oil prices finished lower for just the second time in 12 weeks this week, as a surprise crude inventory increase cut off a rally that had been underpinned by hope that the Biden stimulus plan would boost demand for fuel....after rising 12 cents or 0.2% to $52.36 a barrel last week as a weaker dollar and falling crude inventories supported prices, the contract price of US light sweet crude for February delivery opened lower on Tuesday after falling Monday in overseas markets on a stronger dollar and fears of soaring Covid 19 cases worldwide, but rallied off the early lows to close 62 cents higher at $52.98 a barrel on a weakening dollar and hopes that Biden's $1.9 trillion coronavirus relief plan would increase the demand for fuel...oil prices opened 15 cents higher Wednesday but dipped back toward $53 a barrel as pessimism over the short-term demand outlook in the world’s two largest economies was partially offset by more weakness in the dollar, but recovered to close 26 cents higher at $53.24 a barrel with prospects for further economic stimulus under Biden boosting the outlook for demand as trading in the February US oil contract expired...with the markets now quoting the contract price of US light sweet crude for March delivery, which had risen 33 cents to $53.31 on Wednesday, oil prices steadied on Thursday after industry data showed a surprise increase in U.S. crude inventories that revived pandemic-related fuel demand concerns as the March oil contract closed 18 cents lower at $53.13 a barrel...oil prices extended their losses on Friday after the EIA report surprisingly confirmed that US crude inventories had indeed risen for the first time this year, as the March oil contract fell 86 cents to $52.27 a barrel, weighed down by the oil inventory build and worries that new pandemic restrictions in China would curb fuel demand in the world’s biggest oil importer...oil price quotes thus finished the week 9 cents or 0.2% lower, while the March contract, which had ended last week priced at $52.42 a barrel, finished 15 cents or 0.3% lower...
natural gas prices, meanwhile, finished much lower, as the threat for an outbreak of polar weather, which had been supporting prices, petered out..after rising 1.4% to $2.737 per mmBTU last week as traders bet that a polar air mass would arrive in late January, the contract price of natural gas for February delivery opened 3% lower on Tuesday, after forecasts over the holiday weekend trended warmer for late January and early next month, and tumbled lower throughout the day to finish 19.1 cents or 7% lower at $2.546 per mmBTU in the largest one-day price drop this year...natural gas futures fell again on Wednesday as traders absorbed dwindling expectations for strong weather-driven demand, moderating LNG levels and a change in control in the nation’s capital, shedding seven-tenths of a cent to settle at $2.539 per mmBTU, and then fell another 4.8 cents on Thursday as both the domestic and the European weather models shifted even warmer...natural gas prices fell for a fourth-consecutive day to end the week, with weakened weather demand expectations and lower U.S. export levels overshadowing a government inventory report that showed the steepest withdrawal of the season, as the February contract settled lower 4.5 cents at $2.446 per mmBTU, thus finishng the week down more than 10.6% from the prior week's finish...
the natural gas storage report from the EIA for the week ending January 15th indicated that the amount of natural gas held in underground storage in the US fell by 187 billion cubic feet to 3,009 billion cubic feet by the end of the week, which left our gas supplies just 36 billion cubic feet, or 1.2% higher than the 3,045 billion cubic feet that were in storage on January 15th of last year, but still 198 billion cubic feet, or 7.0% above the five-year average of 2,811 billion cubic feet of natural gas that have been in storage as of the 15th of January in recent years....the 187 billion cubic feet that were drawn out of US natural gas storage this week was 10 billion cubic feet more than the average forecast of a 177 billion cubic foot withdrawal from an S&P Global Platts survey of analysts, and way more than the 97 billion cubic foot withdrawal from natural gas storage seen during the corresponding week of a year earlier, as well as more than the average withdrawal of 167 billion cubic feet of natural gas that have typically been pulled out of natural gas storage during the same week over the past 5 years...
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending January 15th indicated that because of a large drop in our oil exports, we had surplus oil left to add to our stored commercial crude supplies for the 2nd time in the past nine weeks and for the 8th time in the past twenty-six weeks... our imports of crude oil fell by an average of 194,000 barrels per day to an average of 6,045,000 barrels per day, after rising by an average of 870,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 760,000 barrels per day to 2,251,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 3,794,000 barrels of per day during the week ending January 15th, 566,000 more barrels per day than the net of our imports minus our exports during the prior week...over the same period, the production of crude oil from US wells was reportedly unchanged at 11,000,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production totaled an average of 14,794,000 barrels per day during this reporting week...
meanwhile, US oil refineries reported they were processing 14,760,000 barrels of crude per day during the week ending January 15th, 110,000 more barrels per day than the amount of oil they used during the prior week, while over the same period the EIA's surveys indicated that an average of 622,000 barrels of oil per day were being added to the supplies of oil stored in the US....so looking at that data, this week's crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports and from oilfield production was 588,000 barrels per day less than what what was added to storage plus what our oil refineries reported they used during the week....to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a (+588,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the average daily supply of oil and the data for the average daily consumption of it balance out, essentially a balance sheet fudge factor that they label in their footnotes as "unaccounted for crude oil", thus suggesting that there must have been an error or errors of that magnitude in the oil supply & demand figures that we have just transcribed....moreover, since last week's line 13 balance sheet adjustment was (-42,000) barrels per day, indicating a week over week difference of 630,000 barrels per day in the fudge factor, the difference between those 'errors' also means any week over week comparisons of oil supply and demand figures reported here are pretty useless...still, since most everyone treats these weekly EIA figures as gospel and since these numbers often drive oil pricing and hence decisions to drill or complete wells, we'll continue to report them as published, just as they're watched & believed to be accurate by most everyone in the industry.....(for more on how this weekly oil data is gathered, and the possible reasons for that "unaccounted for" oil, see this EIA explainer)....
further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports rose to an average of 5,745,000 barrels per day last week, which was still 11.8% less than the 6,516,000 barrel per day average that we were importing over the same four-week period last year.....the 622,000 barrel per day addition to our total crude inventories was all added to our commercially available stocks of crude oil, while the quantity of oil stored in our Strategic Petroleum Reserve remained unchanged....this week's crude oil production was reported to be unchanged at 11,000,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was unchanged at 10,500,000 barrels per day, while a 5,000 barrel per day decrease to 506,000 barrels per day in Alaska's oil production had no impact on the rounded national total....last year's US crude oil production for the week ending January 17th was rounded to 13,000,000 barrels per day, so this reporting week's rounded oil production figure was 15.4% below that of a year ago, yet still 30.5% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016...
meanwhile, US oil refineries were operating at 82.5% of their capacity while using those 14,760,000 barrels of crude per day during the week ending January 15th, up from 82.0% of capacity during the prior week, and the highest refinery utilization rate since March 20th....however, since US refinery utilization had averaged the lowest on record through 2020, the 14,760,000 barrels per day of oil that were refined this week were still 12.4% fewer barrels than the 16,857,000 barrels of crude that were being processed daily during the week ending January 17th of last year, when US refineries were operating at 90.5% of capacity...
with the increase in the amount of oil being refined, the gasoline output from our refineries was higher for the 3rd time in 9 weeks, increasing by a record 1,373,000 barrels per day to 8,885,000 barrels per day during the week ending January 15th, after our gasoline output had decreased by 1,679,000 barrels per day over the prior two weeks...but since our gasoline production was still recovering from a multi-year low in the wake of this Spring's covid-related lockdowns, that jump still left this week's gasoline output 6.8% lower than the 9,535,000 barrels of gasoline that were being produced daily over the same week of last year....meanwhile, our refineries' production of distillate fuels (diesel fuel and heat oil) decreased by 132,000 barrels per day to 4,529,000 barrels per day, after our distillates output had decreased by 124,000 barrels per day over the prior week....and since our distillates' production was also just coming off a three year low, that output was 8.6% less than the 4,954,000 barrels of distillates that were being produced daily during the week ending January 17th, 2020...
even with the big jump in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the third time in nine weeks, and for 17th time in 28 weeks, falling by a modest 259,000 barrels to 245,217,000 barrels during the week ending January 15th, after our gasoline inventories had increased by 4,395,000 barrels over the prior week...our gasoline supplies decreased this week because the amount of gasoline supplied to US users increased by 580,000 barrels per day to 8,112,000 barrels per day, and because our exports of gasoline rose by 133,000 barrels per day to 731,000 barrels per day, while our imports of gasoline rose by 121,000 barrels per day to 504,000 barrels per day....after this week's inventory decrease, our gasoline supplies were 5.7% lower than last January 17th's gasoline inventories of 260,032,000 barrels, and about 3% below the five year average of our gasoline supplies for this time of the year...
meanwhile, even with the decrease in our distillates production, our supplies of distillate fuels increased for the 7th time in 8 weeks and for the 23rd time in the past year, rising by 457,000 barrels to 163,662,000 barrels during the week ending January 15th, after our distillates supplies had increased by 4,786,000 barrels during the prior week....our distillates supplies rose by less this week than last because the amount of distillates supplied to US markets, an indicator of our domestic demand, rose by 212,000 barrels per day to 3,821,000 barrels per day, and because our exports of distillates rose by 388,000 barrels per day to 1,102,000 barrels per day, while our imports of distillates rose by 114,000 barrels per day to 460,000 barrels per day....after this week's inventory increase, our distillate supplies at the end of the week were 12.1% above the 146,036,000 barrels of distillates that we had in storage on January 17th, 2020, and about 8% above the five year average of distillates stocks for this time of the year...
finally, with the big decrease in our oil exports, our commercial supplies of crude oil in storage (not including the commercial oil being stored in the SPR) rose for the 12th time in the past thirty-two weeks and for the 30th time in the past year, increasing by 4,352,000 barrels, from 482,211,000 barrels on January 8th to 486,563,000 barrels on January 15th...after that increase, our commercial crude oil inventories were about 9% above the five-year average of crude oil supplies for this time of year, and about 47.7% above the prior 5 year (2011 - 2015) average of our crude oil stocks as of the third weekend of January, with the disparity between those comparisons arising because it wasn't until early 2015 that our oil inventories first topped 400 million barrels....since our crude oil inventories had generally been rising over the past two years, except for this autumn and during the past two summers, after generally falling over the year and a half prior to September of 2018, our commercial crude oil supplies as of January 15th were still 13.7% more than the 428,106,000 barrels of oil we had in commercial storage on January 17th of 2020, and also 9.3% above the 445,025,000 barrels of oil that we had in storage on January 18th of 2019, and 18.2% more than the 411,583,000 barrels of oil we had in commercial storage on January 19th of 2018...
This Week's Rig Count
The US rig count rose for the 18th time in the past nineteen weeks during the week ending January 22nd, but for just the 20th time in the past 45 weeks, and hence it is still down by 52.4% over that forty-four week period....Baker Hughes reported that the total count of rotary rigs running in the US rose by 5 to 378 rigs this past week, which was still down by 416 rigs from the 794 rigs that were in use as of the January 24th report of 2020, and was also still 26 fewer rigs than the all time low rig count prior to 2020, and 1,551 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began to flood the global oil market in their first attempt to put US shale out of business....
The number of rigs drilling for oil increased by 2 rigs to 289 oil rigs this week, after rising by 12 oil rigs the prior week, still leaving us with 389 fewer oil rigs than were running a year ago, and still less than a fifth of the recent high of 1609 rigs that were drilling for oil on October 10th, 2014....at the same time, the number of drilling rigs targeting natural gas bearing formations increased by 3 to 88 natural gas rigs, which was still down by 27 natural gas rigs from the 115 natural gas rigs that were drilling a year ago, and still just 5.5% of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008...in addition to those rigs drilling for oil or gas, one rig classified as 'miscellaneous' continued to drill in Lake County, California this week, while a year ago there were three such "miscellaneous" rigs deployed...
The Gulf of Mexico rig count was unchanged at 16 rigs this week, with 15 of those rigs drilling for oil in Louisiana's offshore waters and one drilling for oil offshore from Texas...that was 5 fewer Gulf of Mexico rigs than the 21 rigs drilling in the Gulf a year ago, when 19 Gulf rigs were drilling for oil offshore from Louisiana, one rig was drilling for natural gas in the Mississippi Canyon offshore from Louisiana, and one rig was drilling for oil offshore from Texas...since there are no rigs operating off of other US shores at this time, nor were there a year ago, this week's national offshore rig figures are equal to the Gulf rig counts....however, in addition to those rigs drilling in the Gulf, 3 rigs continue to drill through inland bodies of water this week, one in Lafourche Parish, south of New Orleans, another in St Mary parish, farther west along the southern Louisiana coast, and another in Chambers County, Texas, just east of Houston, while a year ago there was just one rig drilling on US inland waters..
The count of active horizontal drilling rigs was up by 6 to 338 horizontal rigs this week, which was still 372 fewer horizontal rigs than the 710 horizontal rigs that were in use in the US on January 24th of last year, and less than a quarter of the record of 1372 horizontal rigs that were deployed on November 21st of 2014...on the other hand, the vertical rig count was down by one to 18 vertical rigs this week, and those were also also down by 19 from the 37 vertical rigs that were operating during the same week a year ago....meanwhile, the directional rig count was unchanged at 22 directional rigs this week, and those were still down by 25 from the 47 directional rigs that were in use on January 24th of 2020....
The details on this week's changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes...the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins...in both tables, the first column shows the active rig count as of January 22nd, the second column shows the change in the number of working rigs between last week's count (January 15th) and this week's (January 22nd) count, the third column shows last week's January 15th 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 24th of January, 2020..
the details on the rig changes that occurred this week aren't particularly evident at first glance...checking first for the details on the Permian in Texas from the Rigs by State file at Baker Hughes, we find that there were 4 new rigs added in Texas Oil District 8, which corresponds to the core Permian Delaware, while the rig counts in the other Texas Permian districts were unchanged, and hence the Permian basin in Texas saw an increase of 4 rigs this week...since the national Permian rig count was down by 1, that means that all five of the rigs that were pulled out in New Mexico must have come from the far west reaches of the Permian Delaware, to account for the national Permian basin rig decrease...elsewhere in Texas, there was a natural gas rig added in Texas Oil District 5, which would account for the rig increase in the Barnett shale, and another rig added in Texas Oil District 6, which should account for the natural gas rig increase in the Haynesville shale, and also account for the 6 rig increase in the state of Texas...other natural gas rig activity this week included a rig that was added in Ohio's Utica shale, a rig that was added in West Virginia's Marcellus, and a natural gas rig that was pulled out of the Marcellus in Pennsylvania...other oil rig additions this week were in North Dakota's Williston basin and two oil rigs added in Alaska, in a basin or basins that Baker Hughes doesn't name...
DUC well report for December
Tuesday of this past week saw the release of the EIA's Drilling Productivity Report for January, which includes the EIA's December data for drilled but uncompleted oil and gas wells in the 7 most productive shale regions....that data showed a decrease in uncompleted wells nationally for the 18th time in the past twenty-two months in December, as completions of drilled wells and drilling of new wells both increased, but still remained relatively subued....for the 7 sedimentary regions covered by this report, the total count of DUC wells decreased by 145 wells, falling from 7,443 DUC wells in November to 7,298 DUC wells in December, which was also 9.5% fewer DUCs than the 8,067 wells that had been drilled but remained uncompleted as of the end of December of a year ago...this month's DUC decrease occurred as 373 wells were drilled in the 7 regions that this report covers (representing 87% of all U.S. onshore drilling operations) during December, up from the 334 wells that were drilled in November, while 518 wells were completed and brought into production by fracking, up from the 497 completions seen in November, but down by more than half from the 1,039 completions seen in December of last year....at the December completion rate, the 7,298 drilled but uncompleted wells left at the end of the month represents a 14.1 month backlog of wells that have been drilled but are not yet fracked, down from the 15.2 month DUC well backlog of a month ago, with the understanding that this normally indicative backlog ratio is being skewed by a completion rate that is one-third of the previous norm...
both oil producing regions and natural gas producing regions saw DUC well decreases in November, and no basins reported DUC increases...the number of uncompleted wells remaining in the Niobrara chalk of the Rockies' front range fell by 38, decreasing from 480 at the end of November to 442 DUC wells at the end of December, as 32 wells were drilled into the Niobrara chalk during November, while 70 Niobrara wells were being fracked....at the same time, DUC wells in the Eagle Ford of south Texas decreased by 29, from 1,025 DUC wells at the end of November to 996 DUCs at the end of December, as 37 wells were drilled in the Eagle Ford during December, while 66 already drilled Eagle Ford wells were completed...meanwhile, the number of uncompleted wells remaining in Oklahoma's Anadarko decreased by 22, falling from 678 at the end of November to 656 DUC wells at the end of December, as just 15 wells were drilled into the Anadarko basin during December, while 37 Anadarko wells were being fracked....in addition, DUCs in the Permian basin of west Texas and New Mexico decreased by 21, from 3,545 DUC wells at the end of November to 3,524 DUCs at the end of December, as 169 new wells were drilled into the Permian, while 190 wells in the region were completed...and there was also a decrease of 17 DUC wells in the Bakken of North Dakota, where DUC wells fell from 795 at the end of November to 778 DUCs at the end of December, as 20 wells were drilled into the Bakken during December, while 37 of the drilled wells in that basin were being fracked...
among the natural gas producing regions, the drilled but uncompleted well count in the Appalachian region, which includes the Utica shale, fell by 12 wells, from 596 DUCs at the end of November to 584 DUCs at the end of December, as 61 wells were drilled into the Marcellus and Utica shales during the month, while 73 of the already drilled wells in the region were fracked....at the same time, the natural gas producing Haynesville shale of the northern Louisiana-Texas border region saw their uncompleted well inventory decrease by 6 to 318, as 39 wells were drilled into the Haynesville during December, while 45 of the already drilled Haynesville wells were fracked during the same period....thus, for the month of December, DUCs in the five major oil-producing basins tracked by this report (ie., the Anadarko, Bakken, Niobrara, Permian, and Eagle Ford) decreased by a total of 127 wells to 6,396 wells, while the uncompleted well count in the natural gas basins (the Marcellus, Utica, and the Haynesville) decreased by 18 wells to 902 wells, although as this report notes, once into production, more than half the wells drilled nationally will produce both oil and gas...
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Ohio Utica Production Falls Off in Tough First Quarter for Operators - Ohio’s unconventional oil and natural gas production declined sharply in the first quarter as operators grappled with a challenging period in which energy demand crumbled due to the coronavirus pandemic and commodity prices followed with a historic decline. Unconventional natural gas production, driven almost entirely by volumes from the Utica Shale, was 581.6 Bcf during the period, down 15% from the 684.8 Bcf reported in 4Q2019, according to the Ohio Department of Natural Resources (ODNR). Unconventional oil production, also largely from the Utica, declined by 13% over the same period and came in at 5.8 million bbl.Year/year figures were a bit different, as unconventional gas production dropped by 5% from 1Q2019 and oil production increased by 16%. Operators also faced headwinds early last year as they curbed spending and some production as investors searched for better returns and gas prices were low. But 1Q2020 saw significant production curtailments and spending cuts as operators in Appalachia and across the country grappled with the pandemic’s fallout. Appalachian producers shut in both wet and dry gas production. The belt tightening came on top of plans to cut spending heading in 2020 given surplus U.S. gas supplies and stagnant prices. ODNR said the average amount of oil produced by each well during the first quarter was 2,346 bbl, while the average amount of natural gas produced by each was 231.8 MMcf. Ohio law does not require the separate reporting of natural gas liquids or condensate. Oil and gas totals include those volumes. The agency’s latest production report lists 2,573 horizontal shale wells, of which 2,509 reported production.
Buckeye XPress Project Placed in Service in Ohio - TC Energy’s U.S. Natural Gas team started the new year on a high note, placing into service its Buckeye XPress (BXP) project in southern Ohio. The milestone comes just in time as winter weather permeates the U.S. Midwest and temperatures drop, according to a Jan. 19 company statement. BXP adds approximately 275 million cubic feet per day (MMcf/d) of natural gas produced in the region and will be used to heat and power homes and businesses for years to come. “The in-service milestone demonstrates our commitment to delivering the energy Americans need, every day,” said Stanley Chapman III, TC Energy executive vice president and president the company’s U.S. and Mexico Natural Gas Pipelines. “BXP improves reliability along a critical natural gas supply route in southern Ohio and helped support local economies during a difficult year. “I am proud of our team for completing this project safely and with stewardship for the environment,” Stan added. BXP involved the replacement of 66 miles of existing pipeline with safer, more reliable, 36-in. diameter coated pipe, enhancing the sustainability of TC Energy’s infrastructure. The project proceeded cautiously in a year beset by a global pandemic and an economic slowdown. TC Energy worked with its contractors to come up with a comprehensive COVID-19 response plan. The company hired locally and enlisted a few local restaurants and cafés to feed its crews. TC Energy also donated to food pantries and emergency medical services.
Akron wants to sell mineral rights for the fracking of 475 acres of water shed land - Akron Beacon Journal - Akron Council has given initial approval of a deal to allow horizontal drilling and fracking under 475 acres of public land at the La Due Reservoir, which is upstream from the city’s main drinking water supply along the Cuyahoga River.“We’ve been working on this for probably a year and we’ve been watching the oil prices,” Public Service Director Chris Ludle told Council Monday during a committee meeting.If approved again by all of council on Jan. 25, the deal would add another red triangle to a map almost completely covered by red triangles — each representing an oil or gas well in Geauga County where the reservoir is located.Akron owns and manages about 33% of the Cuyahoga River shoreline through Portage and Geauga counties. The city protects wildlife and wetlands, manages the forestry and keeps the water shed fenced as part of a broader effort to safeguard the drinking supply. The gas well deal would allow the city to continue these environmental efforts while tapping into revenue streams locked thousands of feet below the surface where the Utica and Marcellus shale formation overlap in eastern Ohio.The deal would give the city a one-time payment of $500 and acre, or $237,500 total, Ludle said. In addition, the city would get 15% of the royalties for any producing wells. Drilling would not be permitted on the city’s 475 acres just south of the reservoir. Instead, the city said the operator, DP Energy Auburn LLC, would use adjacent, private property to drill down then turn horizontally to reach potential reserves below the city land. If the wells are dry, the contract says they would need to be capped after three years, at which point the city would take back the mineral rights. DP Energy Auburn LLC could not be reached for comment. According to Ohio Secretary of State records, the company was incorporated to do business in Ohio on Jan. 1 by Patrick D’Andrea, an Akron attorney whose website says he “handles oil and gas, real estate development, and personal injury cases.” Ludle said the 475 acres in question represent 3% of the public land around the reservoir. The deal would not allow the drilling company to access the land unless given city approval. And there would be no storage tanks, equipment or access roads installed on the city land.
Akron City Council considers allowing fracking on city-owned land near reservoir in Geauga County connected to Cuyahoga River - cleveland.com– City Council is considering a deal to allow a company to drill and frack under 475 acres of city-owned land at LaDue Reservoir in Geauga County, upstream from Akron’s drinking water supply on the Cuyahoga River.And while the city relies on surface water from Lake Rockwell for its drinking water supply, the potential environmental impact on ground water from fracking still has stirred some concerns.The company – DP Energy Auburn, LLC – owns properties adjacent to the city-owned land and is offering the city $237,500, or $500 per acre. Akron would also receive 15% of the royalties for any oil or gas produced by the wells. “They will be putting gas and oil wells on adjacent properties, so none of the equipment - no drilling equipment, no tank batteries, no road access - will be on City of Akron property,” Public Service Director Chris Ludle told the Planning and Economic Development Committee. “They are using our property to gather enough land to drill these wells.” DP Energy Auburn is seeking to drill horizontally under the city-owned land. If the city does not approve the deal, the company will likely drill underneath adjacent properties it already owns, Ludle said. And in the event that they strike oil or gas, “if that vein goes from our land to their land, how do we know that they’re not drawing under our land and taking the oil and gas?” Ludle said. Ludle said the city has been negotiating with DP Energy Auburn for “about a year,” and that his office has been watching oil prices fluctuate. If the company drills and doesn’t hit anything within three years, it will be required to cap the well and all the mineral rights revert back to the city, Ludle said. DP Energy Auburn was registered with the Ohio Secretary of State’s office on Jan. 1, records show, to Akron attorney Patrick D’Andrea. According to his law firm’s website, D’Andrea was an Akron City Councilman from 1979 to 1989 and a former Summit County Director of Development who currently “represents numerous landowners and small businesses in the Ohio Utica and Marcellus Shale Oil and Gas play included leases and leasing, amending existing leases, pipeline agreements and rights of way, oil and gas mineral sales, location agreements and much more.” D’Andrea did not immediately respond to an inquiry from cleveland.com and The Plain Dealer. Akron owns about one-third of the Cuyahoga River shoreline through Portage and Geauga counties. LaDue Reservoir, formerly called the Akron City Reservoir, is in Auburn and Troy townships and connects to Bridge Creek and Black Brook, both tributaries of the Cuyahoga River. On Jan. 11, the Planning and Economic Development Committee voted to put the proposal on the consent agenda, a set of legislation routinely passed during the following week’s regular council meeting. At-Large Councilman Jeff Fusco, At-Large Councilwoman Ginger Baylor and Ward 7 Councilman Donnie Kammer voted in favor of placing it on the consent agenda, while Ward 5 Councilwoman Tara Samples shook her head and abstained from the vote. Within days, Samples moved to pull the proposal from the consent agenda.
Will states use the Capitol riot to crack down on pipeline protests? - Early last week, with national attention focused on accountability for the pro-Trump rioters who stormed the capitol building in Washington, D.C., Ohio quietly became the 13th state since 2017 to legislate harsher penalties for trespassing on or otherwise interfering with energy and industrial infrastructure — a move that activists and civil liberties groups say is a transparent attempt to criminalize nonviolent protest.“The whole idea behind this is to chill protests at oil and gas industry sites,” said Reverend Joan Van Becelaere, the executive director of the Unitarian Universalist Justice of Ohio, a liberal, faith-based nonprofit focused on immigration, environmental, and economic justice. “It will really cause nonprofits, churches, and other groups that are concerned about climate justice to think twice about sponsoring any protest or demonstration.”Ohio’s Republican governor, Mike DeWine, signed Senate Bill 33 on Monday, making trespassing on oil and gas sites a first-degree misdemeanor punishable with up to six months in prison and a $1,000 fine. (Criminal trespass in Ohio is already a fourth-degree misdemeanor punishable with up to a month in prison and $250 in fines.) The new legislation ups the penalty for trespassing on property with so-called critical infrastructure, a long list of facilities including pipelines, compressor stations, chemical plants, and telephone poles. It also makes “improperly tamper[ing]” with critical infrastructure a third-degree felony that could result in up to five years in prison. Organizations that support such activities could also face civil lawsuits and up to $100,000 in fines. (A spokesperson for DeWine did not respond to Grist’s questions about the governor’s support for the legislation.) The bill was first introduced almost two years ago and passed the state senate in May 2019. For most of 2020, however, the state’s Republican lawmakers focused on blocking DeWine’s coronavirus-related public health orders and the fallout after key lawmakers were arrested for allegedly accepting bribes to bail out two nuclear plants, so the critical infrastructure bill languished in the legislature’s lower chamber. But during the last week of the legislative session in December, the bill found new life. It passed the state’s house of representatives and was sent to the governor’s desk on the last day of the session.
Antero Resources (AR) Jumps 24.8% in a Month: Here's Why - Antero Resources Corporation’s shares have jumped 24.8% in the past month compared with the industry’s 16.8% rally. The company is the third largest natural gas producer in the United States. In the southwestern core of the prolific Marcellus and Utica shale plays, Antero Resources’ footprint covers more than 542,000 net acres. In the resources, the company owns many undeveloped core drilling locations, which has brightened up the upstream energy player’s production outlook. Notably, Antero Resources is expecting significant well cost reduction in the Marcellus that will aid its bottom line. Moreover, the company has hedged 93% of the estimated 2021 natural gas volumes at $2.78 per MMBtu, thereby combating the commodity price volatility. Also, the balance sheet of Antero Resources has lower exposure to debt capital as compared to the composite companies belonging to the industry. Antero Resources has a 29% ownership interest in Antero Midstream Corporation AM through which the upstream firm generates steady revenues. Remarkably, with its midstream energy assets, Antero Midstream provides services to gas production in the Marcellus and Utica shales. Despite so many positive factors aiding the stock’s price rally, one point is needed to be kept in mind. Notably, more than 60% of the company’s net leasehold acreage is undeveloped. Some of the leases in the Marcellus and Utica acreage have set a condition for the company to drill commercially productive wells. Hence, the company can possibly lose the rights under some specific leases if the upstream firm finds it difficult to drill commercially-productive wells.
Students receive lesson in economic development - Students participating in Youth Leadership Guernsey, a program sponsored by the Cambridge Area Chamber of Commerce, received a lesson in economic development recently. The students who are juniors at Cambridge, Meadowbrook, John Glenn and Buckeye Trail high schools, meet once a month to develop their leadership skills. "The students participating in this program are chosen based on their leadership potential," said Jennifer Vincent, Leadership Guernsey administrator. Speakers from Cambridge’s Office of Economic and Community Development, Cambridge/Guernsey County Community Improvement Corporation and the Ohio Oil and Gas Energy Education Program gave students a glimpse of the work they do to create economic opportunities in the county. Among the speakers this month was David Hill, chairman of OOGEEP. He detailed the economic opportunities the oil and gas industry has created in Guernsey County since the start of the Utica Shale boom. Guernsey County was the top oil producing county in the state of Ohio in 2019 according to the Ohio Department of Natural Resources. JobsOhio data shows the industry invested nearly a quarter of a billion dollars in the county in the first half of 2019 alone. All this investment activity has led to job opportunities for Guernsey county residents. The industry directly and indirectly supports thousands of jobs at every education level. The industry needs a wide variety of skills to function, and employs everyone from finance marketing professionals, to welders and construction workers. “The oil and gas industry offers opportunities to everybody, and has invested heavily in Guernsey County,” said Hill. “I encourage students looking to enter the workforce right after high school to consider the industry, and for students planning to attend college or a trade school, OOGEEP offers a scholarship program to help pay the costs.” Students interested in applying for one of OOGEEP’s scholarships or learning more about careers in the oil and gas industry can do so by visiting https://www.oogeep.org/teacher-students/scholarships/.
Erie County landowners gave access for pipeline. Now they're getting hit with liens— A segment of a multimillion-dollar energy project runs under the far end of Richard and Barbara English's farm on Old Albion Road in Springfield Township. Nearly four years ago, in April 2017, the Englishes received a payment in exchange for a right-of-way that allowed a section of the 28.3-mile Risberg natural gas pipeline to be installed on a swath of their property. The 2,300 feet of pipe went in below the soil near where the Englishes grow corn and soybeans. Court records show the couple got $10 per foot. Scores of the English's neighbors also granted rights-of-way for the pipeline. So did property owners in Ashtabula County, Ohio. More than 100 landowners in all agreed to provide access. The Risberg Pipeline's owner, the Erie-based RH Energytrans, needed the rights-of-way to run mile after mile of 12-inch steel pipe from Elk Creek Township, in western Erie County, to North Kingsville, Ohio, just west of the Pennsylvania line. The total planned cost of the project: $86 million. RH Energytrans developed the Risberg Pipeline as an extension of an existing pipeline that draws gas from national transmission lines. The natural gas started flowing through the new section in December 2019, providing Dominion Energy Ohio with up to 40 million cubic feet of natural gas a day — enough to meet the daily needs of about 150,000 households.The pipeline is also expected to provide the natural gas needs of a $474 million pig iron plant that has been proposed for Ashtabula.The Englishes and the other property owners believed their connection to the pipeline was over after the pipe had been buried on their property.Then the legal papers arrived.On Dec. 17, a deputy with the Erie County Sheriff's Office showed up at the Englishes' house. The deputy served them with a document known as a mechanic's lien, a legal instrument that contractors attach to a property to secure payment of a debt from a residence or business. The amount of the debt in the English's mechanic's lien was staggering: $18,946,185. The name of the contractor who filed the lien was the Wood Group USA Inc., of Houston Texas. It is the company that built the Risberg Pipeline for RH Energytrans. At first glance, the mechanic's lien appeared to state that the Englishes owed the Wood Group USA nearly $19 million and that the lien would be forever attached to the couple's property until they satisfied the debt. A closer reading shows that the liens are attached only to the improvements related to the pipeline work, and that "no lien is being claimed against any improvements, dwellings, structures, facilities or fixtures that are not related or connected" to the pipeline. Even so, the lien raises the possibility that a small part of the Englishes' property could be encumbered with a debt.
Federal energy commission opts not to consider PennEast Pipeline a day before Biden becomes president - The Federal Energy Regulatory Commission on Tuesday opted not to consider an amended proposal for a controversial $1 billion natural gas pipeline that would traverse across New Jersey and the Lehigh Valley.In September of last year, the commission issued an environmental assessment of PennEast’s amended proposal to split the project into two phases with new interconnection facilities at Church Road in Bethlehem Township, Pennsylvania.This assessment, which drew opposition from both state and local officials, determined that “with appropriate mitigating measures,” the PennEast Pipeline’s amended proposal “would not constitute a major federal action significantly affecting the quality of the human environment.”The commission’s decision to table consideration of the amended proposal comes a day before Wednesday’s inauguration of President-elect Joe Biden. Outgoing President Donald Trump has been a supporter of this pipeline project and others across the nation.According to the New Jersey Conservation Foundation, the commission removed its scheduled consideration of the revised proposal on Tuesday after Commissioner Neal Chatterjee cited concerns raised by the foundation and The Watershed Institute. Specifically, the organization said that Chatterjee argued that action on the amendment would contradict the Natural Gas Act’s prohibition on modifying or setting aside orders currently before a federal court.Chatterjee did not immediately respond to a request for comment.In November 2019, PennEast asked the Supreme Court to review an appeals decision issued by the Federal Court of Appeals for the Third Circuit in September. The lower court had ruled that the PennEast Pipeline could not seize New Jersey-owned land in order to build the gas line under the legal doctrine of sovereign immunity, which exempts New Jersey from condemnation lawsuits initiated by private parties like PennEast. The Supreme Court in turn requested the Solicitor General for the Department of Justice file a brief on the case, which urged the court to overturn the decision. Earlier this month, the New Jersey Attorney General’s Office filed its own brief challenging this argument and asked the Supreme Court not to hear PennEast’s appeal.
GlobalData: new pipelines necessary for Marcellus and Utica shales to supply natural gas to Gulf Coast The Appalachia Basin, made up of the Marcellus formations and the Utica Shale, accounted for more than 40% of the natural gas produced in the US in 2020. Unlike many of the oil plays in the US Lower 48, natural gas plays, including the Appalachia Basin, saw a less drastic change in production and drilling activity during the economic contraction caused by the COVID-19 pandemic, says GlobalData, a leading data and analytics company.GlobalData’s latest market analysis report, Marcellus and Utica Shales in the US, 2020, reveals that the Appalachia region averaged 32.19 billion ft3/d and 33.44 billion ft3/d in 2019 and 2020, respectively. While major oil-producing operators slashed their 2020 capital expenditure up to 50 - 60%, the top three producers in the Appalachia Basin – EQT Corporation, Antero Resources, and Southwestern Energy – have cut their capital only by 20%, 35% and 40%, respectively.Andrew Folse, Oil & Gas Analyst at GlobalData, comments: “The future prices for Henry Hub in 2020 are currently averaging US$2.75 per thousand ft/3, which prompts many companies to increase drilling and completion activities. The higher price is linked to the growing exports of LNG, growth in the number of heating days, and the drawdowns in the US natural gas storage. In 2019, the US exported approximately 5 billion ft3/d of LNG, which increased to 6.53 billion ft3/d in 2020. The EIA forecasts that LNG exports will continue to grow to an average of 8.50 billion ft3/d in 2021." The outlook for the Marcellus and Utica plays is closely tied to the demand for LNG exports from the US. Currently the US has an export capacity of 9.17 billion ft3/d, and, with current planned and under construction projects, this value will grow to 11.97 billion ft3/d in 2023. While other plays near the Gulf Coast such as the Permian Basin, Eagle Ford, and the Haynesville are better located to provide natural gas to meet LNG feedstock demand, the Marcellus and Utica can also play a relevant role in supplying natural gas to the new LNG facilities located on the Gulf Coast, but additional pipeline capacity will be needed.
FERC Dems Criticize ‘Piecemeal’ MVP Construction, Possibly Stalling Future Authorizations - FERC in its monthly meeting Tuesday failed to pass three draft orders for Mountain Valley Pipeline LLC (MVP), a move that could augur poorly for the developer’s expectations to quickly complete construction amid the transition to Democratic leadership at the agency. In recent months, MVP has sought the Federal Energy Regulatory Commission’s blessing to continue expanding construction efforts, including seeking the elimination of an exclusion zone around the Jefferson National Forest and altering its waterbody-crossing methods to allow for more work on the first 77 miles of the project. While three separate MVP-related items appeared on the agenda for this month’s FERC meeting that could have advanced these efforts, none of them garnered a majority vote, as both Democratic Commissioners Richard Glick and Allison Clements voted no. Recently-installed Republican Commissioner Mark Christie did not participate. The U.S. Forest Service finalized an updated review of the project in December, and MVP late last week provided FERC with a copy of a right-of-way granted by the Bureau of Land Management (BLM) that would ostensibly allow for construction through the national forest lands protected by the exclusion zone. However, comments Tuesday from Glick and Clements suggest this might not be enough to persuade a Democratic-led FERC to authorize further construction activities for MVP. After a number of legal setbacks in recent years, the pipeline has made significant progress in obtaining new or reissued federal permits required under its FERC certificate. However, updated Nationwide Permit 12 (NWP 12) waterbody crossing permitting granted by the U.S. Army Corps of Engineers was stayed by the U.S. Court of Appeals for the Fourth Circuit in November. This leaves the project short of the requirements under Environmental Condition 9 of its certificate and thus should preclude any construction activities as long as any permits remain outstanding, Glick argued. The proposed orders on Tuesday’s agenda “would’ve continued the Commission’s piecemeal approach to authorizing resumption of construction” on MVP, Glick said. Analysts at ClearView Energy Partners LLC told clients following the meeting that the BLM permitting “would normally clear the way for construction resuming” near the Jefferson National Forest. “As we understand it, there are no NWP 12 crossings within the footprint of the pipeline’s route” through the national forest, the analysts said. “Nevertheless, it appears that both Commissioners Glick and Clements are disinclined to allow any additional notices to proceed with construction while the NWP 12 remains outstanding. President Biden, who took office Wednesday, is expected to replace current FERC Chairman James Danly with a Democrat. The ClearView analysts said they expect Biden to hand the gavel to either Glick or Clements “within days.” © 2020 Natural Gas Intelligence. All rights reserved.
Federal commission slows Mountain Valley Pipeline -Federal energy regulators have slowed down the Mountain Valley Pipeline project, surprising some opponents of the project by not approving a request from Mountain Valley to bore under 69 waterbodies and wetlands along 77 miles of the pipeline at its northernmost end in West Virginia. The Federal Energy Regulatory Commission split in a 2-2 vote Tuesday, with a fifth commissioner abstaining from voting, setting the issue aside without a resolution. The FERC’s deadlock denied Mountain Valley’s requests to complete construction and final restoration work along the first 77 miles of the pipeline and effectively eliminate an exclusion zone where construction had been barred. The commission had issued an order last month allowing construction along a 17-mile stretch of the 25-mile zone covering parts of the Jefferson National Forest and surrounding private land. FERC Commissioner Richard Glick said during the commission’s virtual meeting that, in his view, the project could resume construction only after it secures all federal permits for waterbody crossings. In November, the 4th U.S. Circuit Court of Appeals stayed permitting for waterbody construction that had been issued by the U.S. Army Corps of Engineers. “The reason the commission doesn’t authorize construction in the absence in a permit is that it makes no sense to enable a developer to begin digging up land and laying down the pipe when it may be that the subsequent permit is never obtained or it may be that the route of the project has to change because of the conditions associated with the subsequent permit,” Glick said. Glick has been consistent on that point, but he was joined in opposing Mountain Valley’s request by a commissioner who was sworn in last month, Allison Clements. The commission’s newest member, Mark C. Christie, abstained from voting. Mary O’Driscoll, a FERC spokeswoman, said Christie felt that Mountain Valley’s proposal might relate to his 17 years with the Virginia State Corporation Commission, from which he joined the FERC earlier this month. O’Driscoll added that Christie “may explore such issues” in these proceedings going forward.
In a rare rebuke, FERC fails to approve Mountain Valley Pipeline's proposal -- Federal regulators hit the brakes Tuesday on a request to speed up construction of a portion of the Mountain Valley Pipeline, throwing another wrench into the problematic project. The Federal Energy Regulatory Commission deadlocked 2-2 on Mountain Valley’s request to bore under streams and wetlands along the pipeline’s first 77 miles in West Virginia. After running into legal problems with a permitting process that would have allowed digging trenches through water bodies, the company asked FERC to authorize an alternative method of drilling a tunnel below some of the streams and wetlands through which the pipe would pass. Approval by the commission would have enabled Mountain Valley to put the first 77 miles of the pipeline into service while work on the remaining 226 miles — including a stretch through the New River and Roanoke valleys — is slowed by legal attacks from environmental groups. But at FERC’s virtual meeting Tuesday, an order approving the boring request failed to get a majority vote. With the panel split 2-2, and the fifth commissioner abstaining from voting, the matter essentially died unresolved. “It’s a significant setback” for Mountain Valley, said Gillian Giannetti, a staff attorney for the Natural Resources Defense Council. ain Valley’s request to bore under the 69 water bodies that lie between the pipeline’s origin in northern West Virginia and the point where it will connect with another pipeline. Boring “inherently presents significant risks” that should be evaluated more thoroughly, the council wrote in comments submitted to FERC last month. “Mountain Valley failed to conduct geotechnical surveys, groundwater surveys and subsurface soil composition studies necessary to assess whether conventional bores are appropriate,” the filing stated. Natalie Cox, a spokeswoman for the joint venture of five energy companies building the pipeline, said the tie vote means that FERC could revisit the stream-crossing issue in the future. However, the regulatory landscape for natural gas pipelines will likely change under the administration of President-elect Joe Biden, who is expected to be less supportive of the industry than President Donald Trump. FERC usually meets on the third Thursday of every month, but the January meeting was moved up to Tuesday — one day before Biden was to be sworn in. A spokesperson for the agency said the change was made to accommodate a schedule that included Monday’s Martin Luther King Jr. holiday and Wednesday’s closing of federal offices for the inauguration.
Q&A: Manchin on fracking, climate and a clean energy standard -- Friday, January 15, 2021 -- The senator who once put a bullet through the Waxman-Markey cap-and-trade bill for a campaign ad will become an even more important gatekeeper on climate change this year.West Virginia Democrat Joe Manchin will take over the Energy and Natural Resources Committee as soon as next week as his party promises to push increasingly ambitious ideas against global warming.Manchin helped pass three bipartisan energy and public lands bills in the last Congress with outgoing Chairwoman Lisa Murkowski (R-Alaska). The ENR Committee achieved bipartisan success, even as Capitol Hill devolved into further partisan gridlock."We did a lot, but there is still a lot in energy we want to get done," Manchin said in an interview with E&E News yesterday.Incoming Senate Majority Leader Chuck Schumer (D-N.Y.), in a letter to colleagues this week, promised "bold legislation to defeat the climate crisis by investing in clean infrastructure and manufacturing."At the center of those discussions is Manchin, a longtime defender of his state's coal industry and an "all of the above" energy strategy, who has also worked to make inroads with environmentalists.Manchin spoke with E&E News about his vision for the committee, including his views on clean energy standard legislation and taking care of communities displaced by climate rules.He also weighed in on President-elect Joe Biden's Energy secretary pick Jennifer Granholm, the former Michigan governor, and Interior secretary pick Rep. Deb Haaland (D-N.M.).
Lamont: 'I don't want to build Killingly' Energy Center -Gov. Ned Lamont on Tuesday said the words out loud more straightforward than he ever has: “I don’t want to build Killingly.” He was referring to the now five-year battle waged by environmentalists and others against building the proposed Killingly Energy Center, a 650-megawatt natural gas power plant. Those who oppose it have argued it flies in the face of Lamont’s executive order for a 100% zero-carbon electric sector by 2040, it does not support his broader commitment to fighting climate change, and it just isn’t needed. And while he’s hinted that he’s not thrilled with the prospect of the Killingly power plant, he’s never been quite that blunt. His comments were made to more than 300 environmental advocates attending the opening sessions of the Connecticut League of Conservation Voters annual legislative priorities summit, held over Zoom this year. The governor hinted at slowing permitting and being able to “play some games there.” He also hinted that market forces may ultimately take over. “I’m not positive you’re going to see Killingly built at all,” he said. Recent analysis by the Department of Energy and Environmental Protection shows electricity demand down 18 percent in the state, though many believe it will come back up as more items, such as heating, become electrified and more people purchase electric vehicles, which will need charging. The plant has received siting council approval, after two rejections. DEEP has issued an air discharge permit and a water quality certificate for impacts to wetlands. Still pending is a wastewater discharge permit, which is also needed, and Eversource’s water quality certification for a pipeline to bring the natural gas to the plant. “As a natural gas distribution company, we work to provide service to various potential customers — like the developer of the proposed Killingly power plant,” said Eversource spokesman Mitch Gross.
A bankruptcy milestone: Chesapeake plan approved, no changes to executive leadership expected - There is much that remains to be done before Chesapeake formally emerges from bankruptcy. But Doug Lawler, the company’s CEO, told employees in an email sent Thursday morning said a judge’s approval of its exit plan late Wednesday marked “a critical milestone” in its future. The ruling, he said, puts the company on a path “towards fundamentally resetting our company and preparing us to emerge a stronger and more competitive enterprise.” The ruling by Judge David R. Jones sets the stage for the company to rejoin a business world where it can freely operate once again. No changes in Chesapeake’s executive leadership team are expected, although a filing in the case states its existing board of directors will be replaced when the company’s equity owners assume control of the new business. Lawler, the filing states, will keep a seat on the new board.
Proposals to prohibit natural gas bans may threaten cities’ clean energy goals - Kansas and Missouri may become the next states to block cities from banning natural gas, with hearings on legislation in both states expected soon.Although natural gas bans at this point are more of a coastal phenomenon, many Midwestern cities have adopted climate goals that will be difficult to achieve with continued reliance on natural gas. More than two dozen Missouri cities, including Kansas City and St. Louis, have established clean energy goals, along with Lawrence, Kansas. A coalition of Kansas City suburbs recently adopted a climate plan committing to providing city services using only clean energy by 2030, and for all community energy use to be sourced from renewables by 2035.Promoters of clean energy in both states say the pending legislation preempts local decision-making, and they expressed concern that the language could interfere with transitioning from fossil fuels to renewables.“It does seem that the legislation … was intended to prohibit cities like Lawrence from taking steps to reach those goals we set,” said Jasmin Moore, the sustainability director for Lawrence and Douglas County. In March, the Lawrence City Council committed to a gradual transition to clean energy. The first goal is to use electricity only from renewable sources by 2025. Natural gas apparently still would be acceptable. Moore said the city has contracted with Evergy to meet 98% of its power needs with wind.The final goal calls for clean energy in all sectors citywide by 2035. That presumably would preclude the use of natural gas. Moore continued: “I think [the bill] has the potential to slow down the process. The goals of Lawrence are pretty aggressive, and that was intentional because of the climate crisis. The city felt this kind of action is needed now. We wanted to demonstrate leadership in the state.”Zack Pistora, legislative director for the Kansas Sierra Club, said it would be “shortsighted and irresponsible for the state legislature to preemptively interfere with local governments’ energy plans, especially when using Kansas-based, pollution-free energy resources like wind, solar, energy storage, and efficiency [that] can create jobs, improve health and social equity outcomes, and save residents a lot of money. “The Energy Choice Act doesn’t sound like it gives much choice to our local communities and their elected leaders who want to move past the negative costs of fossil fuels.”
Fading Expectations for Frigid Temperatures Weigh Down Natural Gas Futures - Natural gas futures plunged on Tuesday after forecasts over the holiday weekend trended warmer for late January and early next month, diminishing prior expectations for a widespread winter freeze that would fuel robust heating demand. The February Nymex gas futures contract settled at $2.546/MMBtu, down 19.1 cents day/day. March fell 16.7 cents to $2.529. Spot gas prices were also under heavy pressure. NGI’s Spot Gas National Avg. dropped 15.5 cents to $2.690. Following the shift in forecasts, EBW Analytics Group estimated a cumulative decline of 70.2 Bcf of demand compared to projections prior to the holiday weekend, when models had “called for a sustained cold air connection to develop” before the end of January. “With only three or four weeks left in the heart of winter, the stakes are high for natural gas,” the EBW analysts said. Forecasts Tuesday still called for solid blasts of cold late this month – with lows in the teens across much of the northern United States – though not as cold as the subzero temperatures previously anticipated. The colder temperatures were not likely to last deep into the first week of February as earlier outlooks anticipated. Learn More - All News Access Models over the weekend trended “more toward a dominant” positive Eastern Pacific Oscillation pattern and did so “while lessening the influence” of North Atlantic Oscillation blocking, Bespoke Weather Services said. This would result “not only in less cold as we move into the latter part of January but sets the stage to actually revert back warmer than normal into February.” “It is getting difficult to envision any sustainable rally at this stage, as the cold forecasts for the conclusion of this month are failing versus expectations from the other day, and we are already seeing signs of the turn back to a warmer-than-normal regime into February,” the firm said. Strong U.S. liquefied natural gas (LNG) export levels, driven by steady northern Asia demand amid harsh winter conditions and supply interruptions, hovered above 11 Bcf and near record levels early in January, NGI data show. However, LNG volumes dipped below the 11 Bcf threshold on Tuesday. In a holiday abbreviated week, markets will have to wait an extra day to see if LNG demand factored into the domestic storage withdrawal for last week.
February Natural Gas Futures Fall on Demand Uncertainty; Spot Prices Stumble - In a third consecutive day of topsy-turvy trading, natural gas futures ultimately finished firmly in negative territory, as markets fixated more on shifting weather patterns than a bullish storage report and rising U.S. liquefied natural gas (LNG) volumes. The February Nymex gas futures contract settled at $2.666/MMBtu, down 6.1 cents day/day. March fell 5.9 cents to $2.630. NGI’s Spot Gas National Avg. also lost ground, shedding 10.5 cents to $2.740 after losing 8.0 cents the day before amid seasonally mild temperatures. NatGasWeather said data in both the domestic Global Forecast System (GFS) and the European model had shifted warmer this week and presented “a rather bearish pattern through Jan. 21 with only modest cold shots into the U.S.” The firm continues to expect frigid temperatures in late January across the interior West and Midwest, but the likelihood of such conditions advancing deep into the East or toward the South diminished when compared to forecasts earlier in the week. This lowered the odds of strong national heating demand in coming weeks and weighed on gas futures. “The latest GFS still shows colder air eventually reaching the Great Lakes and Northeast Jan. 25-28, but we think this period is also subject to warmer trends in time,” NatGasWeather said.
US working natural gas volumes in underground storage decline 187 Bcf: EIA -— The US Energy Information Administration reported the largest weekly draw from gas in underground storage of the current heating season on Jan. 22, but Henry Hub futures continued to flounder as milder weather points to smaller pulls ahead. Stay up to date with the latest commodity content. Sign up for our free daily Commodities Bulletin. Sign Up Storage inventories decreased 187 Bcf to 3.009 Tcf for the week ended Jan. 15. The report was issued one day later than usual due to federal offices being closed for the US presidential inauguration on Jan. 20. Lower temperatures propelled residential-commercial and industrial demand nearly 4 Bcf/d higher week over week, according to S&P Global Platts Analytics. In addition, gas-fired power generation demand grew 2.2 Bcf/d, with weakness in wind generation and higher total loads driving thermal generation higher. In addition to stronger demand, total supply fell 900 MMcf/d week on week, with onshore production losses accounting for most of the decline. The withdrawal was more than the market expected and 10 Bcf stronger than an S&P Global Platts survey of analysts. The pull was much more than the 97 Bcf draw reported during the same week last year as well as the five-year average withdrawal of 167 Bcf, according to EIA data. Storage volumes now stand 36 Bcf, or 1.2%, more than the year-ago level of 2.973 Tcf, and 198 Bcf, or 7%, more than the five-year average of 2.811 Tcf. The NYMEX Henry Hub February contract shed 5 cents to $2.44/MMBtu in trading following the release of the weekly storage report. March, the last month of the heating season, also fell 5 cents to $2.45/MMBtu. Natural gas prices saw some selling pressure during the week in progress, with the February contract falling below $2.50/MMBtu. Losses can be traced to weather models once again backing off on expected cold, which has been a common occurrence this winter. Losses in forward-looking heating-degree days, and thus demand, have resulted in an upward creep in market expectations for end-of-March storage, which are now hovering near 1.65-1.7 Tcf, according to Platts Analytics. Moreover, with numerous weather forecasts suggesting February could come in significantly milder than normal, the term structure in the market reflects sentiment that winter has been "cancelled," with the balance of winter-to-summer spread nearing 20 cents. The Platts Analytics supply and demand model currently forecasts a 137 Bcf withdrawal for the week ending Jan. 22, which would grow the surplus versus the five-year average by 37 Bcf.
As Weather Outlook Warms, Weekly Natural Gas Prices Cool Off - Natural Gas Intelligence -- In an abbreviated four-day trading week following the Martin Luther King Jr. holiday on Monday, weekly cash prices recorded a double-digit drop as temperatures climbed across much of the Lower 48 and heating demand eased. Comfortable conditions moved in early in the week and stuck around until Thursday, notably including highs in the 40s and low 50s at midweek in the northern Plains and over swaths of the Midwest. Those temperatures were well above usual highs in the 20s and 30s for these key sections of the country that draw heavily on natural gas to power furnaces. Heating demand dwindled as a result. “Weather is king,” Bespoke Weather Services said. NGI’s Weekly Spot Gas National Avg. for the Jan. 19-22 period fell 21.0 cents to $2.610. As the trading week closed, Chicago Citygate was down 23.5 cents to $2.405, while Katy was off 25.0 cents to $2.465 and OGT was down 28.0 cents to $2.340. Spot prices were under particularly heavy pressure early in the trading week, falling nearly 30 cents over the course of Tuesday and Wednesday. For the week ahead, Maxar’s Weather Desk was expecting lows ranging from near zero to the teens in the Midwest and parts of the East, potentially fueling momentum in cash prices in coming days. EBW Analytics Group, however, noted that the mid-range outlook was murky, given substantial shifts in weather models over the past week. “This exceptionally high model volatility could result in continued sharp price swings,” EBW said. “It stems from strong bullish signals in the Arctic and over Greenland, coupled with uncertainty in the Pacific and the tropics.” Natural gas futures struggled to find footing throughout the week, as the volatile forecasts for the rest of this month and the first few days of February ultimately pointed to lighter heating demand than meteorologists had expected as recently as mid-January. Futures lost ground each day of the trading week. Intense cold was still expected over most of the northern United States in the final full week of January, but unlike earlier forecasts, meteorologists were not looking for freezing conditions to extend as far south as Texas or last into February. A warming pattern is projected to return by early next month, impacting demand for gas-powered heating.
US Oil, Natural Gas Infrastructure Growth Potential Said 'Significant' as LNG, Mexico Exports Climb -- The potential for oil and natural gas infrastructure development remains “significant” through 2025 as the U.S. economy recovers from Covid-19 and exports increase, according to ICF Resources Inc. In a report prepared for the Interstate Natural Gas Association of America (INGAA), ICF said one scenario used by researchers to evaluate changes to markets and infrastructure development found that almost 33 Bcf/d of capacity is expected to be placed into service during between 2020 and 2025. The projected development is lower on a per-year basis than it was in 2018, which was “a banner year for pipeline construction,” according to ICF. “While projected development is down by almost 6 Bcf/d, or about 15%, from the level projected” in a second ICF scenario, “it still requires a substantial amount of new infrastructure,” researchers said. ICF relied on its market modeling tools to complete two scenarios of North American oil and gas markets through 2025. The first scenario, ICF Q1 2020, showed market and infrastructure development trends prior to the Covid-19 pandemic and absent extended delays in infrastructure development. The second, INGAA 2020, is more recent, attempting to fully capture impacts of the pandemic and extended delays in infrastructure development. “The pandemic has no doubt slowed the pace of infrastructure development as demand for natural gas and oil were impacted globally, but this report shows that will change as markets rebound,” said INGAA Foundation Executive Director Tony Straquadine. “The industry is well positioned to respond to the needs and challenges outlined in this report as domestic demand and export capacity return to the trajectory we saw entering 2020.” In the report, titled “North American Midstream Infrastructure – A Near Term Update Through 2025,” the ICF research team said it expects markets to rebound as demand returns. Domestic natural gas use is expected to rise to an average of roughly 87.5 Bcf/d in 2025, which is about 3.6% above the 2019 level. Liquefied natural gas (LNG) exports are expected to be a major driver of future demand growth for U.S. export markets, according to the report. ICF researchers noted that last July, monthly average feed gas deliveries to gas export facilities dipped below 3.5 Bcf/d for the first time since 2018. However, feed gas deliveries set a record in November, surpassing 10 Bcf/d. December 2020 feed gas deliveries were higher still, finishing the month at around 11 Bcf/d. The INGAA 2020 scenario projects that LNG exports could rise to 11.7 Bcf/d by 2025 from 5.7 Bcf/d in 2019, an increase of more than 100%.
Largest single shipment of ethane heads to China after loading at US export facility — The world's largest ethane carrier was headed toward the Panama Canal on Jan. 19 after loading at Energy Transfer's terminal in Nederland, Texas, P latts trade flow software cFlow showed. Stay up to date with the latest commodity content. Sign up for our free daily Commodities Bulletin. Sign Up The Seri Everest, a Very Large Ethane Carrier, departed on its maiden voyage from the Orbit Gulf Coast NGL Exports facility at the terminal on Jan. 17, en route to Satellite Petrochemical's Lianyungang ethane cracker in Jiangsu Province, China, according to Energy Transfer. The export facility is operated by Energy Transfer under a joint venture with Satellite. The achievement follows the loading of the first VLGC powered by liquefied petroleum gas at Enterprise Products Partners' hydrocarbon terminal on the Houston Ship Channel in December. US Gulf Coast ethane climbed to the highest level in more than 20 weeks Jan. 15, at 25 cents/gal, amid increased demand for ethane as a viable alternative to normal butane and propane for the petrochemical sector. Prior to that, January barrels of LPG had been on an upward trajectory, spurring the demand for ethane. S&P Global Platts assessed January non-LST ethane, reflecting prices at the Enterprise NGL storage and fractionation facility in Mont Belvieu, Texas, at 23.50 cents/gal on Jan. 19. Stripping ethane and propane from the natural gas produced at the wellhead creates two more revenue streams in addition to the dry gas that remains. US exports of NGLs and their byproducts to Asia have flourished in recent years. Producers in key US shale basins where increasing amounts of associated gas are being lifted with oil, including the prolific Permian Basin in West Texas, rely on those outlets for their supplies. For 2021, global NGL supply is expected to retract by 1% compared with 2020 as production curtailments hit the US, according to Platts Analytics. Ultimately, global NGL supply is not expected to return to 2019 annual levels until 2023. At the Orbit facility, the Seri Everest was loaded with more than 911,000 barrels of ethane, the largest single shipment of ethane to date, Energy Transfer said. It is expected to arrive in China in mid-February, the company said. Energy Transfer's Marcus Hook facility in Pennsylvania is also capable of handling VLECs. As for the Very Large Gas Carrier BW Gemini that departed Dec. 13 from Enterprise's terminal, it was loaded with 590,000 barrels of LPG, including cargo and fuel. On Jan. 19, the vessel was in the North Pacific, with a captain's destination set for Japan's port of Chiba, according to cFlow.
Texas lawmakers to weigh using fracking wastewater to replenish aquifers - Deep underneath the ground, fluids travel down and shoot through ancient shale formations, fracturing rock and starting the flow of oil — the essential part of hydraulic fracturing technology that's transformed America’s oil industry. But that’s not all that comes up out of the earth. Salty, contaminated water — held in porous rocks formed hundreds of millions of years ago — is also drawn to the surface during oil production. Before an oil price war and the coronavirus pandemic caused prices to crash in March, Texas wells were producing more than 26 million barrels of the ancient and contaminated water a day, according to an analysis by S&P Global Platts. In the oil patch, figuring out how to dispose of this water “is something that only gets worse,” said Rene Santos, an energy analyst for S&P Global Platts. “Every time (companies) produce, they have to do something with the water.” Usually, it’s later injected back underground, into separate wells — a practice that has been linked to increased seismic activity. Sometimes it’s reused in another fracking well. But a new U.S. Environmental Protection Agency decision allowing Texas to regulate the discharge of the water after it’s treated could be a first step toward new uses of the water — at least that’s what some Texas lawmakers and oil and gas producers hope. The EPA told the Texas Commission on Environmental Quality last week that the state could take charge of the federal government’s responsibilities to regulate discharging so-called "produced water," if the water met certain toxicity standards. For now, oil and gas operators may apply for individual permits from the TCEQ on a case-by-case basis, an agency spokesperson said. For every barrel of oil produced in the Permian Basin of West Texas, an average of six barrels of water come up with it, according to an S&P analysis. State Sen. Charles Perry, R-Lubbock, argues that the water could eventually help the state replenish its diminishing water supplies.As chairman of the state Senate Committee on Water and Rural Affairs, he helped produce an interim report ahead of the 2021 legislative session that included such a vision — and now Perry says the recent EPA decision will help get federal regulation out of the way. “This is a water supply that hasn’t been cultivated or tapped,” Perry said. “It’s a sin to waste that resource.” The industry, too, has “a lot of excitement” about turning the water into something of value rather than an expense, said Jason Modglin, president of the Texas Alliance of Energy Producers. But scientists and industry observers say the idea is a long shot. Produced water contains high amounts of salt, as well as other minerals and toxins in varying amounts depending on the shale formation it comes from, and technology to make the water potable is still expensive.
EPA Grants Biofuel Waivers to Refiners -- The Trump administration granted three oil refineries exemptions from biofuel-blending requirements in a last-minute move, prompting quick rebuke from ethanol and biodiesel producers. Two of the Environmental Protection Agency waivers apply to the 2019 mandate under the Renewable Fuel Standard, according data posted online. The agency also approved a previously denied 2018 exemption. Another 65 requests are pending, including 15 for 2020. The names of the refineries weren’t disclosed. Biofuel advocates, including lawmakers, had pushed the Trump administration to hold off on approvals, with the U.S. Supreme Court set to hear arguments in a case testing EPA’s ability to grant them. The latest action puts added pressure on the incoming Biden White House to signal how it will proceed in the fight for share of U.S. gasoline tanks. “This disappointing action further undermines the integrity of the Renewable Fuel Standard program by destroying demand for additional gallons of biofuel,” Kurt Kovarik, vice president for federal affairs at the National Biodiesel Board, said in a statement.
Outgoing Trump Administration Warns of U.S. Economic Disaster if Fracking Banned - A ban on hydraulic fracturing, a key technique used to complete unconventional oil and natural gas wells, could reverse U.S. production growth and lead the country backwards to become a net importer once again by as soon as 2025, the outgoing Trump administration warned in a report issued Thursday. The Department of Energy’s (DOE) outgoing Secretary Dan Brouillette in an 80-page analysis said if the completions technique known as fracking were not allowed to continue, it could sharply fray domestic output. The DOE analysis “suggests natural gas price implications under a hydraulic fracturing ban would be considerable, with an estimated 244% increase from the 2019 level, reaching $8.80/MMBtu by 2025,” Brouilette said. Techniques to extract energy resources from the Lower 48, said Brouilette, “unleashed America’s natural resources and made the United States the world’s largest natural gas and oil producer, while also creating high paying jobs and delivering meaningful consumer savings.” Banning the completions process, which has been used for more than 50 years around the world, “would result in the loss of millions of jobs, price spikes at the gasoline pump and higher electricity costs for all Americans. “Such a ban would eliminate the United States’ status as the top oil and gas producing country and return us to being a net importer of oil and gas by 2025,” he said. “It would weaken America’s geopolitical standing and negatively impact our national security.” Natural gas is an “important partner” for renewables and provides baseload power to backup intermittent resources such as wind and solar, according to the report. Renewable energy technology growth could be “adversely” impacted and in turn potentially impact the U.S. power grid. The DOE detailed a litany of damage to the U.S. economy with a ban on fracking. By 2025, it said, the domestic economy “would have 7.7 million fewer jobs, $1.1 trillion less in gross domestic product, and $950 billion less in labor income.” A recovery from the Covid-19 pandemic also could take longer, according to the analysis. Among other things, there could be a near $2/gallon increase in gasoline prices by 2025 from the 2020 average of $2.18. Average diesel prices also are forecast to increase. Marcellus Shale Coalition President David Spigelmyer, whose members produce natural gas and liquids-rich resources in Appalachia, warned that banning unconventional drilling could have a domino effect on emissions. “Banning hydraulic fracturing would reverse course of American’s ongoing global environmental leadership by increasing greenhouse gas emissions while burdening struggling consumers with higher energy costs,”
President Biden Has Limited Flexibility In Moving Against Oil Industry – Forbes - President-elect Joe Biden enters the White House this week with ambitious plans to tackle climate change and hasten the transition to a low-carbon economy. The economic and political realities of the moment, though, will make it difficult to move too aggressively against an oil and gas industry that continues to supply a majority of the country’s energy. Biden, a centrist Democrat, has been here before. In 2009, he became Vice President to President Barack Obama, an administration that also prioritized sweeping climate legislation, including a cap-and-trade carbon emissions program. Those plans, which would have raised the price of gasoline, heating oil and natural gas, quickly gave way to the economic realities of the time. The country was in the midst of the Great Recession, the worst economic downturn since the Great Depression, and battling unemployment rates in the double digits. It’s no wonder that cap and trade failed to gain support despite Democratic majorities controlling both chambers of Congress at the time. Indeed, an administration that was highly critical of the practice of hydraulic fracturing of shale deposits coming into the White House ended up overseeing a doubling of U.S. crude production during its tenure. The shale revolution went on to make America the world’s largest producer of oil and gas.The Obama administration eventually had to accept that the booming domestic oil and gas industry was too important to the national economy and employment to dismantle. The shale industry was responsible for roughly 10 percent of the growth in the U.S. economy’s gross domestic product (GDP) from 2010 to 2015, according to a study by the Federal Reserve Bank of Dallas. The Obama administration also came to realize the geopolitical benefits of being a major producer — so much so that it wiped out a 40-year old ban on exporting U.S. crude oil. Skyrocketing oil and gas production gave Washington more flexibility in setting foreign policy, too, particularly in dealing with the OPEC cartel and Russia. The economy President-elect Biden inherits on January 20 will look a lot like 2009. America continues to struggle under the Covid-19 pandemic. While nationwide inoculations are underway, it could be a long road back for the economy, and no one knows for sure what the new normal in a post-Covid world will look like. Biden will likely continue to have ambitious climate policy goals. Bold talk on climate is something of a prerequisite to maintain the progressive coalition that helped get him elected. But while the energy policy rhetoric may change significantly under the incoming administration, an outright assault on the oil sector is unlikely. To be sure, there will be a tightening of regulations and restrictions on new leasing, but current gains should be maintained.
Biden administration pauses federal drilling program in climate push (Reuters) - U.S. President Joe Biden’s administration has temporarily suspended oil and gas permitting on federal lands and waters in the latest of a series of rapid-fire orders aimed at fighting climate change and tamping down the U.S. fossil fuel industry. The order appeared to be a first step in delivering on newly sworn-in Biden’s campaign pledge to permanently ban new drilling on federal acreage. Federal leases account for close to 25% of the nation’s crude oil output, making them a big contributor to energy supply but also to America’s greenhouse gas emissions. Biden’s predecessor Donald Trump had sought to maximize production of oil, gas and coal on federal acreage, and routinely downplayed threats from global warming. The suspension was welcomed by environmentalists but derided by the oil and gas industry, which is struggling to secure a future under a new administration that has vowed to make countering global warming a top priority. The 60-day pause strips Interior Department agencies and bureaus from their authority to issue drilling leases or permits while the administration reviews the legal and policy implications of the federal minerals leasing program, according to a Department of Interior memo. The order does not limit existing operations, it said. Shares of U.S. shale producers with federal lands exposure fell following the news on Thursday. EOG Resources Inc and Cimarex Energy Co closed down 8.6%, Devon Energy Corp fell 7.9% and Occidental Petroleum Corp closed down 6.4% on the New York Stock Exchange. “This is a frack ban,” Anne Bradbury, chief executive of the drilling trade group American Exploration & Production Council, said in an interview. “Even just for 60 days, it’s a really aggressive move.” Many of the largest onshore drilling companies had stockpiled permits here in anticipation of a change in federal policy ahead of Biden's election, insulating them from a ban.
Big U.S. oil drillers have federal permits to mute effect of any Biden ban (Reuters) - U.S. President Joe Biden’s promised ban on new oil and gas drilling on federal lands would take years to shut off production from top shale drillers because they already have stockpiled permits, according to Reuters interviews with executives. But smaller independent oil drillers without the resources of big corporations were more worried about Biden’s vow to toughen regulations and stop issuing new permits on federal lands, part of his sweeping plan to combat climate change and bring the economy to net zero emissions by 2050. Federal lands are the source of about 10% of U.S. oil and gas supply. Fossil fuels produced on federally managed lands and waters contribute nearly 25% of U.S. greenhouse gas emissions, according to government estimates, making them an easy target for the administration’s climate agenda. Biden’s pledge would reverse former President Donald Trump’s efforts to maximize drilling and mining on federal property. But it will not end production in those areas overnight. The seven companies that control half the federal supply onshore in the Lower 48 states have leases and permits in hand that could last years. “We have always been very confident that we will continue to develop and drill on federal acreage,” said David Hager, executive chairman of Devon Energy Corp, the biggest oil producer on onshore federal land in the Lower 48 states. “It’s embedded into the rights we have in the leases and we’re doing it the right way.” He said he expected the company’s federal lands permits would last at least four years. Other top producers on federal land include EOG Resources Inc, ExxonMobil Corp, Occidental Petroleum Corp , ConocoPhillips, and Mewbourne Oil Company. EOG has said it has at least four years of federal permits. Occidental said last year it had well over 200 federal drilling permits in hand and had requested another roughly 200 permits on New Mexico acreage, where some of the richest reserves lie beneath federally owned property. Ameredev II, which produces about 10,000 barrels of oil per day in New Mexico’s Permian, also has federal drilling permits to last at least four years. Energy consultancy Rystad said it saw stockpiling of federal lands drilling permits in the run-up to the November presidential election, with federal permit requests rising to a 31% share of all permit requests in the major U.S. oilfields from 18% in 2019. Biden’s team did not respond to several requests for comment, and it was unclear when his administration might act on a drilling ban. Most onshore federal drilling happens in Western states like New Mexico, Colorado and Wyoming, which get a share of extraction royalties and depend on that revenue.
IN BRIEF: Nearly 900 Western states oil and gas leases draw new legal challenge | Reuters --Following on the heels of a novel win that halted oil and gas leases in Wyoming, environmental and health groups are again taking the Bureau of Land Management to task over an inadequate “carbon budget analysis” for 890 leases in Western states.WildEarth Guardians and Physicians for Social Responsibility on Tuesday accused the BLM of violating the National Environmental Policy Act with March 2019 and December 2020 lease sales in Colorado, New Mexico, Utah and Wyoming, arguing that the agency failed to analyze how greenhouse gas emissions resulting from fossil-fuel extraction on the parcels measure against its own assessment of total emissions the country can safely release to limit climate change.To read the full story on Westlaw Today, click here: bit.ly/3iut9RV
Feds could follow Colorado’s lead on regulating methane from oil, gas sites — once again - Colorado has led the way on regulations to rein in emissions of methane, a potent greenhouse gas, and now the federal government appears ready to follow suit — again. The series of executive orders that President Joe Biden signed Wednesday, his first day in office, included one to review a Trump administration rule that loosened Obama-era federal methane regulations. The changes, finalized in September, removed oil and natural gas transmission and storage facilities from the rules and scaled back requirements for monitoring emissions from wells and detecting and repairing leaks. The methane regulation is among the Trump administration’s actions that Biden wants agencies to review and likely revise or rescind. He said the goal is to enact rules and policies to address climate change, environmental justice and protect the public health and environment. Federal rules to reduce methane from oil and natural gas operations were modeled after Colorado regulations. In 2014, Colorado approved the first state-level methane regulations in the country and has continued to strengthen its requirements. “President Biden made no secret about his wanting to restore the methane rule. He mentioned it in at least one of the debates.It was a big part of his platform for restoring America’s leadership on methane emissions,” said Dan Grossman, the regional director of the Environmental Defense Fund. Efforts to cut methane emissions have intensified as the effects of climate change have worsened. Methane, the main component of natural gas, is 80 times more potent in the near term than carbon dioxide in trapping heat in the atmosphere. Methane can escape from oil and gas equipment and is often “flared,” or burned as waste in oil production. Methane levels are increasing worldwide, with agriculture and fossil fuels being two of the largest drivers, scientists say. As part of an overhaul of state oil and gas regulations, the state approved rules in 2020 that ban the routine venting and flaring of methane at oil and gas sites and require more monitoring. Clamping down on methane pollution is considered important to meeting statewide greenhouse-gas reduction goals: a 26% decrease from 2005 levels by 2025; 50% by 2020; and 90% by 2050. Critics have questioned whether Colorado’s regulations are strong enough to make the cuts necessary to meet the targets.
Biden's Federal Land Lease Ban To Send Oil Prices Higher: Goldman -Oil stocks tumbled following yesterday's one-two punch of Biden energy news, when first we learned that the Interior Department enacted a 60-day moratorium on issuing oil and gas leases that affects all federal lands, minerals, and waters, which was followed by news that Biden was set to fully suspend the sale of oil and gas leases on federal land, which accounts for about a tenth of U.S. supplies.Yet while E&P companies sold off sharply on the news, one can argue that the decision wasn't exactly a surprise for the drillers themselves, because as the following chart from BofA shows, federal drilling permits spiked into year-end as companies clearly anticipated a ban on drilling on federal lands.But it's not just speculation about what impact on drillers - and especially frackers will be - Biden's intervention will have: an just as important question is what to expect on the price of oil as a result.Well, overnight, Goldman's commodity team said that a lack of urgency from the US government to lift Iranian sanctions and a push for larger fiscal spending support the constructive view on oil and gas prices; at the same time it estimated that a 2 trillion stimulus over 2021-2022 would increase US demand by 200k bpd and stated that delays in a full return of Iran production would support the bullish oil outlook. Goldman's summary, which could say is obvious: "policies to support energy demand but restrict hydrocarbon production (or increase costs of drilling and financing) will prove inflationary in coming years given the still negligible share of transportation demand coming from EVs (and renewables)."In short, just what Putin and the Crown Prince ordered.
DUCs Won’t Save U.S. Oil Production - U.S. oil production has fallen more than 2 million barrels per day since March 2020. Many reasonably expect that DUCs (drilled uncompleted wells) provide a solution to output falling further. They won’t. There are about 5,800 DUCs in the main U.S. tight oil plays. These are already drilled and could be converted into producing wells for the cost of completion which is about half the total well cost. Most DUCs, however, are uncompleted for a reason namely, that their owners don’t believe that their performance will be as good as wells that they chose to complete instead. Even assuming similar performance, the larger problem is that large numbers of DUCs are already being completed and official EIA 914 production remains less than 10.5 mmb/d. North Dakota publishes monthly data on DUCs that can be compared with active, producing wells. DUCs currently account for about 35% of new Bakken producing wells and about 25% of completed wells since March have been DUCs (Figure 1). During the 2015-2016 oil price and production collapse, DUCs in the Bakken reached about 40% of completions. It is, therefore, reasonable to expect that current DUC levels may be close to a maximum. Whether Bakken data applies to other plays is, of course, unknown. More importantly, there are just too few wells being completed to expect U.S. production to maintain 11 mmb/d EIA forecast for 2021. Five key regions of the United States—Texas, North Dakota, New Mexico, Oklahoma and the offshore Gulf of Mexico—account for 80% of total output. Figure 2 shows incremental new wells and new production for those regions from 2014 through July 2020 (12-month average). At least 400 new wells must be added each month to offset declining legacy production and maintain 11 mmb/d for the U.S. Instead of adding new wells, fewer wells were drilled in each successive month after March 2020. Not surprisingly, incremental monthly production has been falling and that is completely consistent with declining overall production levels. It doesn’t matter whether wells are newly drilled and completed or DUCs—there are simply too few wells being added to maintain present levels of production. The good news is that well completions and rig counts have turned around and are now heading in the right direction. The bad news is that it will take many months before drilling and production equilibrate. How far will production fall? The truth is that no one knows. Oil production is part of a complex system. Its interdependencies and feedback loops make it dynamic and adaptive. There are unresolvable uncertainties. The best approach is to identify and describe the key patterns that characterize present state: rig count, decline rates, lags and leads, completions and incremental production rates. These offer the most probable but only notional projections of those trends. In Figure 3, I show three scenarios based on rig count and I also show EIA’s production forecast for 2021. These should be viewed as trend lines rather than forecasts. In the base case, output begins to decline in April 2021 and decreases to 9.1 mmb/d by September 2021. In the low case the production minimum is estimated at 7.8 mmb/d and in the high case, 9.9 mmb/d. Whatever the magnitude of production decline or its precise timing, it is important to recognize what is coming. The lower-for-longer ruling paradigm has been accurate and useful since the oil-price collapse in 2014. What is happening now is different.
Can Shale Resist The Lure Of Another Output Surge? U.S. shale changed global oil markets. It shook the foundations of OPEC as the one single swing producer group.And last year, it crumbled under the weight of the pandemic that sent oil prices to all-time lows, including a short dip of WTI below zero. Now, shale is getting back on its feet, facing the temptation of production as prices rebound above $50.Wood Mackenzie’s Vice Chair for the Americas, Ed Crooks, called it a siren song in a recent analysis. The shale boom happened because producers were chasing constant growth. It was this chase that catapulted the United States to the spot of the world’s largest oil producer, but it was also this chase that made the pandemic-caused slump in the shale patch quite spectacular.Until about a month ago, most of U.S. shale was unprofitable, so producers stayed put—and probably wondered how they were going to keep paying the debts they’d accumulated while going for broke during the second shale boom. Now, at over $50 a barrel, a lot of shale oil is profitable again, at least according to the head of the International Energy Agency Fatih Birol.But it’s not just him. Reuters earlier this week reported shale drillers have started hedging their future production at the current futures prices—another sign more shale oil is profitable at $53-54 a barrel.Production remains subdued, for now. The national total averaged 11 million barrels daily as of the first week of January, unchanged on the previous week and down 2 million from a year earlier, according to the latest EIA weekly petroleum report. But the call of the siren could prove too tempting to resist.The large producers are sticking to their cautious stance. As Pioneer’s president, Richard Dealy, told The Wall Street Journal last week, there is little motivation for production growth. The world does not seem to need more oil right now, he noted, so there is no reason to ramp up output.The company’s CEO, Scott Sheffield, went further, saying during a webcast earlier this month that he did not expect U.S. shale to return to growth over the next few years.
Base production in North Dakota has fully recovered after a significant reduction --. Falling crude oil demand and prices, in response to the COVID-19 pandemic, caused rig counts and drilling activity in North Dakota to decline sharply in 2020. Furthermore, producers delayed deliveries of new wells and shut in or curtailed already producing wells, reducing May 2020 oil production in North Dakota by more than 40% from the peak month of October 2019, as Figure 1 illustrates. After June 2020, crude oil production in North Dakota has been recovering, but it is still about 20% lower than the historical high in October 2019. Although the base production (production from wells more than one year old) has fully recovered, the swing production (production from wells less than a year old) has not because a lower rate of new well completions has resulted in fewer new wells. Both base and swing production recorded significant reductions in the second quarter of 2020. As analyzed in the March 2020 Drilling Productivity Report Supplement, base production was relatively immune to market conditions in the past. For example, it remained almost unchanged in 2015 and 2016 when the rig count collapsed by more than 80%. In contrast, swing production is more sensitive to market conditions. During years past, including 2020, producers reduced swing production by drilling and completing fewer new wells and by curtailing output at some very productive existing newer wells. Table 1 illustrates the number of wells producing for at least one day per month. Well counts are divided into wells less than one year old and wells more than one year old. Additionally, Table 1 shows monthly base and swing production levels.
Washington state nixes methanol plant meant to supply China - (AP) — Officials in Washington state denied a key permit for a large proposed methanol plant Tuesday, saying the project that aims to send the chemical to China to be used in everything from fabrics and contact lenses to iPhones and medical equipment would pump out too much pollution. A significant increase in greenhouse gas emissions and inconsistencies with the Shoreline Management Act were the main reasons the permit was rejected for the project planned on the Columbia River, the state Department of Ecology said in a news release. The $2 billion Northwest Innovation Works plant proposed in Kalama would take natural gas from Canada and convert it into methanol. It would then be shipped to China to make olefins — compounds used in many everyday products. An environmental analysis done by the state agency found that the facility would be one of the largest sources of carbon pollution in Washington, emitting nearly 1 million metric tons a year within the state, and millions of tons more from extracting natural gas, shipping the product to Asia and final uses of the methanol, officials said. “I believe we were left with no other choice than to deny the permit for the Kalama project," Ecology Director Laura Watson said in a written statement. "The known and verifiable emissions from the facility would be extremely large and their effects on Washington’s environment would be significant and detrimental.”
Joe Biden plans to pull Keystone XL pipeline permit on first day in office - President-elect Joe Biden plans to rescind a cross-border permit for the Keystone XL oil pipeline on his first day in office, according to multiple reports.The move could sound a death knell for the controversial project, which President Trump tried to resurrect early in his term after his predecessor, Barack Obama, opposed it. The phrase “Rescind Keystone XL pipeline permit” appeared on a list of Day One executive actions that Biden’s transition team gave to American stakeholders, according to Canada’s CBC News, which first reported the development on Sunday.The pledge did not appear on a memo that Biden chief of staff Ron Klain released Saturday outlining the administration’s early priorities, but it was included in a presentation that circulated among lobbyists and trade groups in Washington, Politico reported.Biden’s transition team did not immediately respond to a request for comment Monday morning.By canceling the permit, Biden would reverse one of Trump’s first presidential actions and return to the Obama administration’s stance against the pipeline, which would move oil from the Canadian province of Alberta into Nebraska. Obama’s administration reportedly rejected the permit in 2015, saying the project would contradict its efforts to combat climate change. Trump signed an executive order allowing it to proceed in January 2017, but the project got caught up in a court battle that led to the Supreme Court upholding a ruling against it last year.
Biden nixes Keystone XL permit, halts Arctic refuge leasing - President Biden on Wednesday signed a sweeping executive order that revokes a key permit for the controversial Keystone XL pipeline, halts oil and gas leasing at a wildlife refuge in Alaska and carries out several other environmental actions. This deals a devastating blow to the approximately 1,200-mile-pipeline that carried oil from Canada to the U.S. and that was opposed by several environmental and indigenous groups. The action reverses a decision on a project championed by President Trump, who first issued a permit allowing it to cross the border during the first months of his presidency. Environmentalists have been critical of the pipeline, particularly because it’s supposed to carry oil made from tar sands, whose production is carbon intensive. Tribes have also expressed opposition, saying that the pipeline would cross onto their lands and violate their treaty rights. Biden, in the executive order, argued that the pipeline "disserves" U.S. national interest. "The United States and the world face a climate crisis. That crisis must be met with action on a scale and at a speed commensurate with the need to avoid setting the world on a dangerous, potentially catastrophic, climate trajectory," the order said. "Leaving the Keystone XL pipeline permit in place would not be consistent with my Administration's economic and climate imperatives. " TC Energy, the company behind the pipeline, released a statement on Wednesday expressing disappointment in the decision, arguing that its pipeline would bolster energy security in North America and provide jobs. The company also said it would “review the decision, assess its implications, and consider its options” but added that the pipeline’s advancement will be suspended. Many Republicans opposed the move, and a group of five GOP senators wrote to Biden on Tuesday urging him to “support the completion and operation” of the pipeline. Biden’s order also places a temporary moratorium on oil and gas leasing activities at the Arctic National Wildlife Refuge, coming just one day after the Trump administration issued leases from its first sale. The refuge is home to grizzly bears, polar bears, gray wolves and more than 200 species of birds. It contains land considered sacred by the Gwich’in people. A 2017 tax law requires two lease sales at the refuge by the end of 2024, and one of those occurred at the tail end of the Trump administration, in a manner that critics argued was rushed. Biden, however, opposes oil and gas leasing at the refuge, and pledged to “permanently” protect it on the campaign trail. The temporary moratorium would stop short of a campaign pledge by Biden to ban new permits for oil and gas leasing on public land and in public waters. Asked during a press briefing whether the administration still had that commitment, White House Press Secretary Jen Psaki said "we do and the leases will be reviewed."
North Dakota officials condemn pipeline permit revocation (AP) — North Dakota Republican Gov. Doug Burgum and the state’s all-GOP congressional delegation want President Joe Biden to reconsider his revocation of the permit for the long-disputed Keystone XL oil pipeline. The 1,700-mile pipeline was planned to carry roughly 800,000 barrels of oil a day from Alberta to the Texas Gulf Coast, passing through Montana, South Dakota, Nebraska, Kansas and Oklahoma. Burgum says in a statement that “revoking the permit is wrong for the country and has a chilling effect on private-sector investment in much-needed infrastructure projects.” Sen. Kevin Cramer urged Biden to reconsider the pipeline decision, calling it an “early mistake by the president and a nod to far-left environmental extremists.” North Dakota Pipeline Authority Director Justin Kringstad said Biden’s action “adds to the uncertainty of project development in North Dakota.” It also puts in question the fate of the Dakota Access Pipeline that carries oil from the western part of the state to a shipping point in Illinois. The $3.8 billion pipeline crosses beneath the Missouri River, just north of the Standing Rock Sioux reservation. The Standing Rock Sioux Tribe sent Biden a letter this week requesting that he instruct the U.S. Army Corps of Engineers to stop the pipeline from operating.
Canada scrambles to salvage Keystone XL as Biden prepares to kill troubled pipeline project (Reuters) - U.S. President-elect Joe Biden’s expected move to cancel the Keystone XL pipeline prompted Canada’s main oil-producing province of Alberta on Monday to threaten to seek damages as Ottawa made efforts to save the troubled project. Scrapping the project would threaten Canadian jobs and the U.S.-Canadian relationship as Prime Minister Justin Trudeau tries to turn the page on the Donald Trump era, though the idea drew support from environmental groups and progressive U.S. Senator Bernie Sanders. A source told Reuters on Sunday that Biden will cancel a permit for the $8 billion project over concerns about fossil fuels contributing to climate change, dealing a blow to the Canadian energy sector. The news sent shares in Keystone XL owner TC Energy lower on Monday and prompted Alberta Premier Jason Kenney to urge Trudeau to reach out to the incoming Biden administration in the next 48 hours. Biden, a Democrat, is due to take the oath of office on Wednesday. “This is the 11th hour and if this really is the top priority, as it should be, then we need the government of Canada to stand up for Canadian workers, for Canadian jobs, for the Canadian-U.S. relationship, right now,” Kenney told a news conference. He said Alberta had retained legal counsel and believed there was a “very solid” legal basis to seek damages under international free trade agreements if the pipeline is effectively killed by presidential fiat. Alberta’s financial exposure is just over C$1 billion ($783 million), Kenney said, after the province last year invested in the pipeline, also known as KXL.
TC Energy Reacts to Keystone Pipeline Development - TC Energy Corporation has announced that it is disappointed with the expected action to revoke the existing Presidential Permit for the Keystone XL pipeline and said it would directly lead to the layoff of thousands of union workers. The company noted that it will review the decision, assess its implications and consider its options. It added, however, that as a result of the expected revocation of the Presidential Permit, advancement of the project will be suspended. TC Energy said it will cease capitalizing costs, including interest during construction, effective January 20, 2021, and added that it will evaluate the carrying value of its investment in the pipeline. Absent intervening actions, the company said these steps could result in a predominantly non-cash after-tax charge to earnings in the first quarter of this year. Looking forward, TC Energy said it is well positioned to capture significant additional growth opportunities that are expected to arise as the world both consumes more energy and transitions to a less carbon intensive energy mix. “Our base business continues to perform very well and, aside from Keystone XL, we are advancing $25 billion of secured capital projects along with a robust portfolio of other similarly high quality opportunities under development,” François Poirier, TC Energy’s president and chief executive officer, said in a company statement. “These initiatives are expected to generate growth in earnings and cash flow per share and support annual dividend increases of eight to ten percent in 2021 and five to seven percent thereafter,” he added. Commenting on the latest Keystone XL Pipeline development, American Petroleum Institute (API) President and CEO Mike Sommers said, “revoking the Keystone XL pipeline is a significant step backwards both for environmental progress and our economic recovery”. “Pipelines are the safest, most environmentally friendly way to transport energy, and the economy cannot recover at full speed unless we deliver reliable energy from where it is to where it is needed. The Keystone XL Pipeline has been through more than ten years of extensive environmental reviews, and … [the] announcement is a slap in the face to the thousands of union workers who are already a part of this safe and sustainable project,” he added. “This misguided move will hamper America’s economic recovery, undermine North American energy security and strain relations with one of America’s greatest allies,” Sommers continued.
PIPELINES: Keystone XL exec plans 1K job cuts from Biden order — email -- Thursday, January 21, 2021 -- A top Keystone XL pipeline executive told employees yesterday that more than a thousand jobs would be cut in the coming weeks because of President Biden's decision to pull a key permit for the oil project.
TC Energy could shrug off loss of Keystone XL pipeline project - The potential cancellation of the Keystone XL oil pipeline project after U.S. President Joe Biden rescinded a key permit would not necessarily dampen TC Energy Corp.'s appeal to investors, midstream industry experts said. The Canadian pipeline giant has only suspended the 830,000-barrel-per-day, 1,200-mile pipeline project for now. But TC Energy is not expected to reapply for any permits — including a U.S. presidential permit for crossing the international border between the United States and Canada — following Biden's Jan. 20 executive order, which followed through on a campaign promise. Even though Veritas Investment's Darryl McCoubrey estimated TC Energy will record an impairment charge of at least C$1.00 per share, he noted that the company's natural gas and nuclear segments, which account for approximately 90% of its portfolio, stand to benefit enormously. "A loss in its oil business indirectly enhances opportunity in its other, much more important operations," he said in an interview. "I don't get why it's all doom and gloom. I get that the Keystone XL windfall would have been huge — my estimate is you could've added C$10 per share maybe had it gone forward ... but that decision in itself doesn't ruin TC Energy's appeal." Estimates in media reports have put the cost of the Keystone XL project at roughly $8 billion, a figure that could swell with delays and cost overruns. Alberta, which helped cover development costs and which could face financial exposure of more than C$1 billion, might seek damages from the U.S. because of the permit decision, according to Reuters. According to analysts at RBC Capital Markets, a decision to ditch Keystone XL would best serve TC Energy's equity value. "We believe the market will view TC Energy walking away from KXL as the best outcome for the stock, particularly as we think the stock currently reflects little, if any, value for KXL and investors can now focus on the 'utility-like' story," the analysts told clients Jan. 17.
Biden Blocking Keystone Threatens to End Mega Pipelines Era - Joe Biden’s move to block the $9 billion Keystone XL project is the clearest sign yet that constructing a major new pipeline in the U.S. has become an impossible task. The incoming president has pledged to reshape the U.S. energy sector and accelerate the transition from fossil fuels, and the cancellation of the proposed link to Canada’s oil sands will be one of his first big environmental actions. Even before Biden’s inauguration Wednesday, the oil and gas industry was on its back foot when it came to building major new infrastructure. Despite Donald Trump’s pro-fossil-fuel policies, energy companies such as Williams Cos. and Dominion Energy Inc. have been forced to scrap new projects in the face of stiff opposition. “I can’t imagine going to my board and saying, ‘we want to build a new greenfield pipeline’,” Williams Chief Executive Officer Alan Armstrong said in an interview. “I do not think there will be any funding of any big cross-country greenfield pipelines, and I say that because of the amount of money that’s been wasted.” The industry’s retreat is a victory for the environmental movement. Groups that once campaigned under the slogan Keep It In The Ground have increasingly turned their attention to the pipes. Building them in much of the U.S. is a far trickier business than drilling oil and gas wells. That’s due to the numerous federal and state permits that, for the most part, can be more easily litigated. The Trump administration sought to streamline federal permitting, but many projects were dealt a mortal blow in the courts. “No one is going to announce a new pipeline while Joe Biden is the president,” said Katie Bays, managing director at FiscalNote Markets, which tracks policy issues for investors. Pipelines are likely to face a more burdensome approval process under the new administration, according to industry watchers including analysts at Morgan Stanley. Armstrong, whose company operates the Transco gas pipeline that runs from the Gulf of Mexico up the East Coast, says costs associated with litigation, together with the risk of delays, mean the construction of interstate projects in the U.S. can no longer be justified. He speaks from recent experience. Williams abandoned its Constitution natural gas pipeline in 2020 following years of legal battles with New York over a water permit. Its Northeast Supply Enhancement plan, which would have added pipeline segments in New York, Pennsylvania and New Jersey to an existing Williams system, was also effectively killed off last year amid opposition from New York Governor Andrew Cuomo. In fact, 2020 proved to be an awful year for anyone trying to build a major pipeline. In July, Dominion and its partner Duke Energy Corp. scrapped plans for their $8 billion Atlantic Coast natural gas project along the U.S. East Coast after legal battles, permitting hiccups and ballooning costs. Less than 24 hours later, a U.S. court court ordered the shutdown of the Dakota Access crude oil pipeline -- though the order was later sidelined. In Minnesota, on-the-ground protests from environmental and indigenous activists continue to dog Enbridge Inc.’s proposal to replace its Line 3 crude pipeline, which shuttles crude from Alberta to Wisconsin. Meanwhile, the $6 billion, 303-mile (488-kilometer) Mountain Valley natural gas project -- which along with Line 3 are the last remaining mega pipeline projects still in development in the U.S. -- is running into regulatory hurdles after years of cost overruns and delays. Shares of Equitrans Midstream Corp., which is constructing the pipeline between West Virginia and southern Virginia, plunged 9.9% Tuesday after a meeting of federal regulators in Washington failed to advance the project.
Oil giant splits from powerful lobbying group over climate change - The American Petroleum Institute, the nation's largest and most powerful oil lobby, is losing one of its biggest members over a disagreement about addressing the climate crisis.France's Total announced Friday it is quitting the API because of the lobby's stances on regulation and carbon pricing as well as its support for politicians who oppose the Paris climate agreement. The move makes Total the first major oil company to leave the API because of the climate crisis. The exit underscores the divide in the oil industry over how to respond to climate change. Top European oil companies including Total and BP have made more aggressive promises to slash carbon emissions and invest in clean energy than ExxonMobil (XOM), Chevron and other US firms. The move also comes amid a broader reckoning in Corporate America over political contributions following the insurrection at the US Capitol. "This is a serious blow for API, whose influence largely stems from its claim to be the voice of the entire oil and gas industry," Andrew Logan, director of oil and gas at sustainability nonprofit Ceres, said in a statement. He added the split is "likely to mark the beginning of an exodus from the trade group."Total has helped lead the industry response to the climate crisis. Last year, Total announced agoal to get to net-zero emissions by 2050. Importantly, that goal included the so-called scope 3 emissions from the products it sells, namely gasoline, jet fuel and diesel. For major oil-and-gas companies, scope 3 can comprise as much as 85% of total emissions, according to S&P Global Market Intelligence.
Halliburton reports better-than-expected earnings on big North America revenue jump -- Halliburton reported on Tuesday quarterly results that topped analysts' expectations amid strong revenue from its North America business. The oilfield services company posted a profit of 18 cents per share on revenue of $3.24 billion for the fourth quarter. Analysts expected earnings per share of 15 cents on revenue of $3.21 billion, according to Refinitiv. Shares of Halliburton rose as much as 2.9% on the back of the news. Around noon ET, however, they were down 1.3%. The company's North America revenue grew by 26% to $1.4 billion when compared with the previous quarter due to increased drilling activity in the region. That increase offset lackluster growth from Halliburton's international markets. CEO Jeff Miller said in a statement he was "optimistic about the activity momentum" in North America, adding he expects international drilling to recover later this year. However, the company's adjusted operating income for 2020 fell to $1.4 billion from $2.1 billion a year earlier. Christopher Voie, an analyst at Wells Fargo, said Halliburton could face some headwinds as its valuation appears to be balanced moving forward. Halliburton shares have fallen more than 14% over the past year. However, they have rallied 68% in the past three months as oil prices surge.
U.S. and Canada underestimating climate risk from abandoned oil and gas wells: study (Reuters) - Methane leaking out of the more than 4 million abandoned oil and gas wells in the United States and Canada is a far greater contributor to climate change than government estimates suggest, researchers from McGill University said on Wednesday. Canada has underestimated methane emissions from its abandoned wells by as much as 150%, while official U.S. estimates are about 20% below actual levels, the study, published in Environmental Science and Technology, found. The U.S. Environmental Protection Agency and Environment and Climate Change Canada did not immediately respond to a request for comment on the study. More than a century of oil and gas drilling has left behind millions of abandoned wells around the globe, posing a serious threat here to the climate that governments are only starting to understand, according to a Reuters special report last year. Methane has more than 80 times the warming potential of carbon dioxide in its first 20 years in the atmosphere. In 2019, methane emissions from abandoned wells were included for the first time in U.S. and Canadian greenhouse gas inventories submitted to the United Nations. But the McGill study found there are about 500,000 wells in the United States that are undocumented along with about 60,000 in Canada. It also found that the EPA and ECCC had come up with emissions estimates that were far too low - a conclusion the researchers said was based on their own analysis of emissions levels from different types of abandoned wells in seven U.S. states and two Canadian provinces. Emissions measurements were also not available from major oil and gas-producing states and provinces like Texas and Alberta, adding to uncertainty around the official data, the study said. The study was co-authored by McGill professor Mary Kang, who in 2014 was the first to measure methane emissions from old drilling sites in Pennsylvania.
Western Canada's crude oil supplies to reach record highs in 2021 - Western Canada’s crude oil production, like in many other regions of the world during the spring of 2020, had to pull back sharply in response to the price and demand chaos brought about by COVID-19. By the end of 2020, oil production almost everywhere remained much lower or was being carefully managed to avoid creating another supply glut. In contrast, production in Western Canada has almost fully rebounded, and is being primed to increase to what could be all-time highs this year. With Alberta’s oil sands producers renewing their role as the long-standing driver of oil supply growth and the recent suspension of production limits in the province, the stage is set for us to review the most recent oil supply developments and future growth prospects. Crude oil production in Western Canada has been a favorite topic of the RBN blogosphere in the past year — sometimes for less-than-pleasant reasons. We described what was happening to supplies from Alberta’s oil sands in our two-part Rock Bottom series last March and April, when COVID was rocking the oil world. Those blogs examined the ultra-low pricing of the heavy oil price benchmark, Western Canada Select (WCS), and how the low prices were driving widespread shut-ins at major oil sands production sites. After prices began to recover, prompting some gains in oil sands production, we updated you with a four-part, late-summer series (Never Say Goodbye) on what that supply recovery meant for utilization of Canada’s oil export pipelines. That was topped off in early November with the one-off blog Livin’ on a Prayer, which described the suspension of nearly two years of oil production limits that had been imposed by the province of Alberta since January 2019.The start of a new year gives us a perfect opportunity to both look back at how Western Canada oil supplies evolved over the course of (most of) 2020 and look ahead at what might happen in 2021. The production trends certainly have been much more positive since last spring, with combined oil supplies from Canada’s four Western provinces (British Columbia, Alberta, Saskatchewan, and Manitoba) recovering to 4.24 MMb/d as of November 2020 (dashed black box in left graph in Figure 1), the last month of reported data. This is only 139 Mb/d short of the all-time monthly high of 4.8 MMb/d (dashed pink box) set in December 2019 and a staggering 883 Mb/d above the COVID-induced low of 3.36 MMb/d in May 2020 (dashed red box).
Washington state nixes methanol plant meant to supply China - (AP) — Officials in Washington state denied a key permit for a large proposed methanol plant Tuesday, saying the project that aims to send the chemical to China to be used in everything from fabrics and contact lenses to iPhones and medical equipment would pump out too much pollution. A significant increase in greenhouse gas emissions and inconsistencies with the Shoreline Management Act were the main reasons the permit was rejected for the project planned on the Columbia River, the state Department of Ecology said in a news release. The $2 billion Northwest Innovation Works plant proposed in Kalama would take natural gas from Canada and convert it into methanol. It would then be shipped to China to make olefins — compounds used in many everyday products. An environmental analysis done by the state agency found that the facility would be one of the largest sources of carbon pollution in Washington, emitting nearly 1 million metric tons a year within the state, and millions of tons more from extracting natural gas, shipping the product to Asia and final uses of the methanol, officials said. “I believe we were left with no other choice than to deny the permit for the Kalama project,” Ecology Director Laura Watson said in a written statement. “The known and verifiable emissions from the facility would be extremely large and their effects on Washington’s environment would be significant and detrimental.” The Department of Ecology last year had demanded additional environmental analysis, saying after five years of planning, its backers had failed to provide enough information about the greenhouse gas emissions and how they would be offset. The company has 21 days to appeal the permit decision. “While we are disappointed by this ruling and evaluating our options for an immediate appeal, we feel confident that science and reason will prevail,” The company is backed by the Chinese government and has said the project will create 1,000 jobs and generate up to $40 million in annual tax revenue. The company also has said it would offset any emissions produced directly or indirectly in Washington state.
China's shift from coal helped push natural gas prices to a peak, Eurasia Group - China's shift from coal to gas is a "big overlooked factor" in record high natural gas prices, according to political risk consultancy Eurasia Group. Henning Gloystein, director of energy, climate and resources at Eurasia said millions of households in China were estimated to have moved from coal to natural gas for heating their homes in 2020. The majority of those transitions happened in the last quarter of the year, just before winter arrived, he told CNBC's "Squawk Box Asia" on Monday. Natural gas prices in Asia fell to a record low in the second quarter of last year as the coronavirus crisis spread, but they have surged more than 1,000% since July. According to S&P Global Platts, the benchmark Japan-Korea-Marker (JKM) spot price for liquefied natural gas in February reached a record high of $32.49 MMBtu last week. Much of the price surge has been attributed to extremely cold weather in North Asia, which caused natural gas demand for heating to soar. But Gloystein said new demand from China also likely drove prices to record highs. "We think this is a big overlooked factor," he said. "Sure, it's been cold across the northern hemisphere and there've even been some supply outages, but what happened in China last year is – there are estimates that more than 10 million households were moved from heating using coal … to using natural gas." By some estimates, that's the equivalent of moving all of Australia's households to another fuel in one year, according to Gloystein. "Then it did get really cold, and suddenly they had to serve all this new demand," Gloystein said. Utilities and energy companies did not have enough storage to prepare for such a big increase in demand, he said. As a result, demand outstripped supply and drove prices to a record high. Gloystein said companies usually build up storage during the summer and use it up in the winter, topping up as needed. This time, however, China suddenly had to purchase more gas for new customers at "literally whatever price, and no one was prepared for that in the market." Still, prices are unlikely to remain high for long. "We've heard single cargos indeed sell in the high $30s, I heard one at $39 [per million British thermal units]," said Gloystein. That level seems like the "high mark" for prices and the peak, he said. The jump in prices has been "pretty extreme," but won't last much longer as the cold season is ending and demand for heating will fall, he explained. "At some point, of course, it will get a little bit warmer," he said. "Prices for February and March will probably come down because … the winter will end for sure."
Why Natural Gas Prices Are Set To Go Higher - Winter temperatures below seasonal norms in the northern hemisphere have created a rally in natural gas prices from Asia to Europe. The spot liquefied natural gas (LNG) prices in north Asia jumped to record highs last week, while the key price marker in Europe, the Dutch Title Transfer Facility (TTF), rallied to the highest in more than two years. This winter season, a rebound in Asian natural gas demand, supply issues at major LNG exporters, logistics issues at the Panama Channel, soaring tanker rates, and last but not least, the cold snap from Madrid to Tokyo, are pushing gas prices higher. Even when temperatures return to seasonal norms in coming weeks and the Polar Vortex-induced cold spells in Europe end, natural gas prices will continue to be supported through the spring and summer, as buyers would look to restock, analysts say. In just two months, the global natural gas market turned from an oversupplied or a finely balanced market at best, into a tightening market, leading to hikes in prices from Asia to Europe. The much higher prices in Asia and Europe than the U.S. benchmark Henry Hub will incentivize U.S. LNG spot sales to those markets and the maximizing of U.S. liquefaction capacity, according to analysts. Spot LNG prices in Asia have staged an impressive rally over the past two months and have now soared 18 times from April 2020 lows—and the surge is obliterating even the recent rally in Bitcoin prices. A perfect storm of unusually cold winter in north Asia, outages at major LNG exporters, and logistical and shipping constraints drove the price of Asia’s LNG benchmark, the Japan-Korea Marker (JKM), to the highest on record last week, soaring over $30 per million British thermal units (MMBtu) for the first time. In Spain, home of one of Europe’s biggest terminals, LNG prices also surged amid an unusual cold snap in the country, which brought a rare snowfall in Madrid. The lower-than-normal temperatures in many parts of Europe are driving higher gas withdrawals than usual, setting the stage for higher-than-expected demand through the spring and summer for replenishing stocks. Goldman Sachs expects a “perfect bullish storm” for natural gas prices this year, and raised its forecasts for the prices at the European benchmark, the Dutch Title Transfer Facility (TTF), to $8.30/MMBtu for the rest of this winter, from $6.65/MMBtu expected earlier. Goldman also lifted its spot Asia LNG price outlook to $14.30/MMBtu from $12.65/MMBtu. “The current cold spell in the northern hemisphere is paving the way for a tighter global gas market throughout the year,” Wood Mackenzie said last week in its 2021 gas market outlook.
Shale Driller Stuns Bondholders as Argentina Runs Out of Dollars --In the 99 years since it was founded to pump the oil fields of Patagonia, Argentine energy driller YPF SA has been whipsawed by countless booms and busts. If global oil markets weren’t collapsing, it seemed, then Argentina was mired in a debt crisis that was wreaking havoc on the whole nation’s finances. Never, though, had the company been pushed into a large-scale default of any kind. Until, it would appear, now. Word of this came in an odd way: Officials at state-run YPF sent a press release in the dead of night laying out a plan to saddle creditors with losses in a debt exchange. Implicit in its statement was a threat that traders immediately understood -- failure to reach a restructuring deal could lead to a flat-out suspension of debt payments -- and they began frantically unloading the shale driller’s bonds the next morning. Today, some two weeks later, the securities trade as low as 56 cents on the dollar. Creditors, including BlackRock Inc. and Howard Marks’s Oaktree Capital Group, are gearing up for bare-knuckled negotiations just four months after ironing out a restructuring deal with the government that marked the country’s third sovereign default this century alone. YPF’s downfall underscores just how hard the pandemic has hammered both the global oil industry and the perennially hobbled Argentine economy. Dollars are now so scarce in Buenos Aires that the central bank refused to let YPF buy the full amount it needed to pay notes coming due in March. That was the immediate cause of the restructuring announcement. A longer view reveals a steady decline in the company’s finances since the government re-nationalized it in 2012 and forced it to swell payrolls, artificially hold down domestic fuel prices and skimp on investments, leading to four straight years of oil-and-gas output declines. YPF must now reach a deal with creditors to get its finances in order to boost investment in the gas-rich Vaca Muerta shale formation in Patagonia.
U.S still important in the oil market, even if Biden is less vocal than Trump: UAE energy minister - The U.S. will always play an important role in global energy markets, even though President-elect Joe Biden is likely to be less vocal than President Donald Trump about oil, the UAE's energy minister told CNBC ahead of Inauguration Day. "The United States of America is a major player now … with its production, with the fact that this industry that has been developed through shale oil and gas has created lots of jobs and created an economy by itself," said Suhail al-Mazrouei. That won't change under a new U.S. president who is expected to focus more on renewable energy and less on oil, he said. Whether President Biden and the new administration [will] be vocal on Twitter or not … the role of the United States will be always important. President Trump used to post on Twitter about crude oil and even communicated with OPEC leaders Saudi Arabia and Russia during the oil price war last year. Biden is likely to take a different approach, but al-Mazrouei said the U.S.'s leading role in energy markets is likely to remain. "Whether President Biden and the new administration [will] be vocal on Twitter or not … the role of the United States will be always important," he told CNBC's Hadley Gamble on Tuesday as part of the virtual Atlantic Council Global Energy Forum. Separately, the UAE energy minister said he's "optimistic" that the oil market will recover before OPEC+ cuts expire in April 2022. The oil-producing group and its allies in April reached an agreement to cut a historic 9.7 million barrels per day in an effort to support crude prices after the coronavirus pandemic destroyed demand. The cuts will taper gradually until April 2022, when the deal will expire. In view of the continuing global health crisis, the alliance in December agreed to raise production by 500,000 barrels per day instead of the initial 2 million bpd. This month, OPEC+ agreed to hold output largely steady, while Saudi Arabia announced an additional voluntary cut of 1 million bpd for February and March. South Belridge Oil Field is the fourth-largest oil field in California and one of the most productive in the U.S. David McNew | Getty Images Al-Mazrouei said there are still many barrels of oil in storage and the market is not balanced yet. "We continue drawing down on the inventories until we reach some reasonable levels, and hopefully that will be done by … the timeframe that we set, which is April 2022," he said. "I'm optimistic that we would reach it before [that]," he added. "But let's say, even if it takes us … to that date, then I think that will take us to balance."
IEA cuts 2021 oil demand outlook as new Covid lockdowns weigh on fuel sales— The International Energy Agency on Tuesday cut its 2021 global oil demand forecast, citing soaring Covid-19 cases and renewed lockdown measures that will further limit mobility. The IEA said it now expects world oil demand to recover by 5.5 million barrels per day to 96.6 million this year. That reflects a downward revision of 0.3 million barrels from last month's assessment and follows an unprecedented collapse of 8.8 million barrels per day last year as the coronavirus pandemic battered global oil markets. The IEA's latest oil market report comes as countries continue to implement strict public health measures in an attempt to curb virus spread, with lockdowns imposed in Europe and parts of China. The Paris-based energy agency said oil demand growth was projected to fall slightly during the first three months of the year in the wake of tougher government plans that call for additional travel restrictions. This is expected to curb worldwide mobility once again, prompting the IEA to trim its first-quarter forecast for oil demand growth to 94.1 million barrels per day. That would see oil demand return to near year-ago levels and reflects a downward revision of 0.6 million barrels from December's oil market report. "The global vaccine roll-out is putting fundamentals on a stronger trajectory for the year, with both supply and demand shifting back into growth mode following 2020's unprecedented collapse," the IEA said in its closely-watched report. "But it will take more time for oil demand to recover fully as renewed lockdowns in a number of countries weigh on fuel sales," it added. Oil prices have rallied in recent weeks, supported by optimism over Covid vaccine rollouts and a surprise oil production cut from OPEC kingpin Saudi Arabia. However, the relatively slow pace of inoculations has raised doubts over how soon economies can recover. International benchmark Brent crude futures traded at $55.26 a barrel on Tuesday morning, up more than 0.9%, while U.S. West Texas Intermediate futures stood at $52.51, around 0.3% higher. Both benchmarks fell more than 2.2% in the previous session, notching their worst daily performance since Dec. 21.
OPEC chief pledges to deepen ties with new administration even as Biden calls for climate action— Oil-producing group OPEC will continue to strengthen its relationship with the U.S. energy industry under Joe Biden's new administration, the oil cartel's Secretary General Mohammed Barkindo told CNBC on Tuesday. It comes despite the Democratic leader's stated commitment to fight climate change and focus on renewable energy. Barkindo congratulated Biden for his upcoming inauguration during a virtual panel hosted by the Atlantic Council Global Energy Forum, and said: "We continue to deepen this relationship, which we found mutually beneficial to all of us." "And we intend to continue along this fashion going forward and the administration of President Biden," he told CNBC's Hadley Gamble in an exclusive interview. OPEC leaders were known to have at times communicated with outgoing President Donald Trump, who was particularly vocal and active about the oil markets and what he believed oil-producing countries should do to alter crude prices. Biden's likely change in approach — as well as his focus on investment in non-oil energy sources — have reportedly unsettled some in the 13-member oil-producing group. The president-elect's potential return to the Iran nuclear deal, which could bring millions of barrels of new oil onto the market, has also raised concerns. The OPEC chief has been diplomatic when it comes to discussing U.S. presidents, but some in the organization are wary of strains with Biden, according to sources cited by Reuters. Asked if he had been in touch with Biden yet, Barkindo replied: "No, not at all." "We believe that we have established very mutually beneficial productive relationships with the industry in the United States. And I think we have no option but to continue to strengthen this relationship under President Biden," he added. Dan Yergin, a longtime oil industry expert and founder of IHS Markit, said during the same panel that Biden's biggest impact on the oil industry would be his commitment to climate change action. "I think he is going to step on the gas on climate," Yergin said. He expects the administration to provide "incentives for electric vehicles ... For solar, wind, and more regulations (for the oil industry) across the board." Biden has named climate change as one of the four biggest crises facing the U.S. and plans to rejoin the Paris Climate Accord on his first day in office. Trump withdrew from the climate deal in 2017. Looking ahead, global trends surrounding energy and climate may be worrying OPEC member states far more than whoever is in the White House. "It is extremely important to understand one thing," Fatih Birol, executive director of the International Energy Agency, said during the panel. "The share of oil in the global energy markets will decline. And the speed of this decline will be determined by the pace of energy transitions." "The political position of the U.S. will give unmistakable signals to investors around the world," he added.
Oil's supply-led rally peters out as virus cases surge - Oil prices on Monday fell further from 11-month highs touched last week, ending a rally that started at end-October on production cuts and strong Chinese demand, with the market's outlook questioned as coronavirus infections rise. Brent crude fell 30 cents, or 0.5%, to $54.79 a barrel by 0622 GMT, after dropping 2.3% on Friday. U.S. oil was down by 21 cents, or 0.4%, at $52.15 a barrel, having declined 2.3% in the previous trading session. The benchmarks had rallied in recent weeks, buoyed by the start of Covid-19 vaccine rollouts and a surprise cut of crude output by the world's biggest oil exporter, Saudi Arabia. Surging new infections throughout the world, however, have raised doubts about how long demand would hold up. U.S. drillers added further pressure by putting more oil and natural gas rigs to work for an eighth consecutive week last week because rising prices have made production more profitable. Still, the number of operating rigs is less than half of the level of a year ago. Still, U.S. drillers "have indicated they will continue to keep their spending under control," ANZ Research said in a note. "The economics also don't favor a surge in drilling, with half of the industry still uneconomical." U.S. shale producers have quickly responded to market gains in recent years, winning market share as Saudi Arabia and other major producers such as Russia have cut production in an attempt to support global oil and gas prices. Shale companies are also taking advantage of market gains by locking in prices for future sales, sources familiar with the matter told Reuters at the end of last week. In China, where new Covid-19 infections have been rising, more than 28 million people are in lockdown as Beijing tries to avoid a resurgence of the coronavirus in the country where it was first discovered.
WTI Slides After Surprise Crude Build -- Oil prices gave back a lot of their early gains today as chatter about the US stimulus plan suggested its not ponies and unicorns for all after all and worries about Chinese demand weighed. WTI slipped back below $53 briefly. The U.S. “is still the biggest market in the world and it hasn’t recovered all the demand loss,”said Peter McNally, global head for industrials, materials and energy at Third Bridge. In the near-term, additional lockdown measures in China are weighing on the outlook as “Chinese demand has been one of the big drivers of improved oil fundamentals.”For now, all eyes are back on inventories to see if the seasonal slowdown is accelerating surging product stocks. API:
- Crude +2.562mm (-2.5mm exp)
- Cushing -4.285mm
- Gasoline +1.129mm
- Distillates +816k
Crude inventory unexpectedly rose last week (+2.5mm vs -2.5mm exp) as product stocks rose for the 3rd straight week...WTI hovered just above $53 ahead of the API data and fell back below on the surprise crude build...
Oil Dips on Demand Pessimism -- Oil dipped toward $53 a barrel as pessimism over the short-term demand outlook in the world’s two largest economies was partially offset by more weakness in the dollar. Futures in New York headed for the first daily drop this week after the American Petroleum Institute said that U.S. crude inventories swelled by 2.56 million barrels last week and gasoline and distillates stockpiles also increased, according to people familiar with the data. Analysts surveyed by Bloomberg have forecast a drop in the inventories before the official data. The API snapshot comes amid signs global fuel consumption is set to take another hit as the rapidly spreading coronavirus spurs more stay-at-home orders and travel curbs. JPMorgan Chase & Co. cut its demand estimates for China as lockdowns spread ahead of the Lunar New Year travel rush. Despite the worsening short-term consumption outlook, crude is still trading near the highest level in almost a year. Saudi Arabia’s unilateral output cuts and a weak dollar, which boosts the appeal of commodities that are priced in the currency, have helped prevent declines. Investors are also optimistic that the administration of President Joe Biden will unleash a major effort to revive growth and rein in the spread of the virus in the U.S. ”The big-picture elements of festering Covid-19, spread of vaccinations, the change of administration in the U.S. and hopes for fresh stimulus have been factored in for the time being,” said Vandana Hari, founder of consulting firm Vanda Insights in Singapore. There’s unlikely to be any major price shocks from the new U.S. administration over the next few days, she said.
Oil rise on hopes of U.S. stimulus and crude stocks drawdown - Oil prices rose on Wednesday, adding to solid gains overnight, on expectations the incoming U.S. administration will go ahead with massive stimulus spending that would boost fuel demand and draw down crude stocks. U.S. West Texas Intermediate (WTI) crude futures climbed 37 cents, or 0.7%, to $53.35 a barrel at 0427 GMT, building on a 1.2% rise on Tuesday. Brent crude futures rose 35 cents, or 0.6%, to $56.25 a barrel, adding to a 2.1% gain on Tuesday. U.S. President-elect Joe Biden's Treasury Secretary nominee Janet Yellen urged lawmakers on Tuesday to "act big" on pandemic relief spending, reinforcing hopes of massive spending to boost growth. "Certainly the expectation is that will support better growth and better demand in the U.S.," said National Australia Bank's head of commodity research, Lachlan Shaw. However, the market remains concerned about near-term oil demand as the International Energy Agency cut its outlook for first-quarter oil demand by 580,000 barrels per day, due to tight lockdowns and border closures to stop soaring Covid-19 infections. China's capital Beijing on Wednesday announced stricter Covid-19 control measures and will shut down a subway station after the city reported its biggest daily jump in new Covid-19 cases in more than three weeks. The country is experiencing its most severe Covid-19 outbreak since March 2020 ahead of the key Lunar New Year holiday season. More than 20 provincial-level regions have asked people to stay put during the holiday. Germany on Tuesday extended a lockdown for most shops and schools for another two weeks, to Feb. 14. Traders will be watching out for U.S. crude and products inventory data due from the American Petroleum Institute on Wednesday and from the Energy Information Administration on Friday. Six analysts polled by Reuters estimated, on average, that crude stocks fell by 300,000 barrels in the week to Jan. 15, but expect gasoline stockpiles rose by 3.0 million barrels. Distillate inventories, which include diesel, heating oil and jet fuel, were seen up by 800,000 bbl.
Oil Prices Rise Despite Consumption Concerns -- Oil pared a rally late in the trading session as concerns over lackluster consumption clouded optimism around the likelihood of additional U.S. stimulus. Futures closed less than 1% higher in New York on Wednesday. Investors are focusing on Washington with U.S. President Joe Biden taking office. Biden has asked lawmakers to pass a $1.9 trillion virus aid package, which could support crude consumption. Still, fuel use is expected to take another hit as new virus outbreaks in China add to a wave of infections in Europe and other parts of the world. The U.S. “is still the biggest market in the world and it hasn’t recovered all the demand loss,” said Peter McNally, global head for industrials, materials and energy at Third Bridge. In the nearterm, additional lockdown measures in China are weighing on the outlook as “Chinese demand has been one of the big drivers of improved oil fundamentals.” Despite the day-to-day fluctuations in headline crude prices, U.S. crude’s closest contract is the most expensive versus those for six months out in about a year. Key Brent spreads are also in what is known as backwardation, an indication of tight supply. Crude has held near $53 a barrel in New York with the nation working to roll out vaccinations as it struggles to contain the pandemic. Still, prices remain supported by the OPEC+ alliance’s continued production curbs. The “U.S. inauguration will tilt oil supply risks in a bearish direction, but Saudi determination to support markets holds sway for now,” said Paul Sheldon, chief geopolitical risk analyst at S&P Global Platts. “OPEC+ production cuts are markets’ most supportive factor at current prices and now appear to be running ahead of coronavirus-related demand uncertainty.” West Texas Intermediate for February delivery, which expires Wednesday, gained 26 cents to settle at $53.24 a barrel. The March contract rose 33 cents to settle at $53.31 a barrel. Brent for March settlement added 18 cents to end the session at $56.08 a barrel. The Bloomberg Dollar Spot Index weakened for a third session, boosting the appeal of commodities priced in the currency Meanwhile, Chinese imports of U.S. and Russian crude last month were at similar levels to November, while purchases from Saudi Arabia and Iraq fell, according to customs data released Wednesday. Imports from Iran almost doubled. In the U.S, crude inventories are expected to have declined last week, according to a Bloomberg survey. The American Petroleum Institute will report its tally later Wednesday ahead of U.S. government storage figures at the end of the week.
Oil steadies after unexpected build in U.S. crude stockpiles (Reuters) - Oil prices steadied on Thursday after industry data showed a surprise increase in U.S. crude inventories that revived pandemic-related fuel demand concerns, while U.S. stimulus hopes buoyed prices. Brent crude futures rose 2 cents to settle at $56.10 a barrel. U.S. West Texas Intermediate (WTI) crude futures fell 18 cents to settle at $53.13 a barrel. Both benchmarks rose over the past two days on expectations of massive COVID-19 relief spending under new U.S. President Joe Biden. Late Wednesday, industry data showed U.S. crude oil inventories rose 2.6 million barrels last week, compared with analysts' forecasts in a Reuters poll for a 1.2 million-barrel draw. [API/S] Official inventory data has been delayed by two days to Friday due to the Martin Luther King Jr. holiday and Inauguration Day. "We are on pause until we get the inventory report," said Phil Flynn, senior analyst at Price Futures Group in Chicago. "The market is waiting to see what we're going to see in inventories tomorrow and stimulus down the road." Elsewhere, compliance with a deal to cut output from the Organization of the Petroleum Exporting Countries and its allies fell in December from November. Compliance reached 99% last month, two sources told Reuters. Meanwhile, rising coronavirus cases in China, the world's largest crude oil importer, weighed on prices. Beijing plans to impose strict virus testing requirements during the Lunar New Year holiday season, when tens of millions of people are expected to travel, as it battles the worst wave of new infections since March 2020. The commercial hub of Shanghai reported its first locally transmitted cases in two months on Thursday.
Oil prices fall as China's surging COVID-19 cases trigger clampdowns - Oil prices dropped on Friday, retreating further from 11-month highs hit last week, weighed down by worries that new pandemic restrictions in China will curb fuel demand in the world's biggest oil importer. U.S. West Texas Intermediate (WTI) crude futures dropped 53 cents, or 1%, to $52.60 a barrel at 0445 GMT, after slipping 18 cents on Thursday. Brent crude futures fell 45 cents, or 0.8%, to $55.65 a barrel, erasing a 2 cent gain on Thursday. Recovering fuel demand in China underpinned market gains late last year while the United States and Europe lagged, but that source of support is fading as a fresh wave of COVID-19 cases has sparked new restrictions to contain the spread. "Indeed, investors are struggling to see through short-term pain for long-term gain heading into the weekend as COVID case counts in China are the most significant demand concern for traders," Axi chief market strategist Stephen Innes said in a note. The commercial hub of Shanghai reported its first locally transmitted cases in two months on Thursday, and Beijing is urging people not to travel during the upcoming Lunar New Year holiday, when tens of millions of urban workers typically head back to their villages. A seasonal boost to China's gasoline demand that is typically seen during the New Year holidays will be moderated by the tightened restrictions this year, consultancy FGE said in a note. "We now have some data on vaccine rollouts, which show that acceptability is a bit on the low side, so pace of implementation may be slow... There may well be a bearish momentum developing (in oil markets)," said Sukrit Vijayakar, director of energy consultancy Trifecta. The market is awaiting official oil inventory data from the U.S. Energy Information Administration on Friday, after industry data on Wednesday showed a surprise 2.6 million barrel increase in U.S. crude inventories last week compared with analysts' forecasts for a 1.2 million barrel draw.
WTI Extends Losses After Surprise Crude Build - Oil prices have tumbled since API's surprise crude build, but stimulus hopes in the US continue to battle record COVID case/death headlines in the bull/bear battle for crude. The Covid-19 situation “is keeping the oil market heeled, unable to take the next leg higher,” However, this morning has seen a ramp from the low $51s as Biden's Executive Orders restraining new drilling sparked bullish calls from Goldman. DOE:
- Crude +4.352mm (-2.5mm exp)
- Cushing -4.727mm
- Gasoline -259k
- Distillates +457k
DOE confirms API's reporting with the first crude build of the year (but a major draw at Cushing, which is central to WTI pricing), Graphics Source: Bloomberg
Oil falls on China's COVID-19 cases, high crude build (Reuters) - Oil prices settled lower on Friday, weighed down by a build in U.S. crude inventories and worries that new pandemic restrictions in China will curb fuel demand in the world’s biggest oil importer. Brent crude futures fell 69 cents to settle at $55.41 a barrel, for a 0.4% change on the week. U.S. West Texas Intermediate (WTI) crude futures fell 86 cents, or 1.6%, settling at $52.27, nearly unchanged from the beginning of the week. Overall U.S. crude inventories surprisingly rose by 4.4 million barrels in the most recent week, versus expectations for a draw of 1.2 million barrels. U.S. energy firms this week added oil and natural gas rigs for a ninth week in a row amid higher energy prices over the past few months, energy services firm Baker Hughes said on Friday, but the overall count is still 52% below this time last year. Recovering fuel demand in China underpinned market gains late last year while the United States and Europe lagged, but that source of support is fading as a fresh wave of COVID-19 cases has sparked new restrictions. Travel on U.S. roads fell 11% in November, a steeper decline over October road use as coronavirus cases increased, the U.S. Transportation Department said Friday. “The pandemic seems to continue to expand into a second wave in China, with infections rising by the day and reaching again different regions such as Shanghai,” said Rystad Energy oil markets analyst Louise Dickson.U.S. crude inventory data showed signs of strength in domestic product demand.While U.S. crude oil stockpiles rose unexpectedly last week, refineries hiked output to their highest capacity usage since March and demand for gasoline and diesel increased week on week. “Crude oil exports did fall quite dramatically, which is the main reason for a decent build overall in crude stocks,”
Pair Of Iranian Oil Tankers Intercepted In Red Sea: Syrian PM - On Sunday Syria’s Prime Minister Hussein Arnous announced that in total seven Iranian oil tankers have been intercepted en route to the country while they were in the Red Sea to date. This includes two which he said were the latest to be detained. This comes amid severe shortages hitting the sanctions-choked as the US continues its economic war. According to Reuters: The shortages worsened after seven oil tankers on their way to Syria were intercepted in "terrorist attacks" with two of the vessels delayed for over a month in the Red Sea before loading, Arnous was quoted as saying in state media without elaborating. No details were given as to the timeline of the tanker intercepts or who was exactly behind it, but the strong suggestion was that the 'targeting' was due to US sanctions enforcement. "Prime Minister Hussein Arnous did not specify how Syria would secure extra supplies but said they had already imported 1.2 million tons of Iranian crude oil that cost along with petroleum products in the last six months around $820 million," Reuters continued. Prior to American forces and Syrian Kurdish proxy militias occupying Syria oil and gas fields in Deir Ezzor, Syria was largely energy independent - having just enough to cover its domestic needs. But over the last couple years miles-long lines have become the "norm" outside gas stations due to the extreme shortages. "We have become dependent on imported oil and we have used up foreign currency in large amounts to pay for petroleum products," PM Arnous said in a speech to Parliament addressing the crisis.
Dubai, Pandemic Party Haven, Faces Its Biggest Surge - - Masks off the minute you step inside. Bars packed and pulsing like it’s 2019. Social media stars waving bottles of champagne. DJs spinning party tunes through multi-hour brunches.Since becoming one of the world's first destinations to open up for tourism, Dubai, in the United Arab Emirates, has promoted itself as the ideal pandemic vacation spot. It cannot afford otherwise, analysts say, as the virus shakes the foundations of the city-state's economy.With its cavernous malls, frenetic construction and legions of foreign workers, Dubai was built on the promise of globalization, drawing largely from the aviation, hospitality and retail sectors — all hard hit by the virus.Now reality is catching up to the big-dreaming emirate. With peak tourism season in full swing, coronavirus infections are surging to unprecedented heights. Daily case counts have nearly tripled in the past month, forcing Britain to slam shut its travel corridor with Dubai last week. But in the face of a growing economic crisis, the city won't lock down. “Dubai's economy is a house of cards," said Matthew Page, a nonresident scholar at the Carnegie Endowment for International Peace. “Its competitive advantage is being a place where rules don't apply."While most countries banned tourists from the U.K. over fears of the fast-spreading virus variant found there, Dubai, home to some 240,000 British expats, kept its doors open for the holidays. Emirates flew five daily flights to London’s Heathrow Airport.Within days, the new virus strain had arrived in the emirates, but that didn't stop reality TV and soccer stars from fleeing Britain's lockdown and wintry weather for Dubai’s bars and beaches — without taking a coronavirus test before boarding. Scenes of pre-pandemic revelry were splattered across British tabloids. Facing backlash, Instagram influencers spotted at raucous yacht parties were quick to proclaim their travel “essential.” Dubai was glad of the influx. Hotel occupancy rates surged to 71% in December, according to data provider STR. The London-Dubai air route ranked busiest in the world over the first week of January, said OAG, an aviation data analysis firm. “People have had enough of this pandemic already,” said Iris Sabellano from Dubai's Al Arabi Travel Agency, adding that many of her clients have been forced to quarantine after testing positive for the virus on arrival or before departure. Travelers coming from a select list of countries don't need to get tests before their trips but all must at Dubai's airport. “With vaccines coming out, they feel it's not the end of the world, they're not going to die," she said. For those who do die of COVID-19, long-haul airline Emirates offers to pay $1,800 to help cover funeral costs.
Israeli human rights organization declares Israel an apartheid state -B’Tselem, one of Israel’s foremost human rights organisations, has issued a report stating that Israel is not a democracy but an “apartheid regime” that enforces Jewish supremacy over the Palestinians in all the land it controls. It confirms not only what critics of Israel’s brutal suppression of the Palestinians have long been saying, but also the historic bankruptcy and reactionary culmination of the Zionist project and all such nationalist programs. In the 1967 War, Israel seized the West Bank and East Jerusalem, previously under Jordanian rule, and Gaza, previously administered by Egypt and under blockade by Israel since 2007. Collectively they are home to more than five million Palestinians. Within Israel, there are approximately 2 million citizens of Palestinian origin, one fifth of the total population, meaning that Palestinians from around half of the population in the lands controlled by Israel. All these four Palestinian groups have different rights from each other that are all inferior to those of Jewish Israelis living in the same areas (except for Gaza where there are no Israeli settlements). As B’Tselem points out, “the entire area between the Mediterranean Sea and the Jordan River is organized under a single principle: advancing and cementing the supremacy of one group—Jews—over another—Palestinians.” B’Tselem’s report, “A regime of Jewish supremacy from the Jordan River to the Mediterranean Sea: This is apartheid,” argues, “By geographically, demographically and physically engineering space, the regime enables Jews to live in a contiguous area with full rights, including self-determination, while Palestinians live in separate units and enjoy fewer rights. This qualifies as an apartheid regime, although Israel is commonly viewed as a democracy upholding a temporary occupation.” Apartheid is deemed a crime under international law. In 1973, the United Nations General Assembly called for the ratification of The International Convention on the Suppression and Punishment of the Crime of Apartheid, which the 2002 Rome Statute of the International Criminal Court defined as inhumane acts “committed in the context of an institutionalized regime of systematic oppression and domination by one racial group over any other racial group or groups and committed with the intention of maintaining that regime.” Neither Israel nor its chief backer the US signed up to the Rome Statute. Hagai El-Ad, B’Tselem’s executive director, said, “Israel is not a democracy that has a temporary occupation attached to it. “It is one regime between the Jordan River to the Mediterranean Sea, and we must look at the full picture and see it for what it is: apartheid.” B’Tselem is not alone it its view. Israeli human rights groups, leftist groups, the so-called “peace camp”, the Meretz Party and politicians, including President Reuven Rivlin and former Prime Ministers Ehud Barak and Ehud Olmert, have for some time been warning that while there was “not yet apartheid” in Israel, it was on a slippery slope. More than a few politicians argued that without a “two state solution,” Israel would become an apartheid state.
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