Asia has rebounded from a 19-month low in September, but industry sources expect output supply cuts, led by Saudi Arabia, to cap freight rates for the rest of the year. The world’s benchmark very large crude carrier (VLCC) export route from the Middle East Gulf (MEG) to Japan, known as TD3, rose to W50.46 on Monday in the Worldscale measure of freight rates, LSEG data showed. It fell to W35.60 in September, the lowest since Feb 2022. Freight rates fell after Saudi Arabia started reducing its output by an additional 1 million barrels per day from July. Adding to the pressure, the leading OPEC member, together with major producer Russia, extended their combined 1.3 million bpd supply cuts to December. “VLCC rates have improved as Saudi crude exports rebounded back to July level this month. Saudi is fulfilling term barrels nomination for October delivery and sending more crude to the West simultaneously,” Anoop Singh, global head of shipping research at Oil Brokerage, said. However, Singh said VLCC rates are unlikely to hit the highs of the fourth quarter last year, or levels suggested by tanker futures markets. “We expect Saudi Arabia not to sustain this level of exports and U.S. crude exports to stall as production stops growing and U.S. refineries return from maintenance,” said Singh. China’s buying appetite is likely to ease as it uses crude from its record-high inventories, he added. The voluntary cuts by the Organization of the Petroleum Exporting Countries and allies, notably Russia (OPEC+), sent freight rates for trademark routes across main crude tankers classes to 2023-lows earlier, Ioannis Papadimitriou, senior freight analyst at Vortexa, said. Changes in price spreads that began last week between West Texas Intermediate and Brent, and between Brent and Middle East crude Dubai, have also weakened the economics of shipping oil across regions, which could reduce the need for ships to travel longer distances. “Given the narrow WTI-Brent spread that will potentially restrict further flows to Asia, this might lead to steady-to-higher Middle East volumes,” Emril Jamil, senior analyst for crude and fuel oil at LSEG, said. “In terms of (freight) rates, we may see a small step-up in Q4, but October might still be weak,” said Jamil, adding that he expects weaker October crude volumes to China amid a decline in refining margins. A source from an Asian shipowner company, speaking on condition of anonymity because they were not authorised to speak to the press, said crude supply was “much less”, demand was not increasing and many ships were available, meaning rates were unlikely to rise sharply. Beyond this year, however, some tanker operators expect broader demand growth. “We see markets which can be sustained at least for a couple of years,”
OPEC+ Cuts Offset By Booming U.S. Oil Production - Despite the fact that U.S. oil producers are now deploying the lowest number of drilling rigs in more than a year and a half, America's crude oil production is set to hit a monthly record in September—at 13 million barrels per day (bpd), according to estimates by Rystad Energy. Production growth has slowed due to the discipline U.S. shale producers have shown in the past two years, but a slower increase still means that output is headed higher, the energy research firm says, as carried by The Wall Street Journal. The expected monthly record in September will match the record output from November 2019, the only other month in which U.S. production hit 13 million bpd—just a few months before the pandemic crippled demand, sank oil prices and led to production cuts across the board. U.S. crude oil production is set to increase even more until the end of the year, with October and four-quarter output estimated to average 13 million bpd-13.1 million bpd, according to Rystad Energy's analysis based on regulatory filings, satellite imagery, and pipeline flows. Even at a slower pace, American production is growing and offsetting part of the OPEC+ cuts, although the extended Saudi and Russian supply reductions are set to tighten the global oil market more than previously expected. U.S. shale production "is not growing as fast as before," Alexandre Ramos-Peon, Rystad Energy's head of shale research, told the Journal. "But it doesn't mean that shale has to decline." According to Ramos-Peon and Rystad Energy, all signs point to still growing U.S. shale, although growth is still slower than before Covid. Despite the loss of active drilling rigs, shale firms are producing more oil and gas and have even exceeded some skeptical projections from earlier this year. Last week, the total rig count fell to 630, per the latest Baker Hughes data—the fewest number of active drilling rigs since February 4, 2022. The number of oil rigs fell by 8 last week to 507, down by 114 so far in 2023.
The Oil Market Traded Lower on Monday as Russia Revised its Fuel Ban -- The oil market traded lower on Monday as Russia revised its fuel ban. The market traded mostly sideways in overnight trading and posted a high of $90.83 as the market remained concerned about higher interest rates that could impact demand. However, the crude market erased any of its gains and sold off to a low of $89.03 by mid-day. The market was pressured as Russia approved some changes to its fuel export ban, lifting the restrictions for fuel used as bunkering for some vessels and diesel with high sulfur content. The market later bounced off its low and settled in a sideways trading range during the remainder of the session. The November WTI contract settled down 35 cents at $89.68, while the Brent contract settled up 2 cents at $93.29. The product markets ended in negative territory, with the heating oil market settling down 4.4 cents at $ 3.2622 and the RB market settling down 1.79 cents at $2.5439. The Russian government has approved some changes to its fuel export ban, lifting the restrictions for fuel used as bunkering for some vessels. It also lifted restrictions on the export of fuel already accepted for export by the Russian Railways and Transneft before the initial ban had been announced last week. According to traders and LSEG data, Russia cut its seaborne diesel and gasoil exports by 30% to about 1.7 million metric tons in the first 20 days of September compared with the same period in August.The European Union’s statistics agency, Eurostat, said European Union energy imports continued their downward trend in the second quarter as members further reduced their reliance on Russian supplies. After a strong increase between 2021 and 2022, EU imports fell by 39.4% in value and 11.3% in volume in the second quarter of 2023 on a yearly basis. That followed declines of 26.5% and 6.1% respectively in the first quarter. Russia, the top supplier of petroleum oils to the EU with a market share of 15.9% in the second quarter of 2022, saw that share decline to just 2.7% in the second quarter of this year, making it only the twelfth biggest supplier.IIR Energy reported that U.S. oil refiners are expected to shut in about 1.7 million bpd of capacity in the week ending September 29th, cutting available refining capacity by 324,000 bpd. Offline capacity is expected to increase to 1.9 million bpd in the week ending October 6th.Phillips 66 reported that release of emissions at tis 149,000 bpd Borger, Texas refinery on Friday. It said the even was ongoing and operations personnel was working to minimize emissions from the event.Valero reported an issue at a sulfur recovery unit at the West plant of its 290,000 bpd Corpus Christi, Texas refinery on Saturday. It initiated shutdown sequences, which included the routing of process gases to facility flares.
The Oil Market Rallied Sharply Higher on Wednesday, Posting its Largest One Day Gain Since Early May -The oil market rallied sharply higher on Wednesday, posting its largest one day gain since early May as it continued to trade in its upward trend channel. The market continued to trade higher in overnight trading after it briefly breached the lower boundary of its channel during Tuesday’s session before it rebounded. The market was supported by speculation that the market is looking to test the $100 level. The crude market also continued to extend its gains ahead of the release of the EIA’s weekly petroleum stock report, which showed a larger than expected draw in crude stocks of over 2 million barrels to 416.3 million barrels, the lowest level since December 2, 2022. The crude market rallied over $3.60 as it traded to $94.04 by mid-day following the supportive report and held some resistance at that level before further buying ahead of the close, pushed the market to a high of $94.17. The November WTI contract settled at $93.68 up $3.29 or 3.64%, the largest one day gain since May 5th. The November Brent contract settled up $2.59 at $96.55. The product markets also ended the session sharply higher, with the heating oil market settling up 9.09 cents at $3.3147 and the RB market settling up 3.64 cents at $2.5986. The EIA reported that U.S. crude oil stocks fell more than expected in the week ending September 22nd, with inventories at Cushing, Oklahoma falling to the lowest level in over a year. U.S. crude stocks fell by 2.169 million barrels on the week to 416.3 million barrels, with stocks in Cushing, Oklahoma falling by 943,000 barrels on the week to 22 million barrels. LSEG is estimating MWE gasoline exports to the United States this month have so far reached 736,000 metric tons versus 828,000 metric tons shipped in August. Russia’s President Vladimir Putin ordered his government to make sure retail fuel prices stabilize, seeking additional measures to balance the domestic market following the introduction of a ban on gasoline and diesel exports. He also told the cabinet it needed to act swiftly and that reviewing oil industry taxes was an option. Earlier, Russia’s Deputy Prime Minister, Alexander Novak, told a government meeting chaired by President Vladimir Putin that some new measures, in addition to the fuel export ban, have been under consideration. He said there are proposals to restrict grey fuel export and increase the fuel export duty for resellers. He said there are proposals to restrict grey fuel exports and to raise fuel export duty to 50,000 roubles or $518.24/ton from 20,000 roubles for resellers. Meanwhile, Russia’s Finance Minister, Anton Siluanov, said Russia’s Finance Ministry is ready to provide additional funding to regions to tackle high fuel prices. The Federal Reserve Bank of Dallas said oil and gas activity in three key energy producing states increased modestly in the third quarter but cost increases continue. It said exploration is driving the increase, with the survey’s business activity index, reaching 10.9 in third quarter from zero in the second quarter. The Alaskan Department of Taxation reported Alaskan North Slope production in August averaged 423,290 b/d, down from 430,743 b/d produced in July and some 74,000 b/d below the January average production of 499,016. Seasonal maintenance is the major reason for normal summer production declines. IIR Energy reported that U.S. oil refiners are expected to shut in about 1.8 million bpd of capacity in the week ending September 29th, decreasing available refining capacity by 375,000 bpd. Offline capacity is expected to increase to 1.9 million bpd in the week ending October 6th.
WTI, Brent Oil Futures Consolidate Lower Following September Rally -- Nearest delivered oil futures on the New York Mercantile Exchange and the Intercontinental Exchange Brent contract rallied Wednesday following a reported drawdown in U.S. crude stocks, ignoring an ongoing advance in the dollar further bolstered by strength in the U.S. economy, while some observers see the Chinese economy stabilizing after a summer slowdown. November West Texas Intermediate surged $3.29 on the session to a $93.68 bbl settlement, paring an advance to a $94.17 13-month high on the spot continuous chart reached intrasession after the Energy Information Administration reported the seventh consecutive weekly drawdown in crude stocks at the Cushing tank farm in Oklahoma. Inventory at Cushing is down 49% from a 2023 high of 43.244 million bbl reached in late June to 21.958 million bbl on Sept. 22, with the stock level nearing a point that can cause operational issues. Estimates suggest operational constraints at the WTI delivery point can occur when stocks fall between 16 and 22 million bbl. The inventory drawdown at Cushing spiked an already wide six-month WTI calendar spread, which surged $2.24 on the session to $10.09 bbl -- the widest backwardation since mid-July 2022. U.S. commercial crude stocks fell 2.2 million bbl to 416.287 million bbl in the third week of September, with 943,000 bbl of the draw at Cushing, pressing inventory to a 15-month low, while 15.5 million bbl or 3.6% below the five-year average. Strong export flow amid supply constraints by OPEC+, including an additional 1 million bpd cut in production by Saudi Arabia and pledge by Russia to withhold 300,000 bpd of oil exports through the end of the fourth quarter, has amplified demand by foreign buyers for U.S. crude. EIA data shows U.S. crude exports for the four-week period ended Sept. 22 averaged 4.275 million bpd, 491,000 bpd or 13% above the comparable four weeks in 2022. Bank of America Research in a note to clients on Tuesday said it lifted its price projection for Brent crude for the fourth quarter to $96 bbl on the production cuts by OPEC+, recent gains in refining margins, and expanding economic stimulus in China. "[W]e expect global oil stocks to decline by 70mm over the coming 3 months," said Bank of America Research. ICE November Brent futures settled at $96.55 bbl Wednesday, up $2.59 on the session, trimming an advance to a $97.06 better-than 10-month high on the spot continuation chart. November Brent widened its premium against the December contract by $0.66 to $2.19 bbl, with the six-month calendar spread settling at $8.87 bbl. NYMEX October ULSD futures rallied $0.0909 to a $3.3147 gallon settlement following three down sessions, with the November contract ending the session at $3.2621 gallon in the backwardated market. October RBOB futures gained by a smaller $0.0364 to $2.5986 gallon at settlement, widening a premium to the November contract to $0.0485 gallon ahead of expiration on Friday. "The recent run up in crude oil and the high sustained margins in gasoline have left wholesale NYMEX RBOB (gasoline) prices at the highest seasonal levels in a decade going into winter, a relatively rare event given winter gasoline's higher Reid vapor pressure and thus lower costs economics," said Bank of America Research. "Meanwhile, turbocharged by a run up in crude oil prices and low inventories, diesel prices have raced to match last year's exceptionally high levels despite the growing downside demand pressures on the industrial and manufacturing side." Oil futures rallied despite a strengthening U.S. dollar, which settled at a 106.366 10-month high, gaining 0.4% in index trading against a basket of foreign currencies. In addition to high interest rates which are expected to remain elevated throughout 2024, U.S. economic growth remains resilient compared with a sluggish Eurozone economy and summer slowdown in China. Wednesday morning, the U.S. Census Bureau reported a 0.2% increase in U.S. durable goods orders in August from a downwardly revised July estimate of 5.6% and expectations for a 0.3% monthly decline. Machinery led the advance in new orders, and transportation equipment led increases in shipments, unfilled orders, and inventories. On Thursday, the Bureau of Economic Analysis will release its third and final estimate for annualized U.S. gross domestic product growth in the second quarter, which is expected to be bumped up from 2.1% to 2.3%. The Atlanta Federal Reserve's GDPNow indicator suggests U.S. GDP in the third quarter would grow at a 4.9% annualized rate. Meanwhile, "China's economy has recently shown some signs of stabilization, and the government still has many policy levers to pull," Beijing hasn't provided large fiscal or monetary stimulus as it has in the past, instead choosing targeted measures, including modest interest rate cuts, reduced restrictions on property buying, and policies to help lower local government debt.
Oil falls as macroeconomic concerns dampen price rally - Oil prices fell on Friday in a volatile trading session, as macroeconomic concerns weighed on the recent rally. Front-month Brent November futures were down 14 cents, or 0.15%, at $95.24 per barrel at 1442 GMT ahead of the contract’s expiry later in the day. The more liquid Brent December contract was down 72 cents, or 0.77%, at $92.38 per barrel. U.S. West Texas Intermediate crude (WTI) was down 92 cents, or 1%, to $90.79 per barrel. WTI futures traded $1 higher earlier in the session, before then trading $1 below Thursday’s close price. With oil futures inching closer to the $100 a barrel threshold, investors could be taking stock of the current rally given ongoing macroeconomic concerns. “But with investors now questioning the resilience of the global economy going into next year against the backdrop of higher interest rates for longer, that bullish bias in oil markets may become more balanced,” said Craig Erlam, an analyst at OANDA. Investors may also be looking ahead to a potential partial U.S. government shutdown on Sunday. A shutdown would be an “unnecessary risk” to a resilient U.S. economy, top White House economic adviser Lael Brainard said on Friday. U.S. consumer spending increased 0.4% in August, while personal consumption expenditures (PCE) price index data showed that inflation excluding volatile food and energy prices slowed to 0.1% last month, from 0.2% in July. Also next week, the OPEC+ ministerial panel meeting will take place on Oct. 4. “Next week’s OPEC meeting will be a key update for the market with increasing probability the voluntary supply cuts by Aramco are reduced,” National Australia Bank analysts said in a client note, referring to Saudi Arabia’s state oil producer. Brent is forecast to average $89.85 a barrel in the fourth quarter and $86.45 in 2024, according to a survey of 42 economists compiled by Reuters on Friday. The supply cuts announced by Saudi Arabia and Russia will dominate oil prices for the remainder of this year, but a run towards $100 per barrel could be short-lived because of “the artificial nature of supply shortages in the system, and the fragile macro environment,” said Suvro Sarkar, energy sector team lead at DBS Bank.
US Expresses Support for Anti-Assad Protesters in Southern Syria - A US official spoke with a Druze spiritual leader to express support for protests against the government of Syrian President Bashar al-Assad that have been taking place in Syria’s southern Suwayda governate. The US Embassy in Syria wrote on X that Deputy Assistant Secretary of State Ethan Goldrich “spoke with Druze spiritual leader Sheikh Hekmat al-Hajari reiterating our support for Syrians’ freedom of expression, including peaceful protest in Suwayda.” According to The Cradle, the protests in Suwayda, a Druze-majority area, broke out on August 16 after the Syrian government raised civil servant salaries but cut fuel subsidies amid a collapse in the value of the Syrian pound. The demonstrations have continued since then with calls for the overthrow of Assad. Three members of Congress also recently spoke with al-Hajari to express bipartisan support for the protests, Reps. Joe Wilson (R-SC), Brendan Boyle (D-PA), and French Hill (R-AR). Boyle told The Nationallast week that he “reaffirmed bipartisan congressional support for the peaceful protests in Suwayda” during his conversation with al-Hajari. The support for the protests comes as the US is looking to exert more pressure on the Assad government as more countries are normalizing with Syria. Assad recently traveled to China for the first time since war broke out in Syria in 2011. Back in May, the Arab League voted to readmit Syria despite opposition from the US. US sanctions on Syria are specifically designed to prevent the country’s reconstructionand have had a devastating impact on the civilian population, creating the economic conditions that sparked the Suwayda protests. On top of the sanctions, the US backs the Kurdish-led SDF in Syria, allowing the US to occupy about one-third of Syria’s territory in the east, where most of the country’s oil and wheat resources are located.
Ukraine Asks West to Bomb Drone Factories in Iran and Syria - Ukraine asked its Western backers to bomb drone factories in Iran, Syria, and in Russia, The Guardian reported on Wednesday, citing a document Kyiv submitted to the G7 in August.In the document, Kyiv alleged that Iranian drones Russia has used to bombard Ukraine contain Western components. Ukraine claims that Iran had diversified its drone production using a factory in Syria and that the production would eventually shift to Russia.The document suggests that Ukraine’s Western backers could launch “missile strikes on the production plants of these UAVs in Iran, Syria, as well as on a potential production site in the Russian Federation.”The document says that Ukraine could launch the strikes if provided with the weapons capable of doing so. “The above may be carried out by the Ukrainian defense forces if partners provide the necessary means of destruction,” it says.For their part, Iran has denied that it has provided Russia with drones since the invasion of Ukraine was launched, a claim Iranian President Ebrahim Raisi reaffirmed last week at the UN General Assembly.The Ukrainian document claims Iran is trying to “disassociate itself from providing Russia with weapons” and “cannot cope with Russian demand and the intensity of use in Ukraine.”
Iran Says Netanyahu Threatened Nuclear Attack in UN Speech - Iran has lodged a formal complaint to the UN accusing Israeli Prime Minister Benjamin Netanyahu of threatening a nuclear attack on the Islamic Republic.In his speech at the UN General Assembly last week, Netanyahu said, “Above all — above all — Iran must face a credible nuclear threat. As long as I’m prime minister of Israel, I will do everything in my power to prevent Iran from getting nuclear weapons.”Netanyahu’s office later said he misspoke, insisting the prepared speech said “credible military threat” instead of “credible nuclear threat.” Iran still issued a complaint, noting that Israel has an arsenal of nuclear weapons that it does not acknowledge.Iranian Ambassador to the UN Amir Saeid Iravani accused Netanyahu of making “explicit threats to use nuclear weapons against an independent member state of the United Nations.” Iravani said the threat is more serious coming from Israel, which he described as an “illegitimate regime that has been widely condemned for aggressions, for apartheid policies and for support for terrorism, as well as for possessing an arsenal of weapons of mass destruction alongside advanced conventional weapons.” The Iranian envoy said the “use or even the mere threat of using nuclear weapons, regardless of the circumstances, by anyone, at any time and in any place, is a clear violation of international laws.”
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