oil prices hit 7 year high, natural gas hits 14 year high on largest one day price jump on record; natural gas supplies see largest draw this winter; gasoline inventories up most in any 4 week period since Jan 1990 as gasoline demand, excluding worst Covid drops, is at a 10 year low; gasoline imports at a 87 week low; total inventories of oil & all products made from it are at 7 1/2 year low with Strategic Petroleum Reserve at a new 19 year low
Oil prices rose for a sixth straight week and eclipsed the 7 year high hit last week on heightened tension over Ukraine, tight supplies, and perceptions of rising demand...after rising 2.2% to $85.14 a barrel last week on supply disruptions in the Middle East and on rising tensions between NATO and Russia, the contract price for US light sweet crude for March delivery opened lower on Monday, but rallied to trade slightly higher amid fading Omicron fears and lingering concerns over tightening supplies, on the back of geopolitical tensions in Eastern Europe and the Middle East, but tumbled 4% in afternoon trading amid a steep selloff in global financial markets and a rapidly strengthening U.S. dollar, before partially recovering to finish $1.83 lower at $83.31 a barrel, as the possibility of sooner than expected increases in interest rates had markets spooked...but oil prices opened 1% higher on Tuesday, supported by prospects of short-term supply scarcity on global oil markets due to OPEC+'s inability to quickly raise production and a heightened geopolitical risk premium in the Middle East, and then further rallied in afternoon trade amid growing fears of a Russian invasion of Ukraine and a consequent tightening in supplies. before settling $2.29 higher at $85.60 a barrel, on concerns that supplies could become tight due to Ukraine-Russia tensions, on threats to infrastructure in the United Arab Emirates, and on struggles by OPEC+ to hit its targeted monthly output increase. as traders assessed growing risks of severe sanctions on Russian energy exports in response to the escalating tensions along the Ukrainian border and lower-than-expected inventory levels in the industrialized countries....oil began trading lower on Wednesday after the American Petroleum Institute reported a smaller than expected draw from US crude supplies, but spiked higher in late morning trading in a reaction to EIA inventory data showing total U.S. crude and petroleum product supplies declined more steeply, amid lower oil production and recovering demand for gasoline, while a large drawdown from Cushing stockpiles, the delivery point for WTI contracts, rallied March futures towards $88 barrel, before they settlled $1.75 higher at a fresh seven year high of $87.45 a barrel, as traders fretted over Russia-Ukraine tensions...oil prices advanced again early on Thursday despite an offer of a "diplomatic path" out of the NATO/Russian crisis, but turned lower under pressure from a rallying U.S. Dollar Index following a better-than-expected reading for U.S. fourth-quarter GDP and a hawkish inflation assessment from Fed, and finished with a 74 cent loss on the day at $86.61 a barrel as the market balanced concerns about tight worldwide supplies with expectations the Fed would soon tighten monetary policy....oil prices reversed higher in early morning trade Friday, with all petroleum related contracts heading for their sixth consecutive weekly advance, spurred by heightened geopolitical risk related to tensions along the Russian-Ukrainian border, and the threat of another missile attack on Gulf oil infrastructure from Iranian backed Houthis. and then reached a seven-year high intraday high of $88.84 a barrel early in the session, before falling back to settle just 21 cents higher at $86.82 per barrel, amid concerns of tight supplies as major producers continued their policy of limited output increases amid rising fuel demand...oil prices thus posted their sixth straight weekly gain, ending 2% higher than last Friday's close, fueled by a combination of robust demand, constrained supplies and heightened geopolitical risks amid the tension between the West and Russia over Ukraine..
Meanwhile, natural gas prices settled higher for the fourth time in five weeks, after spiking as much as 72 percent to a 14 year high in the last hour of trading on Thursday, just before trading of the February gas contract expired....after falling 6.2% to $3.999 per mmBTU last week as key temperatures warmed and forecasts moderated, the contract price of natural gas for February delivery moved up on soaring European prices Monday and settled 2.8 cents higher at $4.027 per mmBTU, as Texas natural gas output remained slow to recover from well freeze-offs earlier in January, and then rose another 2.6 cents to $4.053 per mmBTU on Tuesday, as frigid weather and high heating demand over the past week in the U.S. Northeast kept next-day power and spot gas prices in New York and New England at or near their highest levels since January 2018...natural gas prices jumped on Wednesday after one of the major weather models staged the largest reversal this winter, resulting in a huge jump in projected heating demand for the next two weeks, and settled 22.4 cents higher at $4.277 per mmBTU...the February natural gas contract hovered in a narrow range early Thursday, but began rallying after a bullish government inventory report and some usual buying into the contract's expiration, and then spiked nearly 70% on short-covering in the final hour of trading to a 14 year intraday high at $7.400 per mmBTU, before settling $1.988 higher on the session at $6.265 per mmBTU, the sharpest one-day climb for natural gas in exchange history, as no other trading day in the past decade featured a price move even half as large....with the February contract off the boards on Friday, natural gas quotes referenced the contract price of natural gas for March delivery, which had risen 24.7 cents to $4.283 per mmBTU on Thursday, from where it rose another 35.6 cents to $4.639 per mmBTU, riding high on winter weather forecasts, light production, falling stockpiles and robust demand for U.S. exports....natural gas price quotes thus finished the week 16.0% higher, while the March gas contract, which had closed at $3.782 per mmBTU last Friday, added 85.7 cents or 22.7%...
With natural gas prices seeing their largest jump in history this week and hitting a 14 year high in the process, we'll add a graph here to show what that looked like...
The above is a screenshot of the interactive natural gas price chart for the February gas contract from barchart.com, which i have reset to show the price of February natural gas every half hour over its last five days of trading...this interactive graph can also be reset to show prices of front month or individual monthly natural gas contracts over time periods ranging from 1 day to 30 years, as the menu bar on the top indicates, and also to show natural gas prices by the minute, hour, day, week or month for each...each bar in the graph above represents the range of natural gas prices over 30 minutes, with periods when prices rose indicated in green, with the opening price of natural gas during that time at the bottom of the bar and the closing price at the top, and periods when prices fell indicated in red, with the opening price of natural gas at the top of the bar and the closing price at the bottom, while the small sticks above or below each half hour bar represent the extent of the price change above or below the opening and closing price during the period in question....meanwhile, the bars across the bottom show trading volume for the February contract for the periods in question, again with up periods indicated by green bars and down periods indicated in red...it's pretty clear from this graph that almost the entirely of Thursday's price jump came in the last hour, with most of that in the last half hour..
The EIA's natural gas storage report for the week ending January 21st indicated that the amount of working natural gas held in underground storage in the US fell by 219 billion cubic feet to 2,591 billion cubic feet by the end of the week, the largest gas storage withdrawal since February 19th of last year, which left our gas supplies 308 billion cubic feet, or 10.6% below the 2,899 billion cubic feet that were in storage on January 21st of last year, and 25 billion cubic feet, or 1.0% below the five-year average of 2,616 billion cubic feet of natural gas that have been in storage as of the 21st of January over the most recent five years....the 219 billion cubic foot withdrawal from US natural gas working storage for the cited week was a bit more than the average forecast for a 214 billion cubic foot withdrawal from a S&P Global Platts' survey of analysts, but was way more than the 137 billion cubic feet that were pulled from natural gas storage during the corresponding week of 2021, and also quite a bit more than the average withdrawal of 161 billion cubic feet of natural gas that have typically been pulled out 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 21st indicated that despite a drop in our oil imports, a shift in unaccounted for crude from demand to supply and a moderate withdrawal of crude from our Strategic Petroleum Reserve meant we had enough oil left to add to our stored commercial crude supplies for the second time in 9 weeks and for the 12th time in the past thirty-five weeks….our imports of crude oil fell by an average of 509,000 barrels per day to an average of 6,236,000 barrels per day, after rising by an average of 675,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 186,000 barrels per day to an average of 2,796,000 barrels per day during the week, which together meant that our effective trade in oil worked out to a net import average of 3,440,000 barrels of per day during the week ending January 21st, 695,000 fewer barrels per day than the net of our imports minus our exports during the prior week…over the same period, production of crude oil from US wells was reportedly 100,000 barrels per day lower at 11,600,000 barrels per day, and hence our daily supply of oil from the net of our international trade in oil and from domestic well production appears to have totaled an average of 15,040,000 barrels per day during the cited reporting week…
Meanwhile, US oil refineries reported they were processing an average of 15,497,000 barrels of crude per day during the week ending January 21st, an average of 44,000 more barrels per day than the amount of oil that our refineries processed during the prior week, while over the same period the EIA’s surveys indicated that a net of 161,000 barrels of oil per day were being added to the supplies of oil stored in the US…so based on all that reported & estimated data, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports and from oilfield production was 617,000 barrels per day less than what our oil refineries reported they used during the week plus what we added to storage 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 (+617,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a balance sheet fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting there must have been a error or omission of that magnitude in this week’s oil supply & demand figures that we have just transcribed...moreover, since last week’s EIA fudge factor was at (-501,000) barrels per day, that means there was a 1,118,000 barrel per day difference between this week's balance sheet error and the EIA's crude oil balance sheet error from a week ago, and hence the week over week supply and demand changes indicated by this week's report are completely worthless.....however, since most everyone treats these weekly EIA reports as gospel and since these figures often drive oil pricing, and hence decisions to drill or complete oil wells, we’ll continue to report this data just as it's published, and just as it's watched & believed to be reasonably accurate by most everyone in the industry...(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….
This week's 161,000 barrel per day increase in our overall crude oil inventories left our total oil supplies at 1,006,972,000 barrels, just 1,845,000 barrel above a 10 year low...this week's oil inventory increase came as 340,000 barrels per day were being added to our commercially available stocks of crude oil, while 179,000 barrels per day of oil were being pulled out of our Strategic Petroleum Reserve, part of the first installment of Biden's plan to release 50 million barrels from the SPR, in order to incentive continued use of US gas guzzlers....including the drawdowns from the Strategic Petroleum Reserve under such politically motivated programs, a total of 64,288,000 barrels have been removed from the Strategic Petroleum Reserve over the past 18 months, and as a result the amount of oil left in our Strategic Petroleum Reserve has fallen to the lowest since November 8th, 2002, or to another new 19 year low of 590,782,000 barrels per day, as repeated tapping of our emergency supplies for political expediency or to “pay for” other programs had already drained those supplies considerably over the past dozen years...based on an estimated prepandemic consumption level of around 18 million barrels per day, the US will have roughly 30 1/2 days of oil supply left in the Strategic Petroleum Reserve when the Biden program is complete...
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 6,233,000 barrels per day last week, which was still 9.8% more than the 5,679,000 barrel per day average that we were importing over the same four-week period last year….this week’s crude oil production was reported to be 100,000 barrels per day lower at 11,600,000 barrels per day even though the EIA's rounded estimate of the output from wells in the lower 48 states was unchanged at 11,300,000 barrels per day, because Alaska’s oil production was 6,000 barrels per day lower at 449,000 barrels per day and thus subtracted 100,000 barrels per day from rounded national production total (by the EIA's math)...US crude oil production had reached a pre-pandemic high of 13,100,000 barrels per day during the week ending March 13th 2020, so this week’s reported oil production figure was 11.5% below that of our pre-pandemic production peak, but 37.6% above the interim low of 8,428,000 barrels per day that US oil production had fallen to during the last week of June of 2016...
US oil refineries were operating at 87.7% of their capacity while using those 15,497,000 barrels of crude per day during the week ending January 21st, down from a utilization rate of 88.1% the prior week, and lower than the historical utilization rate for mid-January refinery operations…the 15,497,000 barrels per day of oil that were refined this week were still 5.3% more barrels than the 14,721,000 barrels of crude that were being processed daily during the pandemic impacted week ending January 22nd of 2021, but 2.7% less than the 15,924,000 barrels of crude that were being processed daily during the week ending January 24th, 2020, when US refineries were operating at what was then also a below normal 87.2% of capacity...
With the increase in oil being refined this week, gasoline output from our refineries was again higher, increasing by 229,000 barrels per day to 8,917,000 barrels per day during the week ending January 21st, after our gasoline output had increased by 114,000 barrels per day over the prior week.…hence, this week’s gasoline production was 2.8% more than the 8,885,000 barrels of gasoline that were being produced daily over the same week of last year, but 2.4% less than the gasoline production of 9,158,000 barrels per day during the week ending January 24th, 2020.....at the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 28,000 barrels per day to 4,756,000 barrels per day, after our distillates output had decreased by 60,000 barrels per day over the prior week…after that modest increase, our distillates output was 5.2% more than the 4,518,000 barrels of distillates that were being produced daily during the week ending January 22nd of 2021, but 4.5% less than the 4,979,000 barrels of distillates that were being produced daily during the week ending January 24th, 2020...
With the increase in our gasoline production, our supplies of gasoline in storage at the end of the week rose for the seventh time in nine weeks, after falling each week over the preceding six weeks, increasing by 1,297,000 barrels to 247,918,000 barrels during the week ending January 21st, after our gasoline inventories had increased by a record 23,962,000 barrels over the prior three weeks...our gasoline supplies increased by less this week because the amount of gasoline supplied to US users increased by 281,000 barrels per day to 8,505,000 barrels per day, while our imports of gasoline fell by 77,000 barrels per day to a 87 week low of 314,000 barrels per day and while our exports of gasoline rose by 19,000 barrels per day to 412,000 barrels per day…after four straight big inventory increases, our gasoline supplies are now fractionally higher than last January 22nd's gasoline inventories of 240,748,000 barrels, but still about 2% below the five year average of our gasoline supplies for this time of the year…
the four week average of our gasoline demand fell by 302,000 barrels to a 44 week low of 8,202,000 barrels per day this week...while that's 6.1% higher than gasoline demand low of 7,729,000 barrels per day during the Covid surge of last January 22nd, it's down by 3.9% from the gasoline demand of 8,537,000 barrels per day on Jan 24th 2019, which was the low for that year...except for other pandemic impacted weeks when our demand tanked, our gasoline demand during the last 4 weeks was the lowest in 10 years....meanwhile, the gasoline inventory increase of 25,259,000 barrels over the past 4 weeks was the largest for any four week period on record since 1990, when gasoline inventories jumped by 26,643,000 in the period ending February 9th, handily exceeding the 4 week inventory increase of 23,952,000 barrels that we saw at the outset of the pandemic lockdowns from mid-March to mid April of 2020...
On the other hand, with the recent decreases in our distillates production, our supplies of distillate fuels decreased for the fifteenth time in twenty-two weeks, falling by 2,798,000 barrels to 125,154,000 barrels during the week ending January 21st, after our distillates supplies had decreased by 1,431,000 barrels during the prior week….our distillates supplies fell by more this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, rose by 198,000 barrels per day to 4,754,000 barrels per day, and as our imports of distillates fell by 80,000 barrels per day to 226,000 barrels per day, while our exports of distillates fell by 56,000 barrels per day to 627,000 barrels per day,....after twenty-eight inventory decreases over the past forty-two weeks, our distillate supplies at the end of the week were 23.1% below the 162,847,000 barrels of distillates that we had in storage on January 22nd of 2021, and about 17% below the five year average of distillates inventories for this time of the year…
Meanwhile, with the switch in unaccounted for crude from demand to supply and the withdrawal of crude from our Strategic Petroleum Reserve, our commercial supplies of crude oil in storage rose for the 9th time in 25 weeks and for the 18th time in the past year, increasing by 2,377,000 barrels over the week, from 413,813,000 barrels on January 14th to 416,190,000 barrels on January 21st, after our commercial crude supplies had increased by 515,000 barrels over the prior week…after this week’s increase, our commercial crude oil inventories remained about 8% below the most recent five-year average of crude oil supplies for this time of year, but were still about 31% above the average of our crude oil stocks after the third week of January over the 5 years at the beginning of the past decade, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels....since our crude oil inventories had jumped to record highs during the Covid lockdowns of spring 2020 and remained elevated for most of the year after that, our commercial crude oil supplies as of this January 21st were 12.7% less than the 476,653,000 barrels of oil we had in commercial storage on January 22nd of 2021, and are now 3.9% less than the 431,654,000 barrels of oil that we had in storage on January 24th of 2020, and also 6.7% less than the 445,944,000 barrels of oil we had in commercial storage on January 25th of 2019…
Finally, with our inventory of crude oil and our supplies of all products made from oil all near multi year lows, we are continuing to track the total of all U.S. Stocks of Crude Oil and Petroleum Products, including those in the SPR....the EIA's data shows that the total of our oil and oil product inventories, including those in the Strategic Petroleum Reserve and those held by the oil industry, and including everything from gasoline and jet fuel to propane/propylene and residual fuel oil, fell by 5,341,000 barrels this week, from 1,775,470,000 barrels on January 21st to 1,780,811,000 barrels on January 14th...that means our total supplies are now the lowest since June 13th, 2014, or at a seven and a half year low, which is somewhat amazing, in light of the near record increase in gasoline inventories..
This Week's Rig Count
The number of drilling rigs running in the US increased for the 60th time over the past 71 weeks during the week ending January 28th, but were still 23.1% below the prepandemic rig count....Baker Hughes reported that the total count of rotary rigs drilling in the US increased by six to 610 rigs this past week, which was also 226 more rigs than the pandemic hit 384 rigs that were in use as of the January 29th report of 2021, but was also still 1,319 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, a week before OPEC began to flood the global market with oil in an attempt to put US shale out of business….
The number of rigs drilling for oil was up by 4 to 495 oil rigs during this week, after they had decreased by 1 rig during the prior week, and there are now 200 more oil rigs active now than were running a year ago, even as they still amount to just 30.8% of the shale era high of 1609 rigs that were drilling for oil on October 10th, 2014….at the same time, the number of drilling rigs targeting natural gas bearing formations was up by 2 to 115 natural gas rigs, which was also up by 27 natural gas rigs from the 88 natural gas rigs that were drilling during the same week a year ago, but still only 7.2% of the modern high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008….also note that last year's rig count also included a rig that Baker Hughes had classified as "miscellaneous', while there are no such "miscellaneous' rigs deployed this week...
The Gulf of Mexico rig count was unchanged at 18 rigs this week, with seventeen of this week's Gulf rigs drilling for oil in Louisiana waters and another rig drilling for oil in Alaminos Canyon, offshore from Texas....that's still two more Gulf rigs than the 16 rigs that were active in the Gulf a year ago, when 15 Gulf rigs were drilling for oil offshore from Louisiana and one was deployed for oil in Texas waters…since there is not any drilling off our other coasts at this time, nor was there a year ago, the Gulf rig counts are equal to the national offshore totals for both years....
In addition to those rigs offshore, we also have 2 water based rigs drilling inland; one is a horizontal rig targeting oil at a depth of between 5000 and 10,000 feet, drilling from an inland body of water in Plaquemines Parish, Louisiana, near the mouth of the Mississippi, and the other is a directional rig drilling for oil at a depth of over 15,000 feet in the Galveston Bay area...however, the inland waters rig count of two is still down from the three inland waters rigs that were drilling a year ago..
The count of active horizontal drilling rigs was up by 9 to 553 horizontal rigs this week, which was also 209 more rigs than the 344 horizontal rigs that were in use in the US on January 29th of last year, but still 59.8% less than the record 1,374 horizontal rigs that were deployed on November 21st of 2014....on the other hand, the directional rig count was down by 1 to 36 directional rigs this week, but those were still up by 18 from the 18 directional rigs that were operating during the same week a year ago….at the same time, the vertical rig count was down by 2 rigs to 22 vertical rigs this week, while those were also down by 1 from the 22 vertical rigs that were in use on January 29th of 2021….
The details on this week’s changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes…the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of January 28th, the second column shows the change in the number of working rigs between last week’s count (January 21st) and this week’s (January 28th) count, the third column shows last week’s January 21st 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 29th of January, 2021...
this week we'll start by looking at the four rig increase in Texas drilling activity...checking the Rigs by State file at Baker Hughes for changes in Texas, we find that two rigs were added in Texas Oil District 8, which encompasses the core Permian Delaware, but that rigs in the other Permian districts were unchanged...since the national Permian rig count was only up by one, that two rig increase in the Texas Permian means that the rig that was pulled out in New Mexico had to have been drilling in the westernmost Permian Delaware...elsewhere in Texas, we find that two rigs were added in Texas Oil District 5, which accounts for the increase of 2 oil rigs in the Dallas/Ft Worth area Barnett shale...then, while we had a one rig increase in Oklahoma, there was an oil rig pulled out of the Ardmore Woodford, which means that two rigs must have been added elsewhere in Oklahoma, in a basin that Baker Hughes doesn't track...finally, to address the two rig increase in natural gas rigs, we find one of those was added in Pennsylvania's Marcellus shale, while the other was added in the Haynesville shale of northwestern Louisiana...
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Fitch Affirms Ascent Resources Utica Holdings' Long-Term IDR at 'B'; Outlook Stable - Fitch Ratings has affirmed Ascent Resources Utica Holdings, LLC's (Ascent) Issuer Default Rating (IDR) at 'B'. Fitch has also affirmed the first lien credit facility at 'BB'/'RR1', the second lien term loan at 'BB-'/'RR2' and the senior unsecured notes at 'B'/'RR4'. The Rating Outlook is Stable. Ascent's rating reflects expectations of positive FCF over the rating horizon, debt reduction, moderate leverage, above-average production scale and adequate hedge book. These factors are offset by a material maturity wall from 2024 to 2029 and relatively high firm transportation costs, which results in netbacks slightly lower than the median of its peers. Fitch believes Ascent is able to access debt capital markets and generate FCF to reduce refinancing risk, although acknowledges that natural gas prices are volatile and debt capital markets can be challenging at times. A positive rating action could occur if there are material actions taken to address the upcoming maturity wall.
Marcellus and Utica shales in the US expected to witness steady production growth until 2025 - As natural gas appraisal and development processes in the US’s Marcellus and Utica shales were largely unaffected by COVID-19, natural gas production at these sites is expected to rise at a compound annual growth rate (CAGR) of 5.1% to reach a combined 38.3 billion cubic feet per day by 2025, according to GlobalData, a leading data and analytics company.Svetlana Doh, Oil & Gas Analyst at GlobalData, comments: “Not only did natural gas appraisal and development evade some of the more devastating impacts COVD-19 had on other areas of the oil and gas industry, but natural gas production in these shales exceeded pre-pandemic levels in 2021, reaching 35 bcfd on an annual basis. In fact, Marcellus and Utica accounted for nearly one-third of the total natural gas production in the US. ”According to GlobalData’s latest report, ‘Marcellus and Utica Shales in the US, 2021 – Oil and Gas Shale Market Analysis and Outlook to 2025’, the Marcellus and Utica shale plays saw an increase in natural gas production in Q4 2020 and January 2021 before leveling out during Q1 and Q2, 2021. In July 2021, there was a slight increase to almost 29 billion cubic feet per day (bcfd).Doh continued: “In 2020, with the crash in oil prices, operators saw massive reductions in capital expenditures and headcounts. The US shale industry also witnessed record numbers of bankruptcies and debt restructurings. Operators continue to recover from this downturn. As a result, deal activity in the Marcellus and Utica shales is still below pre-pandemic levels.”The total merger and acquisition (M&A) deal value in these shales is up just 1% over 2020, and down approximately 5% from 2019 through three quarters.Doh added: “M&A activity in other crude oil plays in the US was mainly related to the consolidation tactic of bigger oil and gas companies holding assets across multiple plays. However, Appalachia is the biggest natural gas play in the US, and deals occur mainly for medium-to-small sized operators within a handful of gas plays in the country, resulting in a smaller total deal value.”Crude oil production in the Marcellus shale is expected to reach pre-pandemic levels in 2022 and increase further to 2025, while crude oil production in the Utica shale is unlikely to recover by 2025.
Living near or downwind of unconventional oil and gas development linked with increased risk of early death - Elderly people living near or downwind of unconventional oil and gas development (UOGD)—which involves extraction methods including directional (non-vertical) drilling and hydraulic fracturing, or fracking—are at higher risk of early death compared with elderly individuals who don't live near such operations, according to a large new study from Harvard T.H. Chan School of Public Health. The results suggest that airborne contaminants emitted by UOGD and transported downwind are contributing to increased mortality, the researchers wrote. The study will be published on January 27, 2022 inNature Energy. Our study is the first to link mortality to UOGD-related air pollutant exposures," "There is an urgent need to understand the causal link between living near or downwind of UOGD and adverse health effects." Roughly 17.6 million U.S. residents currently live within one kilometer of at least one active well. Compared with conventional oil and gas drilling, UOGD generally involves longer construction periods and larger well pads (the area occupied by equipment or facilities), and requires larger volumes of water, proppants (sand or other materials used to keep hydraulic fractures open), and chemicals during the fracking process. Prior studies have found connections between UOGD activities and increased human exposure to harmful substances in both air and water, as well as connections between UOGD exposure and adverse prenatal, respiratory, cardiovascular, and carcinogenic health outcomes. But little was known about whether exposure to UOGD was associated with mortality risk in the elderly, or about exactly how exposure to UOGD-related activities may be contributing to such risk. To learn more, the researchers studied a cohort of more than 15 million Medicare beneficiaries—people ages 65 and older—living in all major U.S. UOGD exploration regions from 2001 to 2015. They also gathered data from the records of more than 2.5 million oil and gas wells. For each Medicare beneficiary's ZIP code and year in the cohort, the researchers used two different statistical approaches to calculate what the exposure to pollutants would be from living either close to UOGD operations, downwind of them, or both, while adjusting for socioeconomic, environmental, and demographic factors. The closer to UOGD wells people lived, the greater their risk of premature mortality, the study found. Those who lived closest to wells had a statistically significant elevated mortality risk (2.5% higher) compared with those who didn't live close to wells. The study also found that people who lived near UOGD wells as well as downwind of them were at higher risk of premature death than those living upwind, when both groups were compared with people who were unexposed. "Our findings suggest the importance of considering the potential health dangers of situating UOGD near or upwind of people's homes,"
For the First Time, a Harvard Study Links Air Pollution From Fracking to Early Deaths Among Nearby Residents - Western Pennsylvania residents and doctors have been going public for several years with their concerns that fracking for fossil gas has sickened people and may be causing rare cancers in children. Today, a new study out of Harvard links fracking with early deaths of senior citizens. Published in the peer reviewed scientific journal Nature Energy, the team of researchers from the Harvard T.H. Chan School of Public Health blames a mix of airborne contaminants associated with what is known as unconventional oil and gas development. That is when companies use horizontal drilling and liquids under pressure to fracture underground rock to release the fossil fuels through a process known as hydraulic fracturing, or fracking. The closer people 65 and older lived to wells, the greater their risk of premature mortality, the study found. Those senior citizens who lived closest to wells had an early death risk 2.5 percent higher than people who did not live close to the wells, the researchers found. The study also found that seniors who lived downwind of wells were at a similar higher risk of premature death than those living upwind, when compared with people who were unexposed. In their paper, researchers did not estimate the total number of premature deaths nor the length of time lives were shortened. Still, the authors said it’s the first study to link mortality among those 65 and older with air pollution from fracking wells. “Our findings suggest the importance of considering the potential health dangers of situating (unconventional oil and gas development) near or upwind of people’s homes,” said Longxiang Li, a postdoctoral fellow in the school’s Department of Environmental Health and lead author of the study. The researchers wrote that a variety of activities can cause air pollution around oil and gas wells resulting in increased exposure to volatile organic compounds, nitrogen oxides and naturally occurring radiation. Those activities can include pad construction, well drilling, hydraulic fracturing and fossil fuel production. Diesel trucks and equipment used to build the drilling pads and to force the fracking fluids deep into the ground also emit pollutants. Pollutants can be released directly from wellheads and from the burning of unwanted fossil fuels, a process known as flaring. The Environmental Protection Agency says the industry’s release of volatile organic compounds is a major contributor to the formation of ground-level ozone, or smog, which is linked to aggravated asthma, increased emergency room visits and hospital admissions, and premature death.
People Over Pipelines: Canvassing Communities on the Falcon Ethane Pipeline -During November I joined members of the Beaver County Marcellus Awareness Community (BCMAC) in Allegheny and Beaver counties in Southwestern Pennsylvania to canvass residents living near the Falcon Ethane Pipeline. The Falcon Pipeline is a 98-mile pipeline network through Pennsylvania, Ohio, and West Virginia that, if brought online, will transport ethane to the Shell Ethane Cracker in Monaca, Pennsylvania to be made into plastic. While the pipeline is fully constructed, residents and the concerned public just learned in November via a Facebook post that the pipeline is now filled with ethane. The pipeline has been under investigation since 2019 by federal and state agencies, and a coalition of groups under the People Over Petro Coalition have been working to increase transparency and have safety concerns addressed by regulators before the pipeline comes online. The only indication of the pipeline were innocuous orange markers traveling behind houses and visible off the side of the road. The majority of residents we spoke to had no idea they were living so close to an ethane pipeline. Many of the people living just across the street from the pipeline had just moved in within the past few months. Canvassing the houses felt like shattering the perfect lives these families were starting to build. People we spoke to told us this was the cleanest air they had ever breathed despite being able to see a fracking flare from the top of the street. The house they had just moved into was a dream house they had saved years for. One person we spoke to had no idea about the Falcon Pipeline but grew visibly agitated when we told him it was an ethane pipeline, like the Revolution pipeline in Beaver County less than 15 miles away that explodedin early morning in 2018. The pipeline had been in service for just one week before exploding – destroying a building, killing animals, forcing dozens of residents to evacuate, and leaving 1,500 without power. Despite this history of pipeline incidents in the area, none of the residents we spoke to remembered receiving safety information on the pipeline from Shell Pennsylvania Chemicals. Residents deserve to know the safety risks and the implications of living near an ethane pipeline that crosses through backyards and underneath residential roads. They also deserve to know what safety measures have been put in place by the corporation and local EMS and how to evacuate in the event of an emergency. If you live near the Falcon pipeline and would like to get involved with efforts to get more transparency and safety information on the pipeline please email anaïs at apeterson@earthworksaction.org. If you are a local resident and would like to speak to an attorney regarding issues causes by pipeline construction you can contact the attorney at Mountain Watershed Association at: (724) 455-4200 ext. 7 or melissa@mtwatershed.com
Despite moratorium, 2 million gallons of conventional oil and gas waste spread on Pa. roads since 2018 - Conventional oil and gas producers have spread millions of gallons of drilling waste on Pennsylvania roads in the last few years, despite a 2018 moratorium on the practice. For years, companies have spread oil and gas waste on roads to suppress dust and melt ice. But in 2016, the state blocked the practice for waste from Marcellus shale wells. In 2018, it also prohibited the spreading of waste from conventional oil and gas wells, which typically tap shallower rock formations. The decision resulted in a 90 percent drop on the amount of conventional waste, or brine, spread on roads, said Karen Feridun of the non-profit Better Path Coalition, which produced a report on the topic. Still, Feridun says, companies have disposed of over 2 million gallons of conventional drilling waste on Pennsylvania roads since 2018. “What really are the distinctions between conventional and unconventional (waste)?” Feridun said. “If you are going to take that step of banning unconventional, why not both?” Both conventional and unconventional drilling waste contain salts, metals, and naturally-occurring radioactive materials. Most conventional waste is disposed of at treatment facilities or injection disposal wells. But companies are still disposing of some of their waste through road spreading.They are using a loophole in state law called “coproduct determination,” which allows for companies to replace a commercially-available product with industrial waste as long as using that waste does not “present a greater threat of harm to human health and the environment” than the product it’s replacing. As part of this process, companies are required to evaluate “total levels of hazardous or toxic constituents” in their waste. Earlier this year, the DEP asked 17 companies that had reported road spreading for additional information on these activities. Their responses showed the companies had tested their waste for salts and other minerals. But Feridun, who reviewed these submissions to the DEP obtained through Right-to-Know requests, says the companies aren’t testing the waste for radioactivity and other contaminants. “There are just all sorts of substances and chemicals that are in the waste that are extremely dangerous and are going to have long lasting effects,” Feridun said. The DEP says it’s reviewing the responses and has asked the companies for more information. Conventional drilling companies argue road spreading in Pennsylvania is one of the few remaining disposal methods for small companies. “The alternatives to produced water disposal in Pennsylvania continue to shrink,” said Burt Waite, an independent geologist and member of the DEP’s Pennsylvania Grade Crude Development Advisory Council, at a council hearing Thursday. “At the same time, we’re receiving calls from townships crying for the (waste)water, as it is effective to controlling dust and stabilizing roads.”
We Found The Names of Radioactive Waste Locations That Government Kept Secret - Public Herald -- For about six years, the Pennsylvania Department of Environmental Protection (DEP) has obscured the radioactive hazards of oil and gas operations. Ever since the 2016 release of its study on oil and gas TENORM — technologically enhanced naturally occurring radioactive material — the DEP has kept the names and locations of where radioactive waste was detected a secret and told the general public there was little to worry about. The question is, does the radium in the raw data tell a different story? When the Department chose not to release the names of the 144 locations tested in the 2016 study, it blocked the public’s ability to make place-based, local decisions about potential threats from TENORM. Now, for the first time, all 144 names and locations are being released by the team at Public Herald. We’ve mapped the landfills, centralized waste treatment facilities, publicly owned treatment works, zero-liquid discharge facilities, brine-treated roads, well pads and their test results for radium from the DEP’s study.For Public Herald’s analysis, we focus on radium (Ra-226 & Ra-228) because it is federally regulated for its health impacts, highly soluble in water and a lead indicator of TENORM contamination. The DEP’s TENORM analysis tested the following elements: U-235, U-238, Ra-226, Ra-228, Th-232, Ac-228, Pb-212, Bi-212, and K-40.Using the TENORM study interactive map, the public can finally see the locations Pennsylvania officials withheld. Knowing the location of specific radium results from the DEP’s TENORM study is critical to evaluating the health impacts of oil and gas radioactivity in studies like the one currently underway by the University of Pittsburgh Medical Center (UPMC). View Map in Separate Window » Public Herald’s Pennsylvania TENORM map provides the premier interface with which to visually review the radium data from the DEP’s TENORM study. Our team organized all 144 locations tested into six categories, each represented by a unique icon on the map.When hovered over, icons on the map (corresponding to the legend) will provide the name of that facility and a sample of that specific facility’s radium data.The layers button in the top left of the map window allows the user to add an overlay of Pennsylvania’s watersheds, which are shared with neighboring states and communities downstream.
500 gallons of oil spill at Bethlehem terminal — A state crew was sent to clean up a 500-gallon oil spill Tuesday at the Citgo on River Road, officials said. A technical malfunction caused the leak from a containment area at the gas station, state officials said. The containment area's vapor recovery system, which removes vapors from crude oil, malfunctioned, causing the spill. The Department of Environmental Conservation said vapor recovery was isolated and that a vac truck was on scene cleaning up the spill. Snow and gravel contaminated by the oil will also be removed, the DEC said. The cleanup and area will be monitored by the DEC for threats to public health and the environment, but there were no detected impacts as of Tuesday evening. Fire departments from Selkirk, Elsmere and Delmar joined the DEC and the Bethlehem Police Department.
State expects $90 million in additional Impact Fee funds - The cold weather Bradford County has been experiencing has highlighted to consumers the rising price of heating oil and natural gas, but they will also see a silver lining to that price increase, Pennsylvania municipalities are likely to see an increase in Impact Fee payments.Originally signed into law in 2012, the impact fee bill known as Act 13 established a system of payment from natural gas producers to the state and local governments affected by drilling and exploration. Most major natural gas producing states use a traditional severance tax, not the Impact Fee system. The amount paid is determined by the amount of active wells in a given area and is influenced by the price of natural gas on the national market. The rise of natural gas prices fro February to October of 2021 is expected to increase the amount disbursed by $10,000 per horizontal well, totaling close to $90 million in additional funds throughout the state, according to state officials.
Chesapeake Builds Natural Gas-Rich Marcellus Portfolio with Chief, Tug Hill Purchase - Chesapeake Energy Corp. on Tuesday snapped up a batch of natural gas-rich Marcellus Shale assets with a $2 billion-plus takeover of Chief E&D Holdings LP and affiliates of Tug Hill Inc. According to the Oklahoma City-based independent, pro forma natural production capacity could increase by up to 200 MMcf/d. The transaction, set for completion by the end of March, also may expand undeveloped locations by around 25% and expand the drilling inventory by more than 15 years at current activity levels. Chesapeake agreed to pay a total of $2 billion cash and trade 9.44 million shares. The company was trading above $61.00/share early Tuesday. To help pay for the transaction, the Powder River Basin (PRB) portfolio in Wyoming is being sold to Continental Resources Inc. for $450 million. These “transformative transactions…meet the high bar set by our acquisition nonnegotiables and clarify our portfolio,” CEO Nick Dell’Osso said. “We know the importance of scale, and the Chief and Tug Hill assets fit like a glove with our existing position in the Northeast Marcellus Shale. Once the transactions are completed, Chesapeake would be a three-basin producer, with assets in the Eagle Ford, Haynesville and Marcellus shales. Under the terms of the agreements, unanimously approved by all the principals, Chesapeake is acquiring 113,000 net acres that are more than 90% held by production. Assuming the deal closes by April 1, the assets are projected to produce 835 MMcf/d net for nine months in 2022. The company’s Powder River Basin assets include 172,000 net acres and 350 operated wells in southeastern Wyoming. In the final three months of 2021, volumes averaged around 19,000 boe/d, 58% weighted to oil and liquids. After the transactions are completed, Chesapeake this year plans to add another two rigs on the acquired Marcellus properties. That would result in up to 11 gas-focused and up to three oil-focused rigs working the Marcellus. For Continental, the transaction expands its PRB inventory. The fellow Oklahoma City-based independent last November also entered the Permian Basin.
Old-school shale: The growth of Diversified Energy Co. in southwestern Pennsylvania - Diversified Energy Co. may not drill wells like EQT Corp. and CNX Resources Corp., but the Birmingham, Alabama-based company, is now the largest conventional shale producer in Appalachia, pumping oil and gas out of a myriad of wells dotting the landscape, taking on the type of well that doesn't shine on Wall Street. It has grown to become the fifth-largest shale gas driller in southwestern Pennsylvania, with 327 active local wells. When Diversified Energy first made its mark in the Appalachian basin in 2017, it was by buying hundreds and even thousands of the type of old-school, conventional wells that had long since been surpassed with investment and attention by the deeper, harder-to-get-to and more expensive horizontal wells that tapped into the Marcellus and Utica shales.The company, which was founded by West Virginia native Rusty Hutson, had a contrarian view of success in the Appalachian shale industry. Billions of dollars had by this time flowed to the region to search for and then drill the deep wells in Pennsylvania, West Virginia and Ohio. Fortunes had been made and, in some cases, crushed. But the oil and gas industry is a longstanding business in Appalachia, and Hutson believed that assembling a stable of old-school wells would create a fast-growing business even if it isn't as high-flying as unconventional shale.The strategy has worked. Diversified went from one employee and $400,000 in enterprise value with almost no production to 800,000 acres, 3 million barrels of oil equivalent and $75 million in enterprise value by the time it went public on the London Stock Exchange in 2017. It had, by that time, picked up some conventional oil and gas wells being sold off by Seneca Resources and Eclipse Resources.In the five years since, Diversified has made $2 billion in acquisitions with some of the country's biggest names, picking up more mostly conventional oil and gas wells from CNX, EQT, Dominion Energy, EdgeMarc Energy and Titan Energy, among others.Its revenue has grown from $41.8 million in 2017 to $408.7 million in 2020, and it now has 7.3 million acres under leasehold in Appalachia, many of them the conventional wells that have long since stopped the prolific gush of oil and/or gas but provide a steady flow that, when gathered all together, produce at scale. At the same time, Diversified has also picked up an increasing number of unconventional wells that fit the same profile: Wells from earlier days of shale development over the past decade that companies like Atlas, Titan and CNX drilled and connected to pipelines but that don't have the high production anymore that makes it worthwhile to keep in inventory.
CNX Resources Raising Capex, Sees Costs Tick Upward in Appalachia on Inflationary Pressures - A jump in forecasted natural gas production, along with inflationary pressures, will find CNX Resources Corp. spending more this year to execute a long-term plan that remains on track after the company turned in a solid 2021. Management said operating efficiencies have improved markedly over the last two years across its assets in the Appalachian Basin. As a result, the company is moving forward with a seven-year plan outlined in 2020 with a new base production level of 590 Bcfe instead of the previous 560 Bcfe. “The one rig, one fracture crew that we used to use to run a maintenance and production plan now grows production without adding any new crews,” said CFO Donald Rush during a call on Thursday to discuss year-end results with financial analysts. “…Our old plan was based in a different world from low gas prices to different efficiencies.” The one rig program is expected to give the company low, single-digit production growth. CNX is guiding for production of 575-605 Bcfe this year and capital expenditures (capex) of $470-500 million. Capex guidance was above the $470 million range the company forecasted for 2021. COO Chad Griffith said capex is expected to come in higher because of inflation, as well as plans for water and other midstream infrastructure to support operations. CNX produced 158.2 Bcfe in the fourth quarter, up from 146.5 Bcfe in the year-ago period. Most of its activity occurred in Southwest Pennsylvania during the period. For the full year, the company reported production of 590.2 Bcfe, up from 511 Bcfe in 2020. The average price of natural gas, natural gas liquids and oil, including cash settlements, was $2.83/Mcfe during the fourth quarter, up from $2.49 in the year-ago period. CNX reported fourth quarter net income of $630.3 million ($3.02/share), compared with $195.8 million (88 cents) in the year-ago period. The company reported a 2021 net loss of $498.6 million (minus $2.31), compared with a 2020 net loss of $428.7 million (minus $2.43). The independent was lifted by higher commodity prices across the board, reporting its eighth consecutive quarter of free cash flow (FCF) at $158 million. CNX used 80% of its cash flow to buy back shares, with the remainder used for paying down debt. CNX took a big loss on its hedge book during 3Q2021 that weighed down full-year results, but management said Thursday it has no plans to change its approach. The company currently has about 86% of its 2022 production hedged, the bulk of which is locked in at average prices of $2.94/MMBtu.
ESG-Critical Shale CEO Feels An Ethical Duty To Speak Out - Nick Deluliis, CEO of CNX Resources, is all over Twitter and other social media platforms, advocating for his company and his industry. I asked him why he has chosen to become such a vocal advocate, given that it will inevitably make him a target to so many who oppose fossil fuels in any form. “I feel there’s an ethical duty, a leadership responsibility, there’s a social purpose of a business to accurately, rationally advocate for what you do on behalf of society and why what you do is not in the past, it’s not a bridge that’s going to go away; it’s the present and it’s the future. Particularly when mistruths are used to vilify what you do.” he answered. “When you think about what’s behind that, the domestic energy industry doesn’t produce a widget of methane: What it does is provide quality of life. “That’s what we do as an industry. It’s not that complicated.” “We got really good in the ‘70s and ‘80s at liberating methane from coal seams,” Deluliis told me when we talked recently, “to the point where towards the end of the ‘80s we said what if instead of venting the methane into the atmosphere or flaring it, why not collect it and process it? That’s really the genesis of how we got into the natural gas business.” Today, it is one of the largest natural gas producers in the Marcellus/Utica region, with the bulk of its assets still centered in Western Pennsylvania, southwest Virginia and West Virginia. Deluliis has gained a reputation over the last year for his willingness to be an outspoken advocate for his company and industry, one who hasn’t been shy about being critical of the ESG investor movement that has become so successful in influencing the management philosophies at many energy companies in recent years. I noted that the strategy Deluliis deploys at CNX seems pretty consistent with the Governance-related objectives advocated by these ESG investors, but he disagreed. On ESG investors and what they’ve been able to achieve, Deluliis is not entirely negative. But he sees the results of the influence they wield not just in energy, but across society as a whole, in what he calls a breakdown between “the good, the bad and the ugly.” “On the good side of this - and we’ve been a proof point for it - if you look at any industry that is in manufacturing or energy, anything that requires the interaction of humans with some process or some activity, the safest, the most compliant, they’re the most efficient. The most efficient – in the case of widgets or methane molecules or whatever it is – they’re going to be the most profitable. I am all on board with this,” he told me. “The bad side is when you start getting these different constituent groups to try to put some sort of quick and easy filter on how to come up with either an ESG fund, or to screen companies with a filter for the ESG metrics. This is tremendously hard work. You have to intimately understand the industry. The data are not going to lend themselves to a quick and easy screening on an Excel spreadsheet from an office in California or Manhattan.
US Court Vacates Federal Permit for Mountain Valley Natgas Pipeline - The U.S. Court of Appeals for the 4th Circuit on Jan. 25 invalidated federal approvals for Equitrans Midstream Corp.’s $6.2 billion Mountain Valley natural gas pipeline under construction from West Virginia to Virginia. The court decision was the latest setback for the pipeline, which was already years behind schedule and billions over budget. When Mountain Valley construction started in February 2018, Equitrans Midstream estimated the 303-mile (488-km), 2 Bcf/d project would cost about $3.5 billion and enter service by late 2018. Specifically, the court vacated the record of decisions of the U.S. Forest Service and the Bureau of Land Management allowing the pipe to cross about 3.5-miles (5.6-km) through the Jefferson National Forest, and sent the case back to the agencies. In an email, Equitrans said, “We are thoroughly reviewing the Court’s decision regarding [Mountain Valley’s] crossing permit for the Jefferson National Forest and will be expeditiously evaluating the project’s next steps and timing considerations.” In the past, Equitrans has said it expected the project to enter service during the summer of 2022. Mountain Valley is one of several U.S. pipelines delayed by regulatory and legal fights with environmental and local groups that found problems with federal permits issued during President Donald Trump's administration. When Mountain Valley construction started in February 2018, Equitrans estimated the 303-mile (488-km), 2 Bcf/d project would cost about $3.5 billion and enter service by late 2018. “Today’s decision makes it highly unlikely that this dirty, dangerous, and unnecessary fracked gas pipeline will ever be completed,” said Kelly Sheehan, senior director of energy campaigns at the Sierra Club, which along with other environmental groups filed the latest lawsuit. Equitrans, which has a roughly 47.8% ownership interest in Mountain Valley and will operate the pipe, said it has funded about $2.4 billion of the project as of Sept. 30.
Federal court again yanks two Mountain Valley Pipeline approvals - A federal appeals court has again rejected permits issued by the U.S. Forest Service and the Bureau of Land Management allowing Mountain Valley Pipeline to cross three and a half miles and four streams in the Jefferson National Forest in Virginia and West Virginia. In its ruling issued Tuesday, the Richmond-based Fourth Circuit Court of Appeals concluded that the federal agencies “inadequately considered the actual sedimentation and erosion impacts” of the pipeline, “prematurely authorized” the use of a stream-crossing method and “failed to comply” with a Forest Service rule governing forest management. Mountain Valley Pipeline spokesperson Natalie Cox in an email said the developers “are thoroughly reviewing” the decision “and will be expeditiously evaluating the project’s next steps and timing considerations.” Delays related to permitting and legal challenges have repeatedly pushed back the pipeline’s completion date and increased its budget. While the project’s backers initially projected it would be completed in 2018 at a cost of $3.7 billion, Mountain Valley most recently announced it expected to finish the 300-mile pipeline by summer 2022, with an overall price tag of $6.2 billion. This is the second time the Fourth Circuit has rejected permits from the Forest Service and BLM for the national forest crossing. In July 2018, the court vacated the approvals largely over concerns with how the agencies had reviewed sedimentation impacts. Subsequently the agencies prepared supplemental environmental reviews and in January issued a second round of approvals for Mountain Valley Pipeline. A coalition of environmental groups including the Sierra Club, Wild Virginia and Appalachian Voices, many of whom were involved in the first round of litigation, immediately sued again. The Fourth Circuit on Tuesday accepted many of the petitioners’ arguments that the Forest Service and Bureau of Land Management had failed to meet federal environmental requirements and “inadequately” considered the project’s erosion and sediment impacts. “The Forest Service and the BLM erroneously failed to account for real-world data suggesting increased sedimentation along the pipeline route,” the court concluded. In particular, the judges noted that the agencies’ environmental analyses had not included water quality data from U.S. Geological Survey monitoring stations 15 miles from the Jefferson National Forest that showed sedimentation downstream of the pipeline far exceeded predictions for the Roanoke River put forward in Mountain Valley Pipeline’s hydrologic analyses. The court also agreed with the environmental groups that the agencies’ decision to allow the pipeline to use conventional boring to cross four streams within Jefferson National Forest was “premature” because an assessment of the method’s environmental impacts by the Federal Energy Regulatory Commission hasn’t yet been released.
MVP Dealt Yet Another Blow by Fourth Circuit as Reissued Forest Permits Vacated - Dealing a blow to Mountain Valley Pipeline LLC’s expectations for a timely conclusion to the drawn-out regulatory saga, a federal court has once again struck down crucial permitting for the natural gas conduit’s crossing of the Jefferson National Forest. The U.S. Court of Appeals for the Fourth Circuit on Tuesday vacated and remanded key authorizations issued to MVP by the U.S. Forest Service and the Bureau of Land Management (BLM) to enable the 303-mile, 2 million Dth/d pipeline to cross a 3.5-mile stretch of national forest land along the Virginia and West Virginia border. Partly siding with a coalition of environmental groups challenging the project, the Fourth Circuit found that the federal agencies erred by failing to account for data showing the erosion impacts of the project and by “prematurely” authorizing the conventional bore method for four stream crossings within the national forest. The agencies also failed to comply with a 2012 forest planning rule, the court found. In an order explaining the court’s decision, Circuit Judge Stephanie Thacker criticized the agencies for not considering water quality monitoring data from the U.S. Geological Survey (USGS) showing impacts of the pipeline’s construction 15 miles outside of the Jefferson National Forest. “The USGS data showed water turbidity values that were 20% higher downstream from the pipeline’s construction than upstream — a significant difference from the 2.1% increase in sedimentation the hydrologic analyses predicted for the Roanoke River,” Thacker wrote. As for the stream crossings, the agencies should have waited for FERC to complete an environmental analysis of MVP’s plans to switch to a conventional bore method for stream crossings, according to the court. Even though the Federal Energy Regulatory Commission approved “the use of the conventional bore method for the stream crossings inside the Jefferson National Forest, the Forest Service and the BLM, in deciding whether to approve the pipeline’s route over those lands, would surely benefit from FERC’s environmental analysis of the use of the conventional bore method for other stream crossings outside the Jefferson National Forest,” Thacker wrote. “As a result, the Forest Service and the BLM improperly approved the use of the conventional bore method for the four streams in the Jefferson National Forest without first considering FERC’s analysis.” The latest court action marks the second time that the Fourth Circuit has struck down MVP’s federal permitting for its planned route through national forest lands. The previous approvals were vacated in July 2018. Revised permitting was issued after the Forest Service concluded a supplemental environmental review in late 2020. Analysts characterized the latest Fourth Circuit ruling as a clear setback for MVP, which first received its FERC certificate in 2017 but has been dogged by legal and regulatory setbacks that have dragged out the construction process. “In our view, these permits needed to be upheld on appeal in order for MVP to complete construction as planned,” analysts at ClearView Energy Partners LLC told clients. “That now appears off the table given the need for the agencies to revisit the evidence presented by petitioners in a more substantive fashion.” Similarly, Wood Mackenzie analyst Colette Breshears estimated that the start of service would likely slip to 2023 on the latest developments.
Mountain Valley Pipeline’s Up-And-Down Legal Journey: Explained - For about seven years, the Mountain Valley Pipeline project has forged through a raft of legal challenges and regulatory hurdles that ultimately doomed several other projects in the region. The $6.2 billion, 304-mile natural gas pipeline system would span from northwestern West Virginia to southern Virginia. The line is more than 90% constructed, according to pipeline developers, with an aim of transporting Appalachian shale gas to the eastern U.S.—a cherished goal for the gas industry. EQM Midstream Partners would operate the pipeline, and it owns a significant interest in the project. But the latest legal blow arrived Tuesday. The U.S. Court of Appeals for the Fourth Circuit tossed the federal government’s approval of the project’s three-and-a-half-mile route through Jefferson National Forest. The Mountain Valley Pipeline was designed to carry 2 billion cubic feet of natural gas a day, alleviating a natural gas glut created by the hydraulic fracturing drilling boom. The drilling technique unlocked gas reserves trapped by shale rock formations underlying Appalachia. In the past decade, major pipeline projects sprung up to move gas drilled in states like Pennsylvania, West Virginia, and Ohio to places like New England, the Mid-Atlantic, and the South, said Victor B. Flatt, a George Washington University visiting professor who studies energy and environmental law. U.S. utilities’ shift from burning coal to natural gas—and growing export opportunities to Europe, Asia, and the Caribbean—fed the rush. Mountain Valley’s “ability to lock in contracts with several shippers who stand by the pipeline even through its legal challenges confirms the utility and consumer interest,” said Felix Mormann, a professor at Texas A&M University School of Law. The Mountain Valley project, if it succeeds, would be a major win for the industry as other regional gas pipelines have succumbed to rising local opposition and political pressure. Among projects canceled since 2020: The 116-mile PennEast Pipeline from Pennsylvania to New Jersey; the 600-mile Atlantic Coast pipeline from West Virginia across Virginia and into North Carolina; and the 121-mile Constitution pipeline, which would have traveled from northeast Pennsylvania to central New York. Environmental groups sued to block the PennEast Pipeline, Atlantic Coast Pipeline, and other canceled projects. Their opposition to the Mountain Valley Pipeline is just as vigorous, according to Carolyn Elefant, an attorney with her own energy practice who started her career at the Federal Energy Regulatory Commission. The Sierra Club, Appalachian Voices, and Wild Virginia say the project isn’t needed, and they want the D.C. Circuit to overturn FERC’s orders allowing construction to proceed. Groups led by Appalachian Voices also want the Fourth Circuit to reject the Fish and Wildlife Service’s finding that the project wouldn’t jeopardize protected species. West Virginia and Virginia recently approved water permits for the project, which prompted more lawsuits. The Sierra Club has received funding from Bloomberg Philanthropies, the charitable organization founded by Michael Bloomberg. Bloomberg Law is operated by entities controlled by Michael Bloomberg. One of the differences between the Mountain Valley Pipeline and the PennEast, Constitution, and Atlantic Coast pipelines is that the canceled projects faced strong opposition from states, Elefant said. VIDEO: We look at the series of high profile legal setbacks that has some in the industry asking—is it still possible to build pipelines in America? Environmental groups didn’t need state opposition to secure a win in their challenge to a three-and-a-half-mile pipeline route through a national forest in Virginia and West Virginia. The Bureau of Land Management and Forest Service didn’t consider sedimentation and erosion impacts, prematurely approved the use of a conventional bore method to build stream crossings, and failed to comply with a forest planning rule, the court said. The agencies must now consider the forest crossing plan for a third time. The first two reviews were completed under the Trump administration, but this is the first time the Biden administration will take a look.
Comstock Says Proved Natural Gas Reserves Climb 9% in 2021; Output Up Alongside Prices - Buoyed by solid demand and strong prices, Comstock Resources Inc. said it ramped up activity in the Haynesville Shale and grew its proved reserves of primarily natural gas by 9% in 2021. The Frisco, TX-based independent estimated reserves of 6.12 Tcfe at the close of last year, up from 5.63 Tcfe a year earlier. Of those reserves, 37% were developed and 98% were company operated, it said. Natural gas accounted for about 98% of the total reserves. The producer is focused on developing the Haynesville in North Louisiana and East Texas. Comstock said it spent $628.2 million in 2021 to drill 100 horizontal shale wells and to put 95 wells on production. The company also invested $21.8 million to acquire proved oil and gas properties and $35.9 million to acquire unproved leases in 2021. Comstock said it produced 489.3 billion Bcf of natural gas in 2021, up from 450.8 Bcf in 2020. In the fourth quarter of 2021, production averaged 1.3 Bcfe/d of natural gas, up 12% from a year earlier. The company contributed to a broader industry increase in 2021 as producers increased activity alongside Henry Hub prices, which advanced more than 40% during the year. The U.S. Energy Information Administration (EIA) said production of dry natural gas averaged an estimated 93.5 Bcf/d in 2021, up 2.0 Bcf/d from 2020. It topped 96 Bcf at points late last year. EIA forecast average production will increase by 2.5 Bcf/d in 2022. . Growth is expected to be “led by the Haynesville region, where production tends to be sensitive to change in U.S. benchmark Henry Hub natural gas prices, and by the Permian Basin, where production tends to be more sensitive to oil prices,” EIA researchers said, noting that benchmark crude prices recently touched multi-year highs. “In 2023, we expect dry natural gas production to increase by 1.5 Bcf/d to reach 97.6 Bcf/d.” Comstock’s growth in the fourth quarter built on gains in the third quarter, when its total production climbed 25% year/year. After posting those results, CEO Jay Allison in November vowed to accelerate drilling in the Haynesville.
U.S. natgas futures edge up on soaring European prices — U.S. natural gas futures edged up on Monday as output remains slow to recover from well freeze-offs earlier in January, along with forecasts for more cold and heating demand this week than previously expected and a 16% jump in European gas futures. European gas futures soared on concerns that Russia will invade the Ukraine and cut off supplies of gas to the rest of Europe. Traders said demand for U.S. liquefied natural gas (LNG) will remain strong so long as global prices keep trading well above U.S. futures. Global prices were currently about seven times over U.S. futures as utilities around the world scramble for LNG cargoes to replenish low stockpiles in Europe and meet surging demand in Asia. Front-month gas futures () for February delivery rose 2.8 cents, or 0.7%, to settle at $4.027 per million British thermal units (mmBtu). Futures for the spring and summer months were up more than the front-month, which will expire later this week. U.S. speculators last week boosted their net long futures and options positions on the New York Mercantile and Intercontinental Exchanges for a second week in a row with gas demand expected to have reached a record high on Jan. 21, according to the U.S. Commodity Futures Trading Commission's Commitments of Traders report. During that February freeze, next-day gas jumped to record highs in several parts of the country - gaining over 1,100% on Feb. 12 at the Waha hub (NG-WAH-WTX-SNL) in West Texas - as a winter storm left millions without power and heat for days after freezing gas wells and pipes in Texas and other U.S. central states. Data provider Refinitiv said output in the U.S. Lower 48 states had averaged 94.3 billion cubic feet per day (bcfd) so far in January, down from a record 97.6 bcfd in December. Production rose a bit over the weekend from the lows seen last week. With less cold weather forecast, Refinitiv projected average U.S. gas demand, including exports, would drop from 143.2 bcfd this week to 133.9 next week. On a daily basis, Refinitiv said total U.S. gas demand plus exports hit a preliminary 155.8 bcfd on Jan. 21, which would top the current record of 150.6 bcfd on Jan. 30, 2019. The amount of gas flowing to U.S. LNG export plants has averaged 12.5 bcfd so far this month, which would top December's monthly record of 12.2 bcfd.
US gas production drop persists, tightening supply and increasing call on storage | S&P Global Platts - Following a precipitous drop in US natural gas production earlier this month, output has continued to stumble in late January, tightening the domestic market balance just as colder weather arrives. With gas-fired heating demand hitting seasonal highs recently, increased reliance on gas storage could pose renewed upside risk for 2022 forwards prices. After approaching a prior record high at over 96.3 Bcf/d in late December, US gas production has tumbled since the start of the new year, falling by over 4 Bcf/d to average just 92.2 Bcf/d in January. With output sputtering in the mid-91 Bcf/d range over the past week, US supply has tightened significantly since late December just as temperatures and demand hit levels unseen since last winter, data from S&P Global Platts Analytics shows. In January, population-weighted temperatures across the US Northeast and Midwest – both key heating-demand regions – have dipped into the teens and even the single-digits Fahrenheit. US residential-commercial gas demand has spiked in response, averaging about 51.8 Bcf/d month to date – about 6.9 Bcf/d, or more than 15%, higher compared with the year-ago average. Over the next week, heating demand is expected to continue outperforming, averaging nearly 54.9 Bcf/d with the potential for a new winter-season high at over 62 Bcf/d on Jan. 26, forecast data shows. Tighter supply and strong demand have increased the call on gas storage recently – a trend that appears likely to continue into early February with the potential to significantly reduce inventory levels. In the two storage reporting weeks ended Jan. 13, the US gas industry pulled an estimated 385 Bcf from inventory, outpacing the prior five-year average drawdown by some 63 Bcf, data from the US Energy Information Administration shows. Over the coming three reporting weeks, that trend is expected to continue, according to an updated forecast from Platts Analytics. For the reporting weeks ending Jan. 21, Jan. 28 and Feb. 4, currently projected drawdowns of 210 Bcf, 263 Bcf and 198 Bcf, respectively, would outpace the historical average by a collective 210 Bcf in total. If realized, the withdraws would cut stocks to 2.14 Tcf by early February and the leave the US gas market with a 177 Bcf storage deficit. Even assuming subsequent, average storage drawdowns over the balance of winter, the US gas market would enter the coming injection season with less than 1.5 Tcf in the ground – the lowest winter-ending inventory level since late March 2019, when the US market entered injection season with just 1.1 Tcf.
U.S. natgas futures jump near 6% to 1-wk high on cold forecasts -- U.S. natural gas futures jumped almost 6% to a one-week high on Wednesday on forecasts confirming prior outlooks that the weather will remain colder-than-normal through mid-February. On its second to last day as the front month, gas futures NGc1 for February delivery rose 22.4 cents, or 5.5%, to settle at $4.277 per million British thermal units (mmBtu), their highest close since Jan. 18 for a second day in a row. Futures for March, which will soon be the front month, were up 12 cents at $4.02 per mmBtu. In the spot market, meanwhile, frigid weather and high heating demand over the past week or so in the U.S. Northeast have kept next-day power and gas prices in New York and New England at or near their highest levels since January 2018. Analysts said bitter cold in the United States in recent weeks will boost heating demand enough to force utilities to keep pulling huge amounts of gas from storage, pushing overall inventories below the five-year average for the first time since mid-December Data provider Refinitiv said average output in the U.S. Lower 48 states fell from a record 97.6 billion cubic feet per day (bcfd) in December to 94.2 bcfd so far in January after frigid weather froze wells in several regions, including the Permian in Texas and New Mexico, the Bakken in North Dakota and Appalachia in Pennsylvania, West Virginia and Ohio.
US gas storage fields post largest draw of season as cold weather stays | S&P Global Platts - US natural gas storage fields withdrew more than 200 Bcf for the second week in a row as a pair of 200-plus pulls look likely in the weeks ahead, as the Henry Hub prompt propels to a 14-year high with the largest daily jump for Henry Hub forwards on record. Storage fields withdrew 219 Bcf for the week ended Jan. 21, according to data released by the US Energy Information Administration on Jan. 27. It was stronger than the 214 Bcf draw expected by an S&P Global Platts survey of analysts. The drawdown also outpaced the five-year average of 161 Bcf and last year's 137 Bcf pull in the corresponding week. It proved to be the largest draw of the winter as it outweighed the 206 Bcf draw reported for the week prior Working gas inventories decreased to 2.591 Tcf. US storage volumes now stand 308 Bcf, or 10.6%, less than the year-ago level of 2.899 Tcf and 25 Bcf, or 1%, less than the five-year average of 2.616 Tcf. The EIA report marked the fourth consecutive week of increasing storage withdrawal activity. The draw of 215 Bcf last week was nearly seven times larger than the withdrawal reported during the final week of 2021. Fundamentals have changed dramatically from month to month when the market was eagerly awaiting a storage withdrawal of 100 Bcf or greater. The market is now looking at storage withdrawals rapidly approaching, but not likely to reach, the 300 Bcf mark, according to S&P Global Platts Analytics. The NYMEX Henry Hub February contract catapulted nearly $2 to $6.26/MMBtu in trading following the release of the EIA's storage report on Jan. 27. The prompt month has not closed higher since November 2008. It was also the largest daily jump for Henry Hub forwards on record. Every forward month remains well above $4/MMBtu until April 2023 where it settled at $3.33/MMBtu. Forecasts are calling for more below-normal temperatures and possible well freeze-offs extending into February, according to S&P Global Platts Analytics. Platts Analytics calls for an even larger draw of 262 Bcf for the week ending Jan. 28 with another 200-plus pull likely for the week after. Despite the massive draw expected for the week in progress, demand was down across the Lower 48 on Jan. 27. Supply and demand across all sectors saw downward movement Jan. 27, leaving total US demand down 12.2 Bcf/d on the day to 134.1 Bcf/d, and total US supply down 1.4 Bcf/d to 97.9 Bcf/d, according to Platts Analytics. Residential and commercial demand dropped to 54.4 Bcf/d, accounting for 9.5 Bcf/d of the total decline due to warming temperatures across the nation. The biggest day-on-day losses came from the Midwest, down 5.4 Bcf/d to 17.1 Bcf/d, and the Northeast, down 3 Bcf/d to 18.8 Bcf/d. Gas-fired power generation dropped 2 Bcf/d to 31.3 Bcf/d with nearly half the decline coming from Texas.
February Exits Front Month with Furious Rally, as Natural Gas Futures Fly Close to Seven-Year High - Natural gas prices hovered in a narrow range early Thursday but spiked after a bullish government inventory report and customary buying into prompt-month expiration. The February Nymex gas futures contract settled at $6.265/MMBtu, up $1.988 day/day. It rolled off the books at the close. March, which takes over as the front month, climbed 24.7 cents to $4.283. The February contract topped $7.00 intraday. That easily eclipsed any session high to date in 2022. Futures had traded to a seven-week high of $4.879 on Jan. 12 and a seven-year high of $6.466 last Oct. 6. While outlooks into mid-February were evolving as of Thursday and fluctuating between a warm-up and extended cold into next month, the near-term forecast called for a pair of cold blasts that should keep furnaces cranking into early February, NatGasWeather said. A Nor’easter-type system “will track up the East Coast Saturday-Sunday with rain, snow and wind,” the firm said. “National demand is still expected to ease early next week” from Tuesday through Thursday (Feb. 1-3), “as a mild break sets up over the southern and eastern U.S.” with highs from the 40s to 70s. However, “another frigid system is expected into the northern and central U.S.,” beginning next Friday (Feb 4-7) for another round of strong national demand.” While forecasts beyond that are uncertain, “the theme of this winter has been durable weather patterns lasting for longer than initially forecast, including both strong early-winter warmth and the current long-lasting cold spell. From a market perspective, the protracted current cold throughout the heart of winter has steadily reduced late-winter downside risks.” “Natural gas contracts rolling off the board have gained an average 12.1 cents in 12 of the past 14 months on their final trading day,” . “While support for March may relent seasonally absent a true storage adequacy threat, a falling end-of-winter storage trajectory has limited the extent of likely declines over the next month.” Indeed, the U.S. Energy Information Administration (EIA) on Thursday reported a withdrawal of 219 Bcf natural gas from storage for the week ended Jan. 21. It marked the biggest pull of the winter season to date and easily eclipsed historical averages. It also exceeded market expectations.
U.S. Natural Gas Prices Climb Most Ever In Single Day - U.S. natural gas future prices skyrocketed 72% on Thursday on forecasts of colder weather. It was the sharpest one-day climb for the commodity since the contract launched in 1990, CME Group data confirmed.The 72% surge in prices came before the expiry of the February contract for nat gas as weather forecasts now look colder. The March contract’s price rise paled compared to the February contract rise. But the 10% rise for the March contract—on any other day—would have been more noticeable. Natural gas futures were trading below $4.50 per million British thermal units for most of the trading day, but some time after 12:45 p.m. EST, prices scrambled for the $7 mark, with the contract eventually settling at $6.265. The huge spike in the February contract is a clear sign that bearish bets were being squeezed out of the market.Natural gas prices have been particularly volatile as of late, with nat gas prices surging 6% just a day earlier as cold weather in many parts of the United States boosted demand and the Russia-Ukraine conflict spooked the market into fearing disruptions to the flow of natural gas from Russia to Europe.The cold weather is expected to boost demand for natural gas through space heating and electricity in the coming days, with estimates from NatGasWeather.com estimating that natural gas demand will be strong through the weekend as a cold snap is expected to hit many parts of the country.But today’s price movement is certainly more about a short squeeze than about demand forecasts. According to data compiled by Bloomberg, hedge funds have been net-long on nat gas contracts, expecting prices to rise. But money managers have still held onto a fair share of short positions. Given the price spike, it is clear that some of those money managers waited until the eleventh hour to cover their short bets.
U.S. natgas spikes after record gain in prior session on frigid weather — (Reuters) - U.S. natural gas futures jumped about 8% on Friday as a major winter storm targets the Northeast and on forecasts for much colder weather and higher heating demand in the next two weeks than previously expected, which had also caused prices in the now-expired February contract to soar over 70% late Thursday. In the last half hour of trading on Thursday, futures for February soared in a late flurry of buying that coincided with the imminent expiration of the contract at the end of the session. Traders said short-covering after a larger-than-usual weekly storage draw and forecasts for colder-than-normal weather were the primary reasons for Thursday's late-day price spike. Analysts at Gelber and Associates said there was talk in the market "that a large producer's inability to make delivery at Henry Hub forced them to cover short positions and put them on the wrong side of one of the most dramatic price escalations in the market’s history." On its first day as the front-month, gas futures for March delivery rose 35.6 cents, or 8.3%, from where the March contract closed on Thursday to settle at $4.639 per million British thermal units (mmBtu) on Friday. But compared to where the February contract closed when it was the front-month on Thursday, the March contract was down about 26%, which would be the biggest daily percentage decline since December 1995 when it hit a record 31%. In intraday trade on Thursday, the February contract rose to $7.346 per mmBtu, the highest price for the front-month since November 2008. The contract settled up about 46% at $6.265, its biggest daily percentage gain on record and the highest close for the front-month since October 2021. Of the 7,182 February contracts traded on the New York Mercantile Exchange (NYMEX) on Thursday, about 2,874 traded during the last 30 minutes before the future expired at 2:30 p.m. EST (1930 GMT), according to data from the NYMEX and Refinitiv. Prices during those 30 minutes averaged $6.04 per mmBtu. At 10,000 mmBtu per contract, the total value of those 2,874 contracts was around $174 million. For the week, the front-month was up 16%, its biggest weekly percentage gain since August 2020. Last week, the contract fell about 6%.
Bill introduced to stop utilities from charging customers for natural gas lost to leaky pipes - A Michigan state senator wants to pass a law prohibiting the state's natural gas utilities from charging customers for gas that leaks from pipes or gas that is otherwise lost because of variations in temperature, meter tampering, or during repairs to pipelines. Senator Jeff Irwin (D-Ann Arbor) said together Consumers Energy and DTE Energy are allowed by regulators to charge ratepayers about $25 million a year for lost and unaccounted-for gas. The chief component of natural gas is methane, a potent greenhouse gas which contributes to climate change. “I want to provide an incentive for these utilities to go out there and tighten up these leaks, protect our environment, and protect our ratepayers too,” Senator Irwin said. He conceded it will cost more upfront to fix the leaks, and customers will ultimately pay for that. “But, over time you make that up. Continuing to let our system leak every year and just pay for the leaks every year doesn’t make any sense to me,” Irwin said. Responding in an email, Consumers spokesperson Katie Carey said in part, “Already we have retired 700 miles of vintage pipe, accounting for 24% of our vintage material targeted for replacement and modernization on the distribution system and the advanced measurement technology we have deployed to minimize variances.” A statement from DTE indicated the utility has upgraded more than 1,000 miles of pipelines since 2010.
Idle Oil, Natural Gas Wells Said to Need Proper Monitoring, Maintenance - The Interstate Oil and Gas Compact Commission (IOGCC) recently released its latest counts of documented idle and orphan oil and gas wells in the United States and Canada. “Many idle wells have potential for future oil or gas production or associated uses,” stated IOGCC. “If not properly monitored and maintained, however, they may pose a risk to the environment, public health, and safety.” Idle wells have not been plugged, nor are they producing, injecting, or otherwise being used for their intended purpose, according to IOGCC. Orphan wells, in contrast, are “idle wells for which the operator is unknown or insolvent,” the Oklahoma City-based multi-state government entity added. More federal funding is expected to go toward plugging, remediating, and restoring orphan oil and gas well sites. In November President Biden signed into law the Infrastructure Investment and Jobs Act (IIJA), which the U.S. Department of the Interior said includes $4.7 billion for such activities. IOGCC noted that IIJA was enacted shortly before publication of its new report, Idle and Orphan Oil and Gas Wells: State and Provincial Regulatory Strategies 2021. It stated the legislation includes money to plug orphan wells on federal, state, private, and tribal lands. “In most states and provinces, idle wells with no future beneficial use must be plugged,” stated IOGCC, which surveyed 32 member states and five Canadian provinces for the report. IOGCC said there were 231,287 approved idle wells reported by the states and 140,183 by the provinces at the end of 2020. It stated that operators plugged 62,463 idle wells in the United States and 16,295 in Canada over the three-year span covered in the report. In the United States, a total of 1,619,071 documented wells have been drilled but not plugged, stated IOGCC. The organization said the total for the Canadian provinces is 372,697. At the end of 2020, surveyed states reported 92,198 documented orphan wells and provinces reported 5,015 such wells, noted IOGCC. The organization said improved investigation and operator verification efforts resulted in a 50% increase in the number of documented orphan wells from 2018 to 2020. States and provinces plugged 9,774 and 4,930 orphan wells, respectively, during the period. “In total through 2020, the states have plugged over 78,000 orphan wells and the provinces almost 6,300,” said IOGCC. The organization said the cost to plug an orphan well “varies widely depending on well depth and condition, location, accessibility, and other factors.” The average per-well expenditure ranged from $2,400 to $227,000 in 25 states from 2018 through 2020, with an overall three-year average of $25,634, stated IOGCC. In the three Canadian provinces that plugged orphan wells from 2018 through 2020, the average per-well outlay was C$41,156 ($32,781), which IOGCC derived from a range of C$37,528 to C$42,047 ($29,891 to $33,490). “These numbers do not include expenditures for site restoration,”
Oil powering a big chunk of power grid - NEW ENGLAND POWER plants are burning a lot more oil to generate electricity, apparently because the cost of natural gas is so high. In January last year, oil accounted for just 0.2 percent of the fuel mix used to generate power across the region. This month, starting around January 7, oil began accounting for 20 to 25 percent of power generation, behind only natural gas and nuclear. Coal even popped up in the fuel mix, at about 3 percent. The higher use of oil and coal means greater carbon emissions across the region and underscores how far the region has to go to trim and eventually eliminate its use of fossil fuels in electricity production. Matthew Kakley, a spokesman for ISO-New England, the region’s power grid operator, said power generators using oil are gaining a larger market share right now because their fuel costs are lower. “I don’t have a direct overlay of temperatures and the fuel mix, but what we’re seeing is that natural gas prices are much higher this year than last year, which is making gas plants more expensive than oil units,” Kakley said in an email. “Part of this higher cost is driven by cold weather limiting the amount of gas available to power generators, but it is also affected by higher natural gas prices nationally. For context, the average price for natural gas in Massachusetts last January was $4.97 per MMBtu. It’s only half a month, so it’s not exactly an apples-to-apples comparison yet, but what we’ve seen so far this month is prices averaging $12.39 per MMBtu.” Dan Dolan, president of the New England Power Generators Association, said natural gas prices are higher internationally and domestically than they have been in years. He said supplies of natural gas have stagnated but demand has been picking up, leading to the sharp increases in price. December was a fairly mild month, but colder weather hit the region in the second week of January. In colder weather, more natural gas goes to homes for heating and there is less available for power generators. With natural gas prices spiking, power generators using oil as their fuel jumped into the breach, successfully bidding into the region’s wholesale electricity market for a much greater share of the region’s power generation.
U.S. judge voids 80 million acres of offshore oil and gas leases--The sale of offshore oil and gas leases on more than 80 million acres in the Gulf of Mexico was canceled by a U.S. judge who ordered regulators to take a harder look at the impact on climate change. U.S. District Judge Rudolph Contreras in Washington vacated the lease sale in a 67-page decision, issued Thursday. The judge found that the Interior Department underestimated the climate impacts of the leases and doing a further analysis wouldn’t overly harm the companies seeking the leases. “The leases have not become effective and no activity on them is taking place,” the judge wrote. If the leases were to take effect, it would be much harder to cancel them, Contreras said. The judge also criticized the Interior Department -- writing that it acted “arbitrarily” -- for failing to factor into its assessment the climate effect of the burning of oil and gas from the leases in countries outside the U.S. The court’s decision throws into doubt the November sale of some 308 tracts spanning 1.7 million acres (688,000 hectares) of the Gulf of Mexico. Thirty-three oil companies spent about $192 million buying the drilling rights in the auction, the second-to-last scheduled under a five-year program drawn up by the Obama administration. And it raises questions about a possible Gulf auction in spring. In one of his first acts as president, Joe Biden put a temporary halt on all new oil and gas leasing. But last year, a federal judge in Louisiana ordered the Biden administration to move ahead with the leases. Environmental groups then sued to halt the sale. The Interior Department said in a statement that it was compelled to proceed with the state by the Louisiana court and is reviewing the latest ruling. “Our public lands and waters must be protected for generations to come,” the department said. “That’s why the president called for a pause on leasing in his Executive Order, and why we are appealing the decision enjoining implementation of the pause.” By vacating Interior’s decision to hold the lease sale, the court has ensured that no harm will result from it, the environmental groups, including Earthjustice and Center for Biological Diversity, said in a statement after the ruling. Whatever Interior decides to do, it must start with a blank slate on the lease program and consider the full environmental costs associated with auctioning off public waters to the fossil-fuel industry, the groups said.
Calcasieu Pass in Louisiana nearing start of LNG production - U.S. LNG project developer Venture Global LNG is nearing production of the first amount of liquified natural gas at its new Calcasieu Pass export facility in Louisiana. Venture Global is developing an LNG export facility in Cameron Parish, Louisiana, south of the city of Lake Charles. The project site is at a location that features deep-water access, proximity to gas supplies, and ease of transport for buyers. Once complete, the facility will export 10 million tonnes per year (mtpa) of LNG.The company states the official start of operations as the first quarter of 2023. However, Reuters reports citing energy traders, that the facility is close to producing its first LNG. This came after the amount of feed gas to the facility increased rapidly this week. The amount of gas flowing to Calcasieu rose to 88 million cubic feet per day (mmcfd) on 21 January; from an average of about 38 mmcfd during the prior week.In December, Venture Global and Louisiana goverment announced the company will invest more than $10 billion to develop Calcasieu Pass 2 (CP2) LNG, a fourth LNG export facility in Louisiana. It will build, own and operate an LNG terminal with a liquefaction capacity of 20 mpta of LNG. Furthermore, the company signed a sales and purchase agreement with China’s CNOOC. Under this, China will buy 1.5 million tonnes of LNG from the Calcasieu Pass facility.
Calcasieu Pass ramps up feedgas deliveries as it prepares to begin LNG production | S&P Global Platts -- Feedgas deliveries to Venture Global LNG's Calcasieu Pass reached the highest level to date Jan. 24 – more than double the amount from a week earlier -- as the Louisiana liquefaction facility prepared to begin production, S&P Global Platts Analytics data showed. Once online and fully ramped up, the seventh major US LNG export facility will have a capacity of 10 million mt/year. In the weeks ahead, Calcasieu Pass will be starting up at a time of significant volatility in supply, demand and prices in the global LNG market. US terminals continue to operate at or near full capacity, amid strong netbacks to end-user markets. No cancellations at Gulf Coast facilities have been reported in recent months. "Impossible," an Atlantic-based trader said of the potential for any cancellations in the near-term. "LNG is so much in the money." Platts assessed the Gulf Coast Marker at $26.250/MMBtu on Jan. 24, up $3.750/MMBtu on the day, as US FOB cargo values tracked European prices and low shipping rates. Based on nominations for the morning cycle, gas deliveries observed to be flowing to Calcasieu Pass totaled 77.36 MMcf/d on Jan. 24, up from 47.56 MMcf/d the previous day and 34.71 MMcf/d a week earlier, Platts Analytics data showed. According to Venture Global, all 18 liquefaction modules have been received at the Louisiana terminal from Italy and set on foundations. Earlier in January, the operator received US regulatory approval to begin commissioning the first two-train block with feedgas. Company officials have not addressed whether a cargo will be imported to the terminal for the purposes of cooling down the storage tanks, before the first export from the facility. Cheniere Energy brought in a cool-down cargo before its Sabine Pass terminal, the biggest US liquefaction facility, began exports in 2016. Last spring, the Venture Global had suggested the first export could occur by the end of 2021, a year ahead of its original schedule. Total US LNG feedgas demand stood at 13.28 Bcf/d on Jan. 24, up from 11.43 Bcf/d the previous day and 12.96 Bcf/d a week earlier. At Freeport LNG, utilization recovered Jan. 24 following an unplanned outage on Jan. 23. According to an air emissions notice to Texas regulators, the loss of electric power to Freeport LNG's upstream pretreatment facility resulted in a trip of Freeport LNG's liquefaction trains 1, 2 and 3. "Because of the trip, the boil-off gas compressors also tripped due to an increase in pressure in the BOG recovery system," the notice said. The three LNG trains appeared to be operating on Jan. 24, a person familiar with the outage said.
Feeling Inflation Pinch, Permian E&Ps Targeting Further Efficiency Gains - Continued efficiency improvements are expected to be critical for natural gas and oil producers in the Permian Basin this year as cost inflation for oilfield services (OFS) takes full effect. Larger exploration and production (E&P) independents that locked in cheaper OFS agreements in early 2021 and stuck to their capital expenditure (capex) budgets stayed somewhat shielded from inflation last year, according to Rystad Energy’s Artem Abramov, head of shale research. “Already in early 2021, we started getting some reports about a labor shortage,” Abramov told NGI. It started with the trucking segment, “and that’s always the first sign of upcoming cost inflation.” Privately held E&Ps, meanwhile, “warmed up” service rates in 2021 as they continued to add drilling rigs throughout the year, capitalizing on high oil and gas prices while their publicly traded counterparts maintained capital discipline, Abramov said. For 2022, though, public E&Ps will have no choice but to accept higher OFS prices, Abramov said. Goldman Sachs researchers led by Neil Mehta expressed a similar view recently in a research note to clients. The analyst team said “we see risk for higher capex from cost inflation – the majority of producers at our recent Goldman Global Energy and Clean Technology conference highlighted single/double-digit inflation owing to labor, steel and fuel costs. “We see potential for inflationary pressure not just in 2022 budgets but also in 2023/24 budgets in part due to the need to incentivize further rig/stimulation crew adds.” Rystad, for its part, expects cost inflation alone to drive an estimated 15% year/year increase in drilling and completion costs for Lower 48 operators in 2022, Abramov said. ConocoPhillips CEO Ryan Lance said in November during the 3Q2021 conference call that inflation impacts were likely to be felt most acutely in the Permian heading into 2022. However, because of the Houston-based independent’s scale and sophisticated supply chain network, “we think we have a way to mitigate quite a lot” of the inflationary pressure. Inflation impacts should be offset somewhat by efficiency gains, which in recent years have been saving the industry an estimated $3-4 billion annually, according to Rystad. The Goldman team highlighted efficiency improvements by Permian heavyweights such as Devon Energy Corp.. Since the first quarter of 2018, Devon has “reduced total company operating costs by 23% driven largely by a 34% reduction in Permian operating costs over the same time period,” analysts said. EOG Resources Inc., meanwhile, “is targeting flat well costs in 2022 as a result of continued operational efficiencies and having [roughly] 50% of well costs already secured for the year,” the Goldman team said.
Texas Upstream Oil, Natural Gas Sector Gains 3,000 Jobs Amid Labor Market 'Fireworks’ -Texas’ upstream oil and gas employment grew to 188,700 in December, representing increases of 3,000 jobs month/month and 27,800 positions year/year, the Texas Independent Producers and Royalty Owners Association (TIPRO) reported last week. “Oil and natural gas employment continues to rebound, providing quality, high-paying jobs to Texans throughout the state, and we expect that trend to continue,” said President Ed Longanecker. The Lone Star State’s upstream employment has now risen for eight months straight, said TIPRO, which tabulates job figures from the U.S. Bureau of Labor Statistics Current Employment Statistics report. According to the Texas Oil and Gas Association (TXOGA), that equates to an average monthly gain of 2,538 new jobs. TIPRO noted that the state’s oil and gas services headcount has grown by 26,500 jobs year/year while the oil and gas extraction total is up 1,300 jobs for the period. December’s 3,000-job increase marks a 25% month/month improvement from the upstream employment growth, growth, TIPRO reported for November. It also eclipses gains for October and September.. “These employment opportunities also span across a spectrum of occupations, from laborers and roustabouts to software developers and electrical engineers,” said Longanecker. TIPRO said it continued to see strong job posting data in December for the state’s upstream, midstream, and downstream sectors. The trade association noted that it tracked 8,484 active unique oil and gas postings for the month, including 2,612 new job postings. The organization, which further defines the state’s oil and gas industry within the bounds of 14 specific sectors, said support activities ranked highest in December with 2,144 unique job postings. Claiming the second and third positions were crude petroleum extraction (1,506 postings) and petroleum refineries (874). Houston had the most number of unique oil and gas job postings in December with 3,041 listings, said TIPRO. Midland, the heart of the Permian Basin, and Dallas claimed the next two spots on the list with 939 and 531 postings, respectively. In its ranking of the top companies by unique job postings, TIPRO said NOV Inc. took the lead with 477 listings, followed by Baker Hughes Co. (468) and Halliburton Co. (407).
Aerial surveys detect dozens of methane 'super-emitters' in Permian - (Reuters) -Around 30 oil and gas facilities across the Permian Basin in Texas and New Mexico spewed large amounts of methane for three years, emitting the equivalent annual climate pollution from half a million cars, according to a report released on Monday. The facilities, which include well pads, pipelines, compressor stations and processing facilities, were observed as "persistently" emitting large volumes of methane over the three years of aerial surveys done by the Environmental Defense Fund and research group Carbon Mapper. Carbon Mapper is a non-profit organization backed by philanthropists including Michael Bloomberg that uses technology to see and measure emissions at the scale of individual facilities. The effort, an outgrowth of surveys NASA completed in California using methane-tracking planes, is meant to help polluting industries find and plug leaks. The so-called "super-emitters," located in the most productive U.S. oil field, only account for .001% of the Permian Basin's oil and gas infrastructure but emit around 100,000 tonnes of methane per year. Repairing those leaks offers companies an immediate opportunity to help achieve U.S. and international methane reduction targets and save around $26 million in escaped natural gas, the report said. "The magnitude of emissions coming from a handful of methane sources in one of the top oil and gas producing regions illustrates the opportunity to make significant near-term progress toward the stated methane reduction goals of the U.S., other countries and companies around the world," said Riley Duren, CEO of Carbon Mapper and a researcher at University of Arizona. The report shows these large emission sources cut across a diverse range of infrastructure and oil and gas operators in the Permian Basin. EDF and Carbon Mapper did not disclose the corporate owners of the biggest emitting sources, but provided Reuters with the facilities' coordinates. According to a Reuters review of those locations, plumes identified by the study appeared to be linked to facilities owned by Occidental Petroleum Corp, ConocoPhillips, Energy Transfer Partners LP, Callon Petroleum Co. and Coterra Energy. None of the companies immediately responded to requests for comment. The American Exploration & Production Council, an industry trade group, also had no immediate comment on the survey. Methane is the second-biggest cause of climate change after carbon dioxide. Its high heat-trapping potential and relatively short lifespan in the atmosphere means cutting its emissions can have an outsized impact on the trajectory of the world's climate.
30 Permian Basin Facilities Leak Half a Million Cars' Worth of Methane, Report Finds - As the largest oil-producing region in the U.S., the Permian Basin in Texas and New Mexico is already a nightmare from a climate perspective. But now a new report from Carbon Mapper and Environmental Defense Fund (EDF) reveals that oil and gas facilities in the area are emitting unnecessary greenhouse gas emissions in the form of half a million cars’ worth of methane. “In this decisive decade for reducing greenhouse gas emissions every molecule matters, and the fact that some facilities are persistently leaking methane for years without detection or repair highlights the urgent need for comprehensive and transparent methane monitoring,” Riley Duren, chief executive officer for Carbon Mapper and research scientist at the University of Arizona, said in an EDF press release. The report is based on three years of aerial surveys of oil and gas facilities in the Permian Basin, taken from 2019 to 2021. The surveys revealed that around 30 facilities had consistently leaked large amounts of methane over multiple years. These facilities, which include pipelines, well pads, compressing stations and processing facilities, only account for less than 0.001 percent of the oil and gas infrastructure in the basin, yet stopping their flow of methane would keep 100,000 metric tons of methane out of the atmosphere every year and save $26 million a year in gas. Methane is the second largest contributor to the climate crisis after carbon dioxide, Reuters reported. It lasts for a shorter time in the atmosphere, but while there it traps around 80 times as much heat as carbon dioxide, according to Yale Environment 360. The methane emissions in the report are the result of natural gas leaks, so eliminating those leaks is a relatively simple way to make a big contribution to fighting climate change.
API's "New Tune" on Methane Rules is the Same Old Story - - The American Petroleum Institute’s (API) announcement of support for President Biden’s proposed national methane rules is an illustration of the power of communities and environmental activists to raise the profile of issues like methane pollution from oil and gas and demand bold action to reduce it–just two years ago API was pushing President Trump to undo weaker, Obama era, methane rules. This rapid and significant shift in change is also what makes this public statement disingenuous. After all, this is an industry with a history of machiavellian press relations and politicking. So, what might really be happening behind the decision for API to suddenly support bolder government action to cut oil and gas methane pollution?In March we will release our oil and gas accountability report which tracks climate commitments from 9 major oil and gas companies, compares them to what is actually happening on the ground, and identifies the carbon accounting tricks that the industry relies on to create a facade of progress while they increase emissions.One of those tricks is capitalizing on a broken emissions reporting system that allows them to report their own emissions through a simple multiplication equation without taking any direct measurements of emissions. The result is emissions levels that even the EPA admits are underestimated. Studies that take direct measurements of methane emissions across the sector estimate that the real number is probably 2 times higher. Right now, this flawed data is helping the industry. In fact, it is one of the few indicators that the industry can point to show progress which they need to prove credibility with decision makers and shareholders and to maintain their social license to operate.It’s probably not a coincidence then, that in the same breath as their support for the EPA methane rules API also announced opposition for proposed legislation that would, among other things, require an improvement to the EPA reporting system and charge polluters who surpass an industry defined methane threshold. As they are written right now, the proposed EPA methane rules that API supports are not as comprehensive as they could be. The EPA has the authority to require monthly inspections but the current draft only requires quarterly inspections. The proposed rules also include a loophole of sorts that allows for thousands of wells to avoid regular leak detections all together. Both of these will undoubtedly impact the health of communities living closest to the facilities and leave emissions on the table. However, the rules are not final and there are signs that EPA plans to continue to strengthen them throughout the process. API wasn’t clear whether they would support rules that applied to all wells or included more frequent inspections.
Halliburton sees frac equipment orders double as shale rebounds --Shale-oil companies are using almost all of the frac equipment and crews available as exploration expands, accelerating cost inflation and pointing to worsening supply-chain disruptions across the industry. North American oil drillers appear likely to expand spending by more than 25% this year while overseas explorers are on course for a more modest increase in the mid teens, Halliburton Co. executives said on Monday after reporting their biggest quarterly profit in seven years. The world’s top provider of fracking services already is seeing tightening labor, trucking and raw-material supplies, and in some regions as much as 80% of workers are transplants recruited from other areas. Even something as mundane as the sand Halliburton blasts into wells to help fracture oil-soaked rocks is getting harder to source, Chief Executive Officer Jeff Miller said during a conference call with analysts. The squeeze is proving a boon to Halliburton, which lifted its dividend for the first time since 2014 and said orders for pumping gear have more than doubled. The company’s fracking business is working at full capacity and oil companies are paying higher prices for so-called completion work. ConocoPhillips and peers such as Devon Energy Corp. have been warning since last year that oilfield inflation was a burgeoning threat. “This is a fantastic set of conditions for Halliburton,” Miller said. “Our current completion tool order book has more than doubled from a year ago signaling strong growth and profitability again in 2022.” Oil and natural gas explorers are paying record costs as the economic growth that underpins energy demand rebounds from the pandemic-driven collapse, the Federal Reserve Bank of Dallas said in recent weeks. Supply-chain snarls in the Permian Basin -- the biggest U.S. oil field -- are making drilling projects more complicated, prolonged and expensive. Miller said there’s little reason to expect things to change any time soon. “I don’t see 2023 as an endpoint by any means,” Miller said. “I think the road goes on well beyond on that.”
RPC Eyes Upping Fracturing Fleet Count for 2022 - Oilfield services (OFS) and equipment provider RPC Inc. said it might activate another hydraulic fracturing fleet but added that likely would not occur during the first six months of this year. CEO Richard A. Hubbell said that he sees “many indications of continued growing activity levels and improved pricing” in the new year. Last spring, Hubbell predicted a “continued modest recovery” as 2021 progressed. Previously, he said that he anticipated growth from private as well as public exploration and production (E&P) companies.He said the Atlanta-based oilfield services and equipment provider, which serves onshore and offshore E&P firms operating in the United States and internationally, “reactivated idle pressure pumping equipment as market pricing and customer demand has consistently improved.“RPC’s fourth quarter revenues increased as strong current and forecasted commodity prices encouraged our customers to continue their drilling and completion activities,” Hubbell said. “In addition, our revenues grew due to higher pricing and the new Tier IV dual-fuel pressure pumping fleet we placed into service late in the third quarter.” Hubbell also acknowledged that “personnel shortages exacerbated by the current Covid surge” are affecting the operational environment for RPC. “Our industry is also facing materials and parts shortages impacting many essential inputs, as well as price increases for raw materials and components,” he said. “While we have been able to stay ahead of these issues, they may impact our utilization and profitability in the near term.”Cost inflation has presented challenges across the board for OFS companies.During a call to discuss fourth quarter and full-year 2021 earnings, Vice President Corporate Services Jim Landers said that activating another horizontal pressure pumping fleet – bringing the total from the current eight to nine – is one action RPC is contemplating.When asked about the company’s fleet count during the first half of the year, Landers said he “would think of it as being fairly constant to where…we’re starting the year. We’re assessing a number of things. One of them is activation of another fleet.” Landers noted RPC has “some fairly new and good quality equipment that can be reactivated if demand wants it,” but he added the company has no new equipment on order. If RPC had equipment on order, “we don’t know how long it would take for new equipment to be delivered, but we know it would be a little while. So even if you place an order today, you wouldn’t see a new additional fleet in the field from us during the first half of the year.”To be sure, Palmer said the company is “very interested in activating another fleet” under continued favorable economic conditions. “We will continue to evaluate economics to support upgrading our equipment fleet,” Hubbell said.
EIA forecasts US fossil fuel production to reach new highs in 2023 - After declining in 2020, the combined production of US fossil fuels (including natural gas, crude oil, and coal) increased by 2% in 2021 to 77.14 quadrillion British thermal units. Based on forecasts in its latest Short-Term Energy Outlook (STEO), the US Energy Information Administration (EIA) expects US fossil fuel production to continue rising in both 2022 and 2023, surpassing production in 2019, to reach a new record in 2023. Of the total US fossil fuel production in 2021, dry natural gas accounted for 46%, the largest share. Crude oil accounted for 30%, coal for 15%, and natural gas plant liquids (NGPLs) for 9%. EIA expects those shares to remain similar through 2023.
- US dry natural gas production increased by 2% in 2021, based on monthly data through October and estimates for November and December. In the EIA forecast, improvements in drilling efficiency and new-well production will contribute to production increases of 3% in 2022 and 2% in 2023.
- US crude oil production dropped slightly, by an estimated 1%, in 2021, but EIA expects it to increase by 6% in 2022 and 5% in 2023. EIA forecasts that in 2022 and 2023, crude oil prices will remain high enough to encourage growth in the number of active drilling rigs and continued improvement in drilling efficiency.
- US coal production increased by an estimated 7% in 2021, driven by increased demand for coal because of rising natural gas prices. Coal’s comparatively lower prices made coal more economical for use in electric power generation compared with natural gas. In 2020, US coal production had fallen to its lowest level since 1964. EIA forecasts that coal production will increase 6% in 2022 as coal-fired electricity generators rebuild inventory levels. However, EIA forecasts that coal production will only increase by 1% in 2023 as demand for coal in the electric power sector declines.
- US NGPL production increased by 4% in 2021. EIA expects US NGPL production to increase by 9% in 2022 and then by 4% in 2023. Because NGPLs are a coproduct of natural gas, the forecast for rising NGPL production is linked to the forecast for rising natural gas production.
China's crude oil output rises in 2021 - China's crude oil output reached nearly 199 million tonnes last year, up 2.4 percent from the previous year, official data showed. The volume represented a 4-percent increase from the 2019 level, according to data from the National Bureau of Statistics. In December alone, 16.47 million tonnes of crude oil was produced in the country, up 1.7 percent year on year. Last year, China's import of crude oil neared 513 million tonnes, 5.4 percent lower than the previous year, the data showed.
US shale oil output poised for higher growth - US shale oil production looks to be on a stronger growth path as oil prices rebound and more firms plan to boost spending this year. Oil output is expected to rise by 105,000 b/d, or 1.2pc, from the seven US shale formations covered in the EIA's Drilling Productivity Report (DPR) next month, as new-well production outpaces legacy declines at existing wells by a comfortable margin. Tight oil output growth accelerated in the second half of last year as a strong recovery in the prolific Texas-New Mexico Permian basin was augmented by modest growth in other shale regions (see graph). Most shale firms plan to boost capital spending this year, the latest survey by the Federal Reserve Bank of Dallas says (see graph). In all, 35pc of upstream company executive respondents expect a significant and 43pc a slight increase in spending, compared with 18pc and 32pc, respectively, a year ago (see graph). Nearly half say their firm's primary goal in 2022 is to boost production, 15pc say it is to maintain production and 13pc say it is to reduce debt. The Dallas Fed survey highlights divergent strategies between private and publicly owned shale producers. More small firms — those with less than 10,000 b/d of production — than large firms aim to lift output this year. A total of 57pc of small firms say their primary goal is to raise production, compared with 24pc of large firms. Close to 30pc of large firms say their primary goal is to reduce debt, compared with 7pc for small firms. Smaller firms are typically privately owned, while larger companies include big public shale producers. Private operators accounted for most of the increase in onshore rig counts last year, consultancy Rystad Energy says. The number of horizontal drilling rigs deployed in the US has risen to 544, up by 60pc on a year ago and about three-quarters of pre-pandemic levels (see graph). But half the rigs are operated by private firms, Rystad says, compared with a third a year ago. Private rig counts now exceed pre-pandemic levels. There was a surge in drilling last year by private operators that were inactive for at least six quarters, Rystad says.
Colorado Makes First Assessment of State's Oil, Natural Gas Emissions - The Colorado Oil and Gas Conservation Commission (COGCC) last month released its first annual report to evaluate the cumulative impacts of oil and natural gas emissions, setting the stage for future evaluations and recommendations. State Senate Bill (SB) 181, enacted in 2019, is designed to limit the effects of emissions and environmental disruptions from oil and gas development. “As the first year of Oil and Gas Development Plan (OGDP) approvals after the Mission Change rules went into effect on January 15, 2021, the data set included in this report is small – it is limited to the seven approved OGDPs,” “This report focuses on presenting summaries of the data collected so far and identification of data fields that will inform future evaluation of cumulative impacts.” The annual report is required by COGCC under a rule enacted in November 2020 that took effect last year. Gov. Jared Polis signed SB 181 into law in April 2019, enabling the COGCC to enact rules to “regulate the development and production of the natural resources of oil and gas in the state of Colorado.” The COGCC prepares the report in consultation with the Colorado Department of Public Health and Environment (CDPHE). The state has since pursued some of the nation’s toughest environmental regulations, including Rule 903, which made it the second state in the country to prohibit routine venting and flaring of natural gas by upstream operators. The report highlights air quality data collected in the most active oil and gas region in the state, the Denver-Julesburg (DJ) Basin. For example, a single well in the DJ was found to produce 0.38 tons/year of methane and 1.37 tons/year of volatile organic compounds, researchers noted. The Greenhouse Gas (GHG) Roadmap included in the report further notes a 2021 GHG analysis published by the Air Pollution Control Division of the CDPHE in September last year. Notable findings from that report showed Colorado’s GHG emissions decreased by 9% between 2005 and 2019. The electric power sector was found to be the largest contributor to GHGs, followed by transportation, then residential, commercial, and industrial fuel combustion, and finally natural gas and oil systems. Natural gas and oil was, however, the largest contributor of methane emissions. The report additionally features some of the innovative technologies and measures used by the oil and natural gas industry to minimize cumulative impacts. They include aerial surveys that monitored methane emissions last July and September. The full 2021 Report on the Evaluation of Cumulative Impacts can be found here.
A quite terrible update on pollution from stripper wells in Colorado (and what you can do about it) - In August last year, we shared video evidence of pollution occurring at oil and gas facilities in CO that produce only minimal amounts of oil and gas. Industry and regulators in Colorado call these operations “stripper wells.” At that time, we had only just begun to focus some of our field investigations into stripper and inactive well sites. What we have discovered since is that the more we investigated these facilities, the more pollution we seemed to find. Since August 2021, we have conducted 105 investigations of oil and gas facilities in Colorado’s Front Range, northwestern Colorado, the North Fork Valley, and the Four Corners region in and around Canyon of the Ancients National Monument. These investigations resulted in us filing 27 complaints with the Air Pollution Control Division (APCD) based on our optical gas imaging (OGI) evidence of pollution. Those complaints contain documentation of pollution due to suspected leaks, malfunctions, negligence, and/or intentional violation of air pollution regulations. Seventeen (17) of our recent complaints were filed on oil and gas facilities that were either producing at minimal levels or were inactive. More specifically, our recent complaints regarding stripper and inactive wells account for 13 of the 16 complaints we filed on pollution from storage tanks. Unfortunately, a number of these polluting tanks are allowed uncontrolled emissions and are not subject to regulatory enforcement. This is due in part to the low production levels of several of the facilities. In Colorado, oil & gas operators are allowed to pollute up to a certain amount without meeting a legal threshold to apply for an air permit. Operators are entrusted to calculate their own pollution estimates, and these estimates are not required to be based on direct measurements of emissions. It is what it seems to be: another potential loophole for chronic polluting oil and gas operators. Here are some examples of what uncontrolled emissions from tanks that are purportedly polluting below pollution thresholds look like:
Biden outpaces Trump in issuing drilling permits on public lands --The widening gulf between the president’s policies on oil, gas and coal extraction and his initial promises has raised questions about his climate goals. After years of federal lease sales to oil, gas and coal companies, environmentalists had hopes that President Biden would end the fossil fuel bonanza. But one year after announcing a halt to any new federal oil and gas leasing, Biden has outpaced Donald Trump in issuing drilling permits on public lands. After setting a record for the largest offshore lease sale last year in the Gulf of Mexico, the Interior Department plans to auction off oil and gas drilling rights on more than 200,000 acres across Western states by the end of March, followed by 1 million acres in the Cook Inlet, off the coast of Alaska.The administration’s actions reveal an uncomfortable truth: Although Biden supports a shift to cleaner sources of energy, he has failed to curb fossil fuel development in the United States. His push to suspend federal oil and gas auctions has run headlong into political and legal challenges, and his administration has offered no plan to address the climate impact of mining in Wyoming’s coal-rich Powder River Basin. Collectively, these activities account for nearly a quarter of the nation’s greenhouse gas emissions. This month, Interior’s Bureau of Land Management indicated it would reverse the Trump administration’s decision to expand oil and gas production on the largest swath of federal land, the National Petroleum Reserve in Alaska — but would allow drilling on half of the reserve. Four days later, lawyers for the federal government declined to defend the Obama administration’s 2016 coal moratorium, which Trump lifted two months after taking office. Instead, they argued that environmentalists’ lawsuit to restore it should be dismissed on technical grounds. Climate activists have expressed dismay at the administration’s actions, questioning how the White House can allow more fossil fuel extraction on public lands, given its commitment to cut U.S. emissions. U.S. District Judge Terry A. Doughty in Louisiana struck down Biden’s Jan. 27, 2021, executive order in June, dealing a major blow to the president’s plans to cut greenhouse gas emissions from fossil fuels. The decision by Doughty, a Trump appointee, highlights the challenge in curbing fossil fuel production when current law directs the government to auction off federal land and many states rely on royalty revenue. The authority to suspend oil and gas leasing lies “solely with Congress,” Doughty wrote. Biden officials said they could be held in contempt if they didn’t resume leasing. Legal challenges have “made it impossible for us to stop many of these leases,” White House press secretary Jen Psaki said during Thursday’s daily briefing.
Enbridge Uses Scoring System to Track Indigenous Opposition - AS PART OF its efforts to build and operate pipelines, the oil transport company Enbridge used a tracking system that identified Indigenous-led groups as key threats.Internal documents reviewed by The Intercept describe how Enbridge launched an initiative known as Opposition Driven Operational Threats, or ODOT, to focus the company’s attention on Indigenous opposition to Line 3 and Line 5, two controversial pipelines that transport carbon-intensive tar sands oil between Canada and the United States.The documents provide a rare window into how fossil fuel companies counteract political opposition. In Enbridge’s case, its ODOT initiative goes so far as to track community gatherings of pipeline opponents and label tribal lands as areas where the company faces threats. “To the rest of us, ‘threat’ means actual threats to life and liberty, but to them this is all about how much money they can extract while carrying out an operation that is environmentally devastating,” said Mara Verheyden-Hilliard, director of the Partnership for Civil Justice Fund’s Center for Protest Law and Litigation and an attorney representing opponents of Line 3. “You begin to have this perversion of concepts of what actually are true threats.”Information about how the internal system works is limited, but Verheyden-Hilliard said that there could be civil rights implications depending on whether any state or local agencies are involved in the collection of data for ODOT and how Enbridge uses the information the initiative produces. The existence of the tracking system, she said, was especially troubling considering Enbridge’s payments to law enforcement agencies for policing pipeline opposition. Gatherings of pipeline opponents are protected by the First Amendment. In communities in which tribal governments have invoked their treaty rights to challenge pipeline paths, the tool could potentially be used to develop divisive campaigns aimed at pressuring tribes to back down. Enbridge’s definition of a threat includes virtually anything that could negatively impact the company. ODOT was meant to protect against not only property damage but also reputational harm to the company. A list describing categories of threats included activities that involved trespassing or disruptive protests as well as “awareness events,” which appeared to reference gatherings for pipeline opponents to get their message out. A tribe considering rejecting an Enbridge easement, often by invoking its treaty rights, could also qualify as a threat.The ODOT initiative includes a system that assigns a risk score to geographical areas. One of the factors used to tally the score is “Indigenous Opposition.” Enbridge has used the scores to generate color-coded maps that often identify areas covered by treaty rights as places where the company faces a threat.On the maps, lands of the Red Lake Nation, the Leech Lake Band of Ojibwe, and the Bad River Band of Lake Superior Chippewa — all Upper Midwest tribes that have opposed Enbridge pipelines in court — have been marked in red to indicate a threat area.Through ODOT, the company also tracks individual pipeline opposition groups. To facilitate the monitoring, Enbridge has used a system to count the number and types of “threats” to Enbridge projects carried out by particular “threat actors” over time. In 2021, the counts focused particularly on Line 3 and Line 5, tracking more than a dozen threat actors, including Indigenous-led pipeline resistance groups such as Camp Migizi and the Giniw Collective.
Hess Ramping Up Bakken Production as Oil Demand, Prices Rise - U.S. independent Hess Corp. expects production from its Bakken Shale assets to grow 6-9% in 2022 to 165,000-170,000 boe/d.The New York-based producer is ramping up Bakken activity after adding a third rig last September. Previously it had slashed its rig count from six to one because of the coronavirus pandemic. A fourth rig could potentially come online next year, executives said in an earnings call Wednesday.Bakken net production was 159,000 boe/d in the fourth quarter compared with 189,000 boe/d in the prior-year quarter, primarily due to the impact of lower drilling activity.The company can generate “attractive returns” in the Bakken at $60/bbl for West Texas Intermediate (WTI) oil, executives said. They called the Bakken a “cash engine.” In 2022, Hess will drill 90 Bakken wells and bring approximately 85 new wells online.On the call, CEO John Hess highlighted efficiency gains in the face of inflation. In 2021, the firm’s drilling and completion cost per Bakken well averaged $5.8 million, 6% lower than in 2020. Hess sees the company offsetting anticipated inflation “through lean manufacturing and technology driven efficiency gains.” He sees drilling and completion costs remaining flat in 2022. Overall capital expenditures (capex) will be $2.6 billion in 2022, about 80% of which will go to the Bakken and Guyana, Hess said. The capex figure is 37% higher than in 2021.
Vandalism leads to oil well spill near Watford City – A produced water spill at an oil well near Watford City was due to vandalism. North Dakota Oil and Gas Division officials say valves were opened Sunday on the location, leading to a spill of more than 18,000 gallons. Most of the wastewater had been recovered by vacuum trucks. Produced water is a mixture of saltwater and oil that can contain drilling chemicals. It’s a byproduct of oil and gas development. A state inspector has been to the Abraxas Petroleum Corp. site and will monitor required cleanup.
Judge refuses to delay release of disputed DAPL documents - A state district judge on Friday refused to delay the release of thousands of documents related to security during the construction in North Dakota of the heavily protested Dakota Access Pipeline. South Central District Judge Cynthia Feland in late December ruled that the documents are public and subject to the state's open records law. Attorneys for pipeline developer Energy Transfer asked Feland to put on hold the part of her ruling permitting public disclosure of the records while the company appeals to the state Supreme Court. Feland in a Friday ruling gave Energy Transfer the go-ahead to appeal, but she rejected the request to delay the public release of the records, which the company considers “confidential, proprietary, and privileged documents” that shouldn't be made public. Feland wrote that "Energy Transfer provided no specifics and has failed to provide sufficient information to assess the validity of a claim of privilege or exception that would prohibit the disclosure of even a single document within the 16,000 documents that comprised the disputed documents." The ruling is another victory for The Intercept news organization, which sued in November 2020 to get access to the documents for investigative journalism. The documents are being held by the North Dakota Private Investigation and Security Board, which obtained them during a case involving TigerSwan, the North Carolina company that Energy Transfer hired to oversee security during construction. The records later became entangled in three lawsuits involving the Intercept, TigerSwan and Energy Transfer subsidiary Dakota Access LLC.
North Dakota appeals oil and gas royalty rulings to Supreme Court - The North Dakota Supreme Court will again take up a case concerning oil and gas royalties from the development of state-owned minerals. The state Board of University and School Lands has appealed several 2021 rulings from a lower court in a case involving Newfield Exploration Co. that has had implications for numerous other state oil and gas leases. The appeal challenges part of a 2021 law that put a limit on how far back the state can retroactively collect unpaid royalties, and it raises matters surrounding the state's relationship with Newfield. The state previously brought a breach of contract claim against Newfield for underpaying royalties, but Northwest District Judge Robin Schmidt dismissed the matter last fall. She wrote in an order that she could not find a record of a contract between Newfield and the state among the documents included in the litigation. The state is appealing that decision "to ensure stability and add clarity to the issues," Land Commissioner Jodi Smith said in a statement. Smith leads the North Dakota Department of Trust Lands, which is overseen by the five-member Board of University and School Lands chaired by Gov. Doug Burgum. The group better known as the Land Board has been involved in this dispute for several years. The Supreme Court has heard other issues in the case already and released a ruling in 2019 favorable to the state, which has since sought to collect what could amount to hundreds of millions of dollars in unpaid royalties from a number of oil and gas companies. At the center of the original dispute was whether companies such as Newfield could deduct transportation and gathering costs from royalties paid for the development of state-owned minerals. The Land Board's attempts to collect the money have faced significant pushback from the oil and gas industry, which viewed the state's initial efforts as punitive. The industry backed legislation last year that capped the length of time for which the state could seek to collect unpaid royalties at seven years. Schmidt upheld that law after it passed. The Land Board still takes issue with its retroactive applicability, as the law prohibits the state from collecting royalties owed before August 2013. The state is asking the Supreme Court to consider the matter in its appeal. The Department of Trust Lands has estimated that the state will forgo collecting $69.4 million in royalties owed before August 2013 because of the new limit. Royalty money benefits public education through a number of trusts managed by the board and the department.
Santa Barbara Prosecutors Settle Cuyama River Oil Spill Case - In a case of seriously bad timing for ExxonMobil, the Santa Barbara District Attorney’s office just finalized a settlement with the Bakersfield-based trucking company responsible for a 4,500-gallon oil spill into the Cuyama River not far above Twitchell Reservoir nearly two years ago. While the spill hardly qualifies as the biggest in county oil history, it might well be the most politically inopportune. Its settlement announcement comes just a few weeks before the county supervisors are scheduled to decide the fate of ExxonMobil’s proposal to send up to 78 tanker trucks a day from its plant at Las Flores Canyon to a facility in Kern County by way of Highway 166. The spill in question has been seized upon by environmental critics of the plan as Exhibit A in their argument as to why Highway 166 is not a safe route for such an undertaking. The settlement, while relatively modest in terms of dollars and cents, calls attention to the proposal’s most evident weakness and will make it that much harder for ExxonMobil to garner the votes necessary to reopen its Gaviota plant. Based on the settlement agreement, Golden Valley Transfer Company has agreed to pay $111,326 to the California Department of Fish and Wildlife to help restore the stretch of riverbed contaminated when an oil tanker driven by one of the company drivers — Jesse Villasana — lost control of his rig in the early morning hours of March 21, 2020, while heading into a curve while driving at what prosecutors characterize as “unsafe speed.” In addition, the company will pay a fine of $88,674. Beyond that, the company had already spent $314,320 in cleanup costs. And that doesn’t count the fine imposed last February by the Environmental Protection Agency. As for the driver, Villasana, he’s been fined $515 for his role in the accident. He will also serve a year on probation. During that time, he must perform 20 hours of community service for an environmental organization.
Los Angeles to Prohibit Oil, Natural Gas Drilling, Phase Out Existing Production - The Los Angeles (LA) City Council on Wednesday unanimously approved a motion to prohibit drilling new oil and gas wells, phase out production from existing wells, and establish a plan for plugging and remediating all wells in the city. The city has a total of 5,229 oil wells, including 296 that are idle and the majority within 2,500 feet of homes, schools and hospitals, according to Elected Officials to Protect America (EOPA), an environmental group that supported the measure. “Oil drilling is and has always been an inherently incompatible land use with neighborhoods and schools and hospitals and homes,” said Councilmember Paul Koretz, a co-author of the original motion. “No one should have to wake up in her own bed with a nosebleed caused by toxic oil drilling chemicals. Nor with cancer caused by the same. That said, we must also ensure the affected workers have a secure working future. Today’s item will take care of both.” The motion directs the Department of City Planning (DCP) to draft an ordinance to ban new oil and gas extraction, and to make existing wells a nonconforming land use in all areas of the city. The council also is directing DCP to commission a study to establish a timeline for the phaseout of existing operations. To help ensure an equitable transition for impacted oil and gas workers, the council is directing DCP and to participate in Los Angeles County’s Just Transition Taskforce, EOPA highlighted. Martinez also introduced a motion to create a job quality stabilization program to ensure oil and gas workers can transition to clean energy jobs “while retaining their wages and benefits.” According to EOPA, more than 580,000 Los Angeles residents live within one-quarter mile of a productive oil and gas well.“On behalf of 430 elected officials from 49 counties working to phase out dangerous oil and gas drilling, EOPA California congratulates the LA City Council for their bold leadership to phase out and end the pumping of dirty fossil fuels that continue to devastate communities of color with toxic pollutants that can lead to premature death,” said EOPA’s Dominic Frongillo, executive director. “EOPA California is working statewide to do the same as California transitions with a just transition for workers to a 100%clean energy future.”Upstream operations in Los Angeles include the Inglewood Oil Field operated by Sentinel Peak Resources California LLC. The asset is “the largest contiguous urban oil field in the U.S., with more than one million people living within five miles of the site,” said EOPA, noting that jurisdiction of the field is split between Culver City and LA County. Gov. Gavin Newsom has called for the state to stop issuing new drilling permits by 2024 and to phase out oil and gas extraction entirely by 2045. In October, state regulators launched a proposal to prohibit new wells and facilities within a 3,200-foot exclusion area, or setback, from homes, schools, hospitals, nursing homes and other “sensitive” locations.
Los Angeles bans new oil and gas wells and will phase out old ones over five years - The Los Angeles City Council on Wednesday voted to ban new oil and gas wells and to phase out existing wells over a period of five years, following decades of complaints by residents who have grappled with health problems from living near drilling sites. The measure, introduced by Council members Nury Martinez and Paul Krekorian in December 2020, is part of a broader push by the county and the state of California to establish more distance between drilling and people and transition away from climate-changing fossil fuels. The region includes one of the largest urban oil fields in the country, with more than 5,000 active wells in LA County and more than 1,000 active or idle wells within city limits. More than half a million people in LA live within a quarter-mile of active wells that release air pollutants like benzene, hydrogen sulfide, particulate matter and formaldehyde, and the pollution disproportionately affects Black and Latino residents. "Today, we are reinforcing our commitment to environmental justice," Martinez said during a news conference on Wednesday morning. "For far too long, neighborhood drilling has disproportionally affected the health of our low-income communities of color," Martinez said. "From freeways to power plants, our frontline communities bear the brunt of pollution and climate impacts." Research shows that people who live near oil and gas drilling sites are at greater risk of preterm births, asthma, respiratory disease and cancer. Living close to wells is also linked to weakened lung function and wheezing, according to a study published in the journal Environmental Research. "This is not just a matter of public health and safety … it's also a matter of justice," Jasmin Vargas, a senior organizer at the nonprofit Food & Water Watch, told council members before the vote. "I think this day has been a long time coming." Oil tanks wedged between homes in the Wilmington neighborhood of Los Angeles. Emma Newburger | CNBC The oil and gas industry has strongly opposed such measures, arguing that banning and phasing out oil and gas will hike gas prices and harm jobs. Supporters have urged that the city must ensure that fossil fuel jobs are replaced with clean energy jobs. Rock Zierman, chief executive officer of the California Independent Petroleum Association, an industry group representing nearly 400 oil and gas companies, said the measure would essentially be "taking someone's property without compensation, particularly one which is duly permitted and highly regulated." "Shutting down domestic energy production not only puts Californians out of work and reduces taxes that pay for vital services, but it makes us more dependent on imported foreign oil from Saudi Arabia and Iraq that is tankered into LA's crowded port," Zierman wrote in an email to CNBC.
Quebec Indigenous groups join Questerre Energy in push for natural gas development - Questerre Energy Corp. QEC-T has gained additional First Nations support for its push to develop what it calls a “zero-emissions” natural gas hub in Quebec, ahead of a looming ban by the province on any future oil and gas development. The Indian Resource Council of Canada (IRC), an organization representing more than 130 First Nations that produce energy or have direct interests in the energy industry, issued a statement of support late Wednesday for the proposed project. The hub would be located near Bécancour, Que., on land the Abenaki First Nation of Wolinak considers its traditional territory. The Abenakis last week announced a preliminary deal with Calgary-based Questerre that would give them a share of the profits from development on the land. The Abenakis would also have an opportunity to acquire a working interest in Questerre’s exploration licences and participate in future development. “This project has the full support of the Abenakis and offers innovative solutions to reducing emissions while providing an affordable and reliable source of energy to the market,” IRC president Stephen Buffalo said. “The current proposed ban by the Government of Quebec on oil and gas development is a clear violation of Aboriginal and treaty rights and the IRC will do everything it can to support the Abenakis.” The move by Indigenous groups to back the proposal raises the stakes for Quebec Premier François Legault, whose government is readying new legislation that will put the hydrocarbon development ban into effect. The Premier, who faces an election in October, may be forced to consider whether boosting his environmental credibility is worth roiling First Nations as they try to raise own-source revenue for their communities. Resource estimates suggest Quebec has enough natural gas to meet its own needs for several decades, most of it concentrated in the province’s portion of the Utica shale formation along the southern flank of the St. Lawrence River, in and around the Bécancour region. Early efforts to access the gas, using a technique that fractured the underlying rock, met with significant public opposition. The majority of the deposits remain untapped. Questerre holds the licence rights to more than one million gross acres of farmland in the province. The company’s efforts to develop natural gas projects have been repeatedly thwarted by government moratoriums. Rather than exit the province, Questerre has continued trying to convince decision-makers that it can adopt new production methods that mesh with Quebec’s environmental goals.
'Lack of understanding': Trump's former energy secretary slams Biden's plans to divert gas to Europe - Former U.S. Energy Secretary Rick Perry on Wednesday sharply criticized the Biden administration's contingency plans in the event that Russia cuts off its gas supplies to Europe. His comments come amid growing fears of a potential Russian incursion into Ukraine. President Joe Biden's administration has sought ways to secure energy supplies for European allies in the event that the Kremlin abruptly cuts off flows of oil and gas exports in retaliation for sanctions. "Governments have a really hard time manipulating markets, and I think that's what you're seeing here," Perry told CNBC's Hadley Gamble on Wednesday. The former Texas governor stood down from his role as former President Donald Trump's top energy official in December 2019. "Biden's decision to get on the phone and call around and say: 'Hey, will you guys crank up your LNG exports?' It just doesn't work that way," Perry said, referring to liquefied natural gas. "I think that is the sadness of this administration. Either their lack of understanding of just pure economics or their naivety when it comes to the decisions that they've made about the energy sector [and] about climate change," he added. A spokesperson for the White House was not immediately available to comment when contacted by CNBC. A senior administration official, who declined to be named in order to share details of ongoing plans, said on a call with reporters on Tuesday that the U.S. had been in talks with major natural gas producers to better understand whether they would be prepared to temporarily allocate natural gas supplies to European buyers. A second senior administration official warned the prospect of Russia's weaponization of natural gas or crude oil exports "wouldn't be without consequences to the Russian economy." Western leaders have repeatedly warned Russian President Vladimir Putin that the Kremlin would face a heavy price for invasion.Biden said on Tuesday that he would consider imposing personal sanctions on Putin himself in the event of a war, saying the effects of a possible invasion "would change the world." Russia has amassed an estimated 100,000 troops near the border of Ukraine but denies planning to enter the former Soviet republic.
Dutch industrial gas use down by nearly 100 GWh/d The Netherlands' industrial gas demand in the first two weeks of 2022 was almost 100 GWh/d lower than a year earlier, as companies may have continued to limit production in response to high prices. Combined industrial gas use was about 874TJ — equivalent to about 243 GWh/d — on 3-16 January, the first two full weeks of the new year, data from statistics office CBS Statline show. This was down from 339 GWh/d in weeks 1 and 2 of 2021. The data include consumption from large industrial consumers connected directly to the national transmission system but excludes power plants. Industrial demand fell to just 229 GWh/d on 27 December-2 January, the lowest for any week since at least the start of 2019. This may have been partly because of reduced economic activity following the Christmas holidays and over the New Year holiday period. But the decline at the end of 2021 compared with earlier in December was much more pronounced than in previous years. A renewed rally in European gas hub prices in mid-December may have resulted in some companies continuing to minimise or again turning down production. Some firms, such as fertilizer producers Yara and OCI, turned down production at their Dutch sites in autumn in response to high gas prices. Yara in early December said most of its ammonia production, including that in the Netherlands, was "back on stream or preparing to start up". But this was before gas hub prices climbed to fresh historic highs in mid-December in response to low storage inventories, slow Russian deliveries to Europe and French nuclear shutdowns. Gas prices slipped considerably in late December-early January because of a flurry of LNG tankers turning towards Europe where prices had opened wide premiums to traditional LNG premium markets in northeast Asia. But OCI was still running only one of its two ammonia units at Geleen in mid-January because of high gas prices and other producers may have also reduced output. And while gas use in the chemicals industry — the sector with by far the largest gas consumption — showed signs of recovery in early December, this has stalled in recent weeks. The sector's gas consumption of 125 GWh/d in the first two weeks of this year was still well above the lows of just over 100 GWh/d that it reached in mid-October, but was considerably below the 137 GWh/d it had reached by mid-December. And it was 35 GWh/d lower than the 160 GWh/d registered in weeks 1 and 2 last year. Gas use by the petroleum industry — which in recent months has fallen the most in percentage terms — has continued to slide. The sector's consumption of 16 GWh/d in the first two weeks of this year was only just over a third of the 47 GWh/d in weeks 1 and 2 last year.
Mideast would struggle to cover Russian oil loss -Saudi Arabia, Kuwait and Iraq would struggle to cover the shortfall in crude supply created by a blanket ban on Russian energy exports as they have already allocated their annual term supplies, according to sources close to the matter.Although trading sources say the ensuing European energy crisis will probably steer officials in Brussels and Washington away from strict energy sector sanctions in the event of a Russian invasion of Ukraine, EU foreign ministers and the White House have been deliberating potential retaliatory measures against Moscow should it proceed with military action, and the US has hinted that Russian oil and gas could be included.A blanket ban on Russian oil exports would severely curtail the availability of sour crude at a time when similar-quality supplies from Iran and Venezuela are also subject to sanctions. Russia exports up to 1.5mn b/d of Urals crude from Baltic Sea ports, another 400,000 b/d from the Black Sea terminal at Novorossiysk and up to 800,000 b/d by pipeline to central and eastern Europe.Mideast Gulf producers have comparable quality crude, and Saudi Arabia's Saudi Aramco and Iraq's Somo operate term supply contracts in Europe. Kuwaiti counterpart KPC also sends some limited volumes to the region. But Mideast Gulf sources warn that these three companies would have little room to cover a spike in sour crude demand in Europe in the event of a total embargo on Russian oil, given that they have committed most of their 2022 supplies via term agreements.Aramco, Somo and KPC typically negotiate their annual contracts between late October and early December in the year before loading. Contract volumes depend on producers' projections of their overall output and domestic requirements. Existing term customers can nominate crude in excess of their contracts, but approving such requests is at the discretion of Aramco, Somo and KPC. Vortexa data indicate that seaborne deliveries of Saudi, Kuwaiti and Iraqi crude to northwest Europe and the Mediterranean — including Iraqi exports marketed by the semi-autonomous Kurdistan Regional Government (KRG) — stood at a combined 932,000 b/d last year. All three have a much more significant foothold in Asia-Pacific.Iraq, Kuwait and notably Saudi Arabia have spare production capacity that could be deployed. Their output, as well as Russia's, is currently restricted by the ongoing Opec+ output restraint agreement, but the group might reconsider the pace at which it increases production this year if sanctions are placed on Russian crude. Opec+ delegates acknowledge that the standoff over Ukraine may be contributing to the current oil price rally.
Peru declares environmental emergency in area fouled by oil spill following Tonga volcano eruption - Peru declared an environmental emergency Saturday to battle an oil spill caused by freak waves from a volcanic eruption in the South Pacific. The stunningly powerful eruption last Saturday of an undersea volcano near Tonga unleashed tsunami waves around the Pacific and as far away as the United States. In Peru, the oil spill near Lima has fouled beaches, killed birds and harmed the fishing and tourism industries. With its 90-day decree, the government said it plans "sustainable management" of 21 beaches tarred by 6,000 barrels of oil that spilled from a tanker ship unloading at a refinery last Saturday. One aim of the decree is to better organise the various agencies and teams working in the aftermath of the disaster, said the environment ministry. Foreign Trade and Tourism Minister Roberto Sanchez estimated Saturday that economic losses total more than $50 million, all sectors combined. The government is demanding payment of damages from the Spanish energy giant Repsol which owns the refinery. The environment ministry said 174 hectares – equivalent to 270 football fields – of sea, beaches and natural reserves were affected by the spill. Crews have been working for days to clean up the spill. But the ministry said it issued the emergency decree because the crude still in the water was still spreading, reaching 40 kilometers (25 miles) from the spot of the original spill. The environment ministry said "the spill amounts to a sudden event of significant impact on the coastal marine ecosystem, which has major biological diversity." It said that over the short term, Repsol is responsible for emergency cleanup operations. The refinery is in the town of Ventanilla near Lima. Repsol has said the spill occurred because of the freak waves caused by the eruption. The company has argued that it is not responsible for the spill, however, because it says the government gave no warning that there might be rough waters from that undersea blast. On Saturday, Repsol issued a statement outlining the cleanup operation by 1,350 people using big-rig trucks, skimmers, floating containment barriers and other equipment. Repsol said it is "deploying all efforts to attend to the remediation of the spill." In addition to the fishing industry, Peru's tourism sector has taken a major blow, including everything from restaurants, to beach umbrella rentals to food and beverage sales by vendors. "In a normal season, between January and March (during Peru's summer) five million people visit the affected beaches. The economic loss is immense," Sanchez said, adding that thousands of jobs had been affected and the tourism sector "mortally wounded."
Tonga Volcanic Eruption: Peru Races To Save Seabirds After 6,000-Barrel Oil Spill Poisons Beaches - Peru has declared an environmental emergency after almost 264,000 gallons of crude oil spilled into the sea when a tanker was hit by big waves while offloading at a refinery. A Lima zoo is racing to save dozens of seabirds, including protected penguins, after 6,000 barrels of crude oil spilled off Peru's coast due to waves from a volcanic eruption in the South Pacific. More than 40 birds, including Humboldt penguins -- listed as vulnerable by the International Union for Conservation of Nature -- were brought to the Parque de Las Leyendas zoo after being rescued from polluted beaches and nature reserves. "We have never seen anything like this in the history of Peru," biologist Liseth Bermudez told AFP, while tending to a bird. "We didn't think it was going to be of this magnitude." A team of veterinarians is caring for the birds, bathing them with special detergents to remove the suffocating oil. The animals have also been given anti-fungal and anti-bacterial drugs, as well as vitamins. "The birds' prognosis is unclear," Bermudez said. "We are doing everything we can." Peru has declared an environmental emergency after almost 264,000 gallons (1.2 million liters) of crude oil spilled into the sea last Saturday when a tanker was hit by big waves while offloading at a refinery. The abnormally large waves were triggered by the eruption of an undersea volcano near the archipelago of Tonga, thousands of miles (kilometers) away. The spill near Lima has fouled beaches and harmed the fishing and tourism industries, with crews working non-stop to clean up the mess. The environment ministry said Sunday that more than 180 hectares -- equivalent to around 270 soccer fields -- of beach and 713 hectares of sea were affected, as sea currents spread the spilled oil along the coast. The health ministry has warned would-be bathers to stay away from at least 21 affected beaches. Biologist Guillermo Ramos of Peru's Serfor forestry service said more animals will die if the oil spreads. "There are species here that feed on crustaceans and fish that are already contaminated," he said. Serfor staff have found many dead birds and sea otters on beaches and in natural reserves since the spill, he added. More than 150 bird species in Peru depend on the sea for nutrition and reproduction. Among the birds rescued alive but in need of help are different types of cormorants and six Humboldt penguins. Juan Carlos Riveros, scientific director of rescue NGO Oceana Peru, said the oil could affect the reproductive capacity of some animals and cause birth defects, especially in birds, fish and turtles.
Repsol hopes to move forward quickly to clean up Peru oil spill - .- Spain’s Repsol oil company on Tuesday confirmed that it is “collaborating closely” with Peruvian authorities and civil society “to move forward as quickly as possible on addressing the areas affected by the petroleum spill” that occurred on Jan. 15 off the coast of Lima. The petroleum firm said in a statement that it is “in continuous contact with the communities affected” by the spill “to understand their needs and provide them with the support they need.” In addition to these initiatives, the firm said it is pursuing “other proposals in accord with the requirements that may contribute to achieving long-term agreements.” Repsol also said that it has “intensified cooperation” with the Lima “Park of Legends” zoo, where the animals that have been rescued from amid the floating oil are being housed and cared for. The company also said that it has held meetings with Energy and Mines Minister Eduardo Gonzalez Toro and with the Environmental Assessment and Control Agency (OEFA) to report on the advances made “in all areas of activity” regarding the emergency. “Repsol is sending information daily to the Environment Ministry and communicating to OEFA on the progress on the timetable presented to the authorities, which forecasts the conclusion of clean-up work by the end of February.” In that regard, the firm said that currently more than 2,200 people are participating in cleaning up the ocean waters and the Peruvian coast, and they have been joined by 300 members of the Peruvian armed forces with another 225 people to be added on Tuesday. Involved in these activities are 73 pieces of heavy machinery, nine skimmers for cleaning the ocean waters, 27 large vessels, 90 small vessels and nine floating tanks. Moreover, the firm has installed containment barriers in the water extending 4.44 kilometers (2.75 miles) between the Cavero and Faro Chancay beaches. So far, a total of 10,386 cubic meters (some 367,000 cubic feet) of oil-saturated sand, equivalent to more than 2,000 containers, has been recovered and is being treated to remove the oil so that ultimately it can be returned to the beaches. After stating that it will continue with “ongoing monitoring actions by land, sea and air,” Repsol added that its commitment to the clean-up project “is absolute, as well as (the firm’s) support for the public and attention to the wildlife.” On Jan. 15, some 6,000 barrels of crude oil spilled into the ocean off the Peruvian capital from a vessel that was unloading petroleum into the pipelines at the La Pampilla refinery, which Repsol operates, and over the subsequent days the spill spread over more than 1.8 square km (about 0.7 sq. miles) along the coast and 7.1 sq. km (2.75 sq. mi.) of ocean off Lima and the province of Callao.
Nigeria: Bonga Oil Spill Victims Urge Shell to Pay $3.4bn NOSDRA Fine - Victims of the 2011 Bonga oil spill have demanded that Shell Nigeria Exploration and Production Company (SNEPCO) should immediately pay the sum of $3.4billion fines and awards to them as imposed by the National Oil Spill Detection and Response Agency (NOSDRA). The victims, under the auspices of the Artisan Fishermen Association of Nigeria (AFRAN), Niger Delta Chapter, in a communique issued at the end of their New Year review and agenda-setting meeting in Port Harcourt, insisted that the fine and awards were upheld both by the National Assembly through the House Committee on Environment and the Federal High Court. The communique, which was signed by Chairman, AFRAN Niger Delta Chapter, Pastor Samuel Ayadi and three others, said the Bonga oil spill led to the untimely death of many of the members of the association as a result of the attitude of Shell subsidiary towards the victims. It reads in part: "The Shell Bonga Oil Spill of 20th December, 2011 and the consequent stay away order made by NOSDRA to save the lives of Nigerians especially the fishermen has foisted great hardship on the fishermen plying their livelihoods sustenance trade on the coastal waters. This hardship which has led to the untimely death of many of the members of the Association is as a result of the attitude of Shell towards the victims. "That Shell never empathised with the victims even during the height of the spill impacts even when it had been determined through a Post Impact Assessment that the spill was as a result of operational failures and an estimated 40,000 barrels of crude oil had been pumped into the waters - operational fields of the fishermen/women." "We demand on behalf of all the victims of the Shell (SNEPCO) Bonga Oil Spill which is rated globally as one of the most devastating, that Shell pay immediately the fines/awards of $3.4billion imposed on it by the National Oil Spill Detection and Response Agency (NOSDRA) which fines/awards were upheld both by the National Assembly through the House Committee on Environment and a competent court of the land -the Federal High Court in Lagos. "We demand that should Shell want to appeal against the judgment of the Federal High Court, Lagos, they should show good faith by first lodging the judgment sum with the Registry of the Federal High Court."
Navy to keep eye on oil spill - The Royal Thai Navy has been instructed to expedite the monitoring of an oil spill in the Gulf of Thailand after a tanker carrying 500,000 litres of diesel oil sank on Saturday. VAdm Pokkrong Monthatphalin, spokesman for the navy, yesterday said the First Naval Area Command was told about a sunken vessel, Por Andaman 2, 24 nautical miles off Chumpon province about 7.15pm that day. He said VAdm Pichai Lorchusakul, commander of the First Naval Area, had instructed a fleet of 114 patrol boats and flying units to examine an oil spill that could affect residents living along coastal areas. Multiple markers were placed around the oil spill area to establish a safe perimeter. Each unit of the navy has been instructed to support the Marine Department's clean-up efforts and retrieve the sunken ship, as well as warn residents about the oil spill, he said. The sunken ship's captain, identified as Wayu Moryadee, and five other crewmen were rescued by a fuelling vessel, he said. Thai Laemthong Fishery Oil Trade Co Ltd, owner of the sunken ship, has been notified about the incident and is prepared to help clean up the spill, he said. After the spillage is cleaned, the company must be ready to retrieve the sunken ship and work with the navy to check the safety of its other vessels, he said. An initial probe showed strong winds and rough waters caused the ship's flooding, he said, adding the crew failed to pump the water out and the ship sank, leaking diesel oil in the area. As diesel oil is light and thin, it can naturally decompose, he said.
Thailand rushes to contain oil spill after undersea leak - Thailand's navy and pollution experts battled Thursday to clear up an oil spill close to pristine holiday beaches, after an undersea pipeline leaked up to 50 tonnes of crude. The kingdom's Pollution Control Department has warned that the spill in the Gulf of Thailand, about 20 kilometres (12 miles) off the coast of Rayong province, could threaten a national park in nearby Ko Samet island. Weak currents have kept the oil away from coastal areas and there has been no reported impact on marine life or seafood farming, officials said. Star Petroleum Refining Public Company Limited, which operates the pipeline, said the spill volume was between 20 and 50 tonnes—around 22,000 to 60,000 litres. The company said divers had found a failure in a flexible hose that formed part of the undersea equipment around a single point mooring—a floating buoy used to offload oil from tankers. The Pollution Control Department and other experts are assessing what type of dispersants to use on the spill, officials said at a joint news conference with the navy and other agencies. A pipeline leak in the same area in 2013 led to a major slick that coated a beach on Ko Samet, leaving recovery workers in protective suits to clear up the blackened sand.
Stand-alone natural gas wells driving new growth in Saudi Arabia’s natural gas production Saudi Arabia’s dry natural gas production reached an average of 11 billion cubic feet per day (Bcf/d) for the first time in 2020, a 30% increase from 2010. Oil production cuts related to the December 2016 OPEC+ agreement have reduced Saudi Arabia’s associated natural gas production (natural gas produced as a by-product of oil production). However, the country’s total natural gas output has steadily grown over the past two decades because of the development of non-associated, or stand-alone, natural gas fields. Natural gas produced from non-associated gas fields in Saudi Arabia increased from nothing in 2000 to 46% of total production in 2020. In 2016, Saudi Aramco, the national oil company, began to prioritize the development of non-associated gas fields, located mostly offshore. Saudi Aramco’s strategy includes plans to develop more non-associated natural gas, including unconventional resources, and to further expand natural gas reserves with new reservoirs near existing fields and new discoveries to help meet growing domestic demand. Saudi Arabia’s proved natural gas reserves totaled 333 trillion cubic feet (Tcf) as of January 2021, including those in an area shared with Kuwait known as the Neutral Zone. Saudi Arabia was the sixth-largest natural gas producer in the world behind Russia, Iran, Qatar, the United States, and Turkmenistan in 2020. At the end of 2021, Saudi Aramco awarded contracts to energy companies to develop the country’s largest unconventional field, Jafurah, located to the east of Ghawar oil field near the Persian Gulf. The company expects the Jafurah project to begin production in 2025. Saudi Aramco expects that by 2030, the project will have a maximum capacity of 2 Bcf/d of dry natural gas, 418 million cubic feet per day (MMcf/d) of ethane, and 630,000 barrels per day of condensate. Saudi Arabia does not import or export natural gas, but it expects to begin exporting natural gas by 2030. The government of Saudi Arabia also plans to replace its crude oil, fuel oil, and diesel-powered electric generators with natural gas and renewable energy generation by 2030, which will likely increase domestic natural gas demand. Replacing crude oil with natural gas-fired generation in the electric power sector could make more crude oil in Saudi Arabia available for export. Saudi Arabia has extensive natural gas infrastructure that can capture, process, and transport natural gas to the country’s demand centers. However, the western and southern regions lack sufficient natural pipeline capacity from the eastern fields, where most of the country’s production is located. Saudi Aramco intends to expand its natural gas pipeline capacity along the southwest coast of the country from 9.6 Bcf/d to 12.5 Bcf/d, but it has not announced a completion date yet.
Saudi Aramco sees oil demand near pre-pandemic levels--Saudi Aramco said demand for oil is nearing pre-Covid levels and reiterated that producers globally are investing too little in supply. “We are getting very close to pre-pandemic levels,” Chief Executive Officer Amin Nasser told reporters on Monday in Dhahran, where the world’s biggest oil company is based. “We continue to see healthy demand in the future.” Consumption of crude crashed from around 100 million barrels a day in early 2020 as the coronavirus pandemic spread, shutting down factories and triggering mass lockdowns. The International Energy Agency, which advises rich countries, said it was back to almost 98 million barrels daily as of September. Oil prices have surged 13% this year to more than $85 a barrel as demand continues to recover and the omicron variant of the virus proves less damaging economically than many traders first feared. At the same time, spare supply capacity is dwindling as several major producers struggle to boost output. There’s no sign yet that rising prices are causing consumers to cut back on oil, Nasser said. He and Saudi Arabian officials have previously warned that crude could climb even more if Western governments and energy companies pull back from fossil fuels too quickly. Persian Gulf countries are among the few still spending billions of dollars to increase their output. Saudi Arabia plans to raise its daily crude-production capacity to 13 million barrels from 12 million by 2027.
Opec+ oil producers with spare capacity have upper hand in a reshuffle of 2019 quotas - Oil prices have made a strong start to the year. Opening December below $66 per barrel, Brent crude reached $75 by New Year and touched $89.50 on Thursday. $100 seems within sight and the ability of Opec+ to respond is crucial. The International Energy Agency raised its demand forecasts for this year by nearly 200,000 barrels per day. Both the IEA and Opec grew more sanguine that the economic impact of the Omicron coronavirus variant would be limited. Yet in December, production from group members bound by cuts grew 300,000 bpd, less than the planned 400,000 bpd increase. Overall output is now 650,000-790,000 bpd under the target. Most of the shortfall comes from Angola and Nigeria, the perennial laggards. After a temporary gain in December, exports from Angola’s mature fields are expected to see a further decline of about 100,000 bpd by February. Nigeria also suffers from underinvestment and pandemic-related maintenance shortfalls, as well as endemic unrest, sabotage and theft from pipelines. Algeria was on target in December, but its capacity is slowly declining. But as allocations steadily increase, more and more countries hit their practical ceilings. On the IEA’s figures, Kuwait will probably reach its maximum later this year, and Iraq will be nearing it. The UAE foresaw this problem back in July, when it asked for its baseline production – from which cuts are calculated – to be raised to 3.8 million bpd from 3.168. The UAE Minister of Energy and Infrastructure, Suhail Al Mazrouei, revealed in June 2020 that the country’s capacity was 4.2 million bpd, and it will have increased since then as efforts continue towards a goal of 5 million bpd by 2030. Eventually a compromise was reached, with the baseline set at 3.5 million bpd from this May, and other countries’ allowances also adjusted, notably Russia and Saudi Arabia, who were both awarded 11.5 million bpd. That will speed up production increases – but only for those countries who can deliver. Russia, by far the dominant member of the non-Opec contingent, produced 9.95 million bpd in December, a little below its allowable level, and clearly far under its baseline. It seems to have mostly exhausted its spare capacity, the number of shut-in wells having fallen back to pre-pandemic levels. Additional production gains depend on drilling new wells, a slower process. Instead of restoring its allowed 100,000 bpd each month, the country may manage about 50,000-60,000 bpd.Because of field maturity, production is declining in nearly all the smaller members, and this trend is unlikely to be reversed in the near term. Collectively the Republic of Congo, Gabon, Equatorial Guinea, Sudan, South Sudan, Azerbaijan, Malaysia, Bahrain and Brunei yielded 200,000 bpd lower in December than their allowable level from October.
Oil bulls encouraged by low inventories: Kemp - (Reuters) - Portfolio investors added to their bullish positions in petroleum for the fifth week running as the worst of the latest wave of coronavirus infections passed and governments began to lift restrictions on business and travel. Hedge funds and other money managers purchased the equivalent of 33 million barrels of futures and options in the six most important petroleum-related contracts in the week to Jan. 18. Fund managers have purchased a total of 217 million barrels since Dec. 14, after earlier selling 327 million barrels since Oct. 5, amid mounting fears about the impact of the Omicron variant (https://tmsnrt.rs/3Io5azw). Bullish long positions outnumbered bearish short ones by a ratio of 6.24:1 (in the 80th percentile for all weeks since 2013) last week, up from 3.83:1 (47th percentile) five weeks earlier. The adjustment came from the creation of fresh bullish long positions (+38 million barrels), but new bearish shorts were also established (+5 million) as a few investors anticipated a reversal of the recent rally. In the most recent week, funds purchased NYMEX and ICE WTI (+23 million barrels), European gas oil (+8 million) and U.S. gasoline (+3 million), with no change in U.S. diesel, and small sales in Brent (-2 million). Crude inventories around the NYMEX WTI delivery point at Cushing in Oklahoma are at less than 34 million barrels, down from 41 million in 2019, and the lowest for the time of year since 2012. U.S. inventories of distillate fuel oil are at just 128 million barrels, down from 142 million at this time in 2019, and the lowest since 2014. Reflecting the shortage of petroleum, the front-month NYMEX WTI futures contract has been trading above $85 per barrel at the highest level since 2014. Short-term scarcity has pushed prices for crude delivered in March to around $5.50 per barrel higher than for deliveries deferred until September. Hedge fund managers have anticipated, accelerated and amplified the expected shortage of oil and resulting rise in prices by building large a bullish long position. As their position becomes more lopsided, the risks of reversal have increased, with bullishness almost as high as in October, before the last reversal. But there has been little profit-taking so far, or signs of renewed short-selling, which suggests most funds still see price risks tilted to the upside.
Oil Prices Rise On Supply Fears - Oil prices rose slightly on Monday amid fading Omicron fears and lingering concerns over tightening supplies on the back of geopolitical tensions in Eastern Europe and the Middle East. Brent crude futures for April delivery rose 27 cents, or 0.3 percent, to $87.35 a barrel, while U.S. West Texas Intermediate (WTI) crude futures for March settlement were up 27 cents, or 0.3 percent, at $85.41. Both crude benchmarks rose for a fifth week in a row last week amid demand optimism and signs of dwindling supplies. The World Health Organization (WHO) has for the first time in a while indicated that the pandemic could come to an 'end' in Europe after the current Omicron-driven wave passes over. The U.S. State Department announced Sunday evening it would reduce staff levels at the U.S. Embassy in Kyiv, Ukraine, beginning with the departure of nonessential staff and family members due to the threat of military action from Russia. In the Middle East, the United Arab Emirates (UAE) government has ordered to stop all flying operations of private drones and light sports aircraft in the Gulf country for a month, following a deadly drone attack last week by Yemen's Houthis on the Gulf country. Also, OPEC and its allies continued to struggle to raise their output in line with targets, helping keep sentiment in the oil market bullish.
Oil prices drop as investors brace for interest rate hikes -- Oil prices fell around three per cent on Monday, with both major benchmarks hit by the possibility of quicker than expected interest-rate hikes from the Federal Reserve. Analysts widely anticipate a bump in interest rates from the current level of 0-0.25 per cent over the coming weeks, which has proven a major headwind to sustained market rallies in recent weeks. Brent Crude has dropped to $85.46 per barrel, with prices plummeting 2.76 per cent while WTI has fallen by over three per cent to $82.43. Prices initially rallied this morning amid heightened political tensions between Russia-Ukraine, but faded as grim news arrived of a looming spike in interest rates. Nevertheless, the two benchmarks are up 10 per cent this year, but hopes of prices reaching $100 have dampened as the US has rebuilt its oil inventories, offsetting shortfalls from OPEC and its allies in recent months.
Oil falls 2% as Fed rate hike talk spooks risk markets - Oil prices fell on Monday, hit by a stronger dollar and investor concerns over the possibility of quicker than expected increases to interest rates by the U.S. Federal Reserve. Brent crude fell $1.62, or 1.8%, to end the day at $86.27 per barrel. West Texas Intermediate (WTI) crude settled 2.15% lower, or $1.83, at $83.31 per barrel. The dollar rose to a two-week high on Monday against a basket of currencies, lifted by the tension between Russia and the West over Ukraine and the possibility of a more hawkish stance from the Fed this week. Brent had risen more than a $1 earlier in the session on concerns over tight supplies and elevated geopolitical risks in Europe and Middle East. Further escalation of the situation in both Ukraine and the Middle East "justify a risk premium on the oil price because the countries involved – Russia and the UAE – are important members of OPEC+", said Commerzbank analyst Carsten Fritsch. Tensions in Ukraine have been increasing for months after Russia massed troops near its borders, fuelling fears of supply disruption in Eastern Europe. In the Middle East, the United Arab Emirates intercepted and destroyed two Houthi ballistic missiles targeting the Gulf country on Monday after a deadly attack a week earlier. Barclays, meanwhile, has raised its average oil price forecasts by $5 a barrel for this year, citing shrinking spare capacity and elevated geopolitical risks. The bank raised its 2022 average price forecasts to $85 and $82 a barrel for Brent and WTI respectively. Both benchmarks rose for a fifth week in a row last week, gaining about 2% to reach their highest since October 2014. Oil prices are up more than 10% this year on the concerns over tightening supplies and OPEC+ now struggling to hit a targeted monthly output increase of 400,000 barrels per day.
Oil Off Lows on Tighter Supplies -- Following a sharp selloff triggered by a surging U.S. dollar and volatility in stock markets, oil futures bounced higher in overnight activity to trade little changed, supported by prospects of short-term supply scarcity on the global oil market tied to concerns over OPEC+'s ability to quickly raise production joined by escalating tensions in Eastern Europe and Middle East that heightened geopolitical risk premium in oil prices. Near 7:30 a.m. ET, West Texas Intermediate futures for March delivery faded overnight gains to trade near $83.38 per barrel (bbl) after jumping above $84 bbl in overnight trading, and international crude benchmark Brent advanced $0.35 to $86.60 bbl. Both benchmarks fell as much as 2% on Monday. NYMEX February RBOB futures gained more than 1 cent to trade near $2.4094 gallon, and the front-month ULSD contract traded little changed near $2.6269 gallon. Oil's move higher came despite ongoing strength in the U.S. dollar index that spiked more than 0.3% against a basket of foreign currencies to near 96.215 level. Greenback continues to find support on expectations that the Federal Open Market Committee might tighten monetary policy more aggressively than previously expected to rein in surging inflation that came in at 7% in December -- the highest in 40 years. FOMC begins its two-day policy meeting today and is expected to signal the first interest rate hike in three years in March, while unwinding its monthly bond purchases. The Fed is currently buying $60 billion of bonds each month -- half the level prior to the November taper and $30 billion less than in December. Goldman Sachs forecasts at least four hikes in the federal funds rate this year. CME Group's FedWatch tool sees a small chance for the central bank to announce a rate hike Wednesday, and overwhelmingly a 25-basis point increase on March 16 when FOMC meets next. The VIX volatility measure in the stock market, surged to the highest level in nearly a year ahead of the statement from the Federal Reserve along with some of the key economic data in the United States. On Thursday, Bureau of Economic Analysis will release its first estimate of a fourth quarter gross domestic product, followed by Fed's preferred inflation gauge- personal consumption expenditures for the final month of 2021. Stocks on Wall Street staged a dramatic turnaround in the last 15 minutes of cash trading Monday to finish broadly higher after Dow Jones Industrial plunged more than 1000 points mid-session. Oil futures moved off intrasession lows with the reversal in equities.
Oil prices rebound as fears of Russia invading Ukraine rise - Oil prices have recovered from a slight hiccough over recent days, amid growing fears of Russian invading Ukraine and a consequent tightening in supplies. While increases in US oil inventories headed off shortfalls in production from multiple OPEC members and initially dampened rallies on both major benchmarks, the growing potential for conflict in Eastern Europe has caused prices to rise again. Currently, the US is in talks with major energy-producing countries such as Qatar and companies around the world over a potential diversion of supplies to Europe if Russia invades Ukraine. The US previously ruled out military action in Ukraine following talks between US President Joe Biden and Russian premier Vladimir Putin, instead warning of potential sanctions. However, it has now placed 8,500 troops on alert to be ready to deploy to Europe in case of an escalation in the Ukraine crisis, which the Kremlin said it was watching with great concern. The International Monetary Fund has also warned any conflict between Russia and Ukraine could result in sustained price hikes . Gita Gopinath, the fund’s deputy managing director, gloomily argued yesterday that conflict would mean “further increase in prices of oil and natural gas, and therefore of energy costs more broadly, for many countries in the world”. Alongside fears of reduced supplies from Ukraine-Russia tensions, there are also continued issues with underinvestment in the sector as banks make it harder for oil giants to invest and acquire loans. The market is also awaiting for US inventory reports from the American Petroleum Institute (API) and the US Energy Information Administration (EIA), which will both be published later this week. Biden is keen to head off high oil prices ahead of the mid-terms in November and reduce the cost of living for millions of Americans. Previous calls from Biden for OPEC and its allies to increase production above current rates of 400,000 extra barrels per day have so far fallen on deaf ears. In fact, multiple members are failing to even reach their relatively modest production increases amid capacity issues and fears of a supply glut this quarter. “I expect we’ll continue to see more of the same message from the White House as they can’t be seen to be doing nothing. But his hand is quite weak and it would take a massive release of reserves to make any real difference, which won’t be easy to do. And ultimately, OPEC+ could easily offset it.” “Whether or not Biden will intervene is purely a political, not markets question. That being said, if oil goes over $100 a barrel before the midterm elections, I would not be surprised if the Biden Administration decided to make another symbolic release of reserves. In reality, it is unlikely to have any meaningful or lasting effect on the price of oil.”
Oil Rebounds After Focus Shifts to Steady Demand Outlook - Oil prices rallied Tuesday after the biggest one-day tumble this year, with traders refocusing on the outlook for strong demand and the risk that a Russia-Ukraine conflict could disrupt supplies. West Texas Intermediate futures settled above $85 a barrel as fears about fresh lockdowns and a hit to global demand due to the omicron variant eased. Prices have whipsawed as the U.S. Federal Reserve prepares for interest-rate increases, while Russia builds troops along the border with Ukraine. “Crude prices are soaring on expectations that an already tight oil market could see geopolitical risks exacerbate the current imbalance,” said Ed Moya, Oanda’s senior market analyst for the Americas. “The risks are not just with the Russia-Ukraine border, but also include Iran nuclear talks and also North Korea.” In recent months, oil bears have retreated with speculators turning more bullish amid lower stockpiles. Crude rallied to a seven-year high last week as global consumption remained strong in the face of the fast-spreading, but milder, omicron variant. While inventories usually grow early in the year, traders are fretting that by the Northern Hemisphere’s summer, when demand typically rises, stockpiles may be too low to prevent a jump in prices. “Markets have proved to be tighter than we thought,” said David Martin, head of commodity desk strategy at BNP Paribas. He see small reductions in inventories this quarter, “and that underpins this view that the market continues to tighten up.” Inventories in key regions have tightened with stockpiles at Cushing, Oklahoma, the delivery point for benchmark U.S. crude futures, sliding to the lowest levels in more than five years seasonally. The market is also skeptical the Biden administration can do anything to slow down oil’s move higher as OPEC+ seems set to stick to gradual production increases, Moya said. The U.S. Energy Department announced that it loaned another 13.4 million barrels as part of an 32 million barrel exchange program announced in November, aiming to ease a rise in domestic gasoline prices. WTI for March delivery jumped $2.29 to settle at $85.60 a barrel in New York. Brent for the same month rose $1.93 to $88.20. The U.S. is putting thousands of soldiers on alert for deployment to Eastern Europe. The risk of a Russian invasion of Ukraine in the next few weeks stands at more than 50%, according to RBC Capital Markets analyst Helima Croft. Disruption to oil flows from Russia could easily send prices to $120 a barrel, JPMorgan Chase & Co. wrote last week. Costlier oil is helping fan inflationary pressures worldwide, prompting central banks to tighten monetary policy and forcing governments to take steps to cushion the impact on consumers. On Tuesday, Japan said it will give subsidies to refiners in a bid to curb gasoline prices.
Oil Prices Stable After API Reports Small Crude Draw - The American Petroleum Institute (API) estimated the inventory draw this week for crude oil to be 872,000 barrels after analysts predicted a draw of 400,000 barrels. U.S. crude inventories shed some 75 million barrels since the start of 2021, and about 17 million barrels since the start of 2020. In the week prior, the API reported a build in crude oil inventories of 1.404 million barrels after analysts had predicted a draw of 1.367 million barrels. Oil prices were trading up on Tuesday in the run-up to the data release, erasing Monday's losses in just the latest bout of price volatility with geopolitical concerns and strong demand pushing prices up, and fed moves and a strong dollar pushing prices down. WTI was trading up 2.36% to $85.28 on the day at 3:00 p.m. EST but down roughly $2 per barrel on the week. Brent crude was trading up by 2.16% at $88.13 on the day and down roughly $0.60 per barrel on the week. U.S. oil production continues to climb. For the week ending January 14—the last week for which the Energy Information Administration has provided data—crude oil production in the United States held fast at 11.7 million bpd. This is down 1.4 million bpd from the pre-pandemic era. Last week, the API reported the third build in a row for gasoline inventories, at 3.463 million barrels. This week, the API reported a build in gasoline inventories at 2.4 million barrels for the week ending January 21—on top of the previous week's 3.463 million barrel build. Distillate stocks saw a decrease in inventory of 2.2 million barrels for the week, after last week's 1.179 million barrel decrease. Cushing saw a 1 million-barrel decrease this week. At 4:43 pm, EST, WTI was trading at $85.08, with Brent trading at $87.78.
Brent Tops $90 As Oil Prices Dip Then Rip After US Inventory Data -- Dip-buyers charged in to buy oil after an initial dip following DOE's report of a surprise crude inventory build. WTI is up near $88. And Brent broke above $90... That is the first time Brent is above $90 since October 2014... A string of Wall Street banks including Goldman Sachs have forecast oil will hit $100 a barrel this year as the global market tightens.Prices are also moving on mounting concern over a possible Russian incursion into Ukraine, with President Biden saying he’d consider sanctioning Vladimir Putin if the Russian leader orders an invasion. Oil prices are dramatically extending yesterday's gains, despite a smaller than expected crude draw reported by API, as the tension between the West and Russia over Ukraine continues to add to geopolitical risk premia. “Crude prices are soaring on expectations that an already tight oil market could see geopolitical risks exacerbate the current imbalance,” “The risks are not just with the Russia-Ukraine border, but also include Iran nuclear talks and also North Korea.” In another bullish development for oil prices, more Chinese are expected to travel for the Lunar New Year holiday this year than in the previous two years, despite the Omicron spread, in a boost to fuel consumption in the world’s largest crude oil importer, according to data cited by Bloomberg.For now, all eyes will be on gasoline demand and crude inventories. API
- Crude -872k (-2.1mm exp)
- Cushing -1.0mm
- Gasoline +2.4mm (+2.2mm exp)
- Distillates -2.2mm (-1.6mm exp)
DOE
- Crude +2.377mm (-2.1mm exp)
- Cushing -1.823mm
- Gasoline +1.297mm (+2.2mm exp)
- Distillates -2.798 (-1.6mm exp)
The official crude inventory data surprised the market with a 2.377mm build (vs 2.1mm draw expected and a small draw reported by API). Cushing saw its 3rd straight week of draws. Gasoline stocks grew but at less than expected while distillate inventories fell most since early December... Graphics Source: BloombergGasoline demand remains drastically low - even assuming seasonals... Source: BloombergUS Crude production slipped to its lowest since November...The 4 week average volumes for U.S. crude exports are struggling to rise above the 3m b/d mark. This is despite perceptions that foreign demand is robust against a backdrop of supply shortages. But a pick up is expected in the weeks to come as Chinese refiners resume purchases for delivery after the Winter Olympics.Bloomberg's Danny Adkins notes that jet fuel inventories are at their lowest seasonal level in EIA data going back to 1992, despite a modest build last week. Stockpiles have held below 35 million barrels for four straight weeks, the first time they have done so since 1996.WTI is holding just above $87 (up $2 from last night's API report) ahead of the official data and slipped very modestly on the surprise build...Finally, we note that it would seem President Biden's sabre-ratlling in Eastern Europe are not helping his cause at home...
WTI Spikes 2.5% on Cushing Stock Draw, Lower Crude Output -- Oil futures nearest delivery on the New York Mercantile Exchange spiked in late morning trade Wednesday in reaction to weekly inventory data showing total U.S. crude and petroleum product supplies declined during the third week of January amid lower oil production and recovering demand for motor gasoline, while a large drawdown from Cushing stockpiles -- the delivery point for West Texas Intermediate futures -- rallied WTI futures towards $88 barrel (bbl). Around noon New York time, March WTI futures spiked $2.20 bbl to $87.80 bbl, February RBOB futures surged 6.5 cents to $2.5245 gallon, with front-month ULSD futures rallying more than 7 cents to $2.7429 gallon. Total U.S. crude and oil products stocks decreased 4.1 million bbl from the previous week to 1.78 billion bbl, about 7% below the five-year average. Included in the drawdown was a 2.8 million bbl decline realized in distillate fuel stocks that pressed distillate inventories to 17% below the five-year average. Demand for middle of the barrel fuels surged 198,000 barrels per day (bpd) from the previous week to 4.754 million bpd -- the highest weekly demand rate since early December 2021. In the gasoline complex, demand also recovered, gaining 281,000 bpd to 8.505 million bpd, up more than 8% against a year ago. Gasoline stockpiles increased by 1.3 million bbl from the previous week to 247.9 million bbl compared with analyst expectations for inventories to have increased by 2.3 million bbl. U.S. commercial crude oil inventories increased for only the second time in the past nine weeks last week, rising 2.4 million bbl to 416.2 million bbl -- still about 7% below the five-year average. Markets mostly expected crude stockpiles would fall by 800,000 bbl from the prior week. Larger-than-expected crude build was realized as domestic refiners scaled back run rates by 0.4% last week to 87.7% compared with expectations for a 0.3% decrease. Oil stored at the Cushing delivery hub in Oklahoma fell 1.8 million bbl from the previous week to 31.7 million bbl. At this level, Cushing inventories stand more than 30% below the five-year average and at the lowest since October 2018. After holding steady at the beginning of January, U.S. crude oil production unexpectedly fell by 100,000 bpd last week to 11.6 million bpd, according to the EIA. U.S. crude production is still 1.4 million bpd below March 2020 level when COVID-19 pandemic shut-in a large chunk of domestic output.
Global oil benchmark tops $90 for the first time since 2014 -- Brent crude futures, the international oil benchmark, topped $90 on Wednesday for the first time since 2014, adding to oil's blistering recovery since its pandemic-era lows in April 2020. The threshold breakthrough comes amid growing geopolitical tensions between Russia and Ukraine, and as supply remains tight amid a rebound in demand. The contract added more than 2% at one point to hit a high of $90.47 per barrel for the first time since October 2014. However, Brent pulled back slightly in afternoon trading, ultimately settling 2% higher at $89.96 per barrel. West Texas Intermediate crude futures, the U.S. oil benchmark, settled 2.04% higher at $87.35 per barrel. During the session the contract hit a high of $87.95, a price last seen in October 2014. Rebecca Babin said potential sanctions on Russia, which would be triggered by a Ukraine invasion, would be a catalyst for higher crude prices. Goldman Sachs said Wednesday the firm's base case is that supply disruptions are unlikely to occur, but that there could be upside for energy prices given an already tight market. "Commodity markets are increasingly vulnerable to disruptions, after a couple years of historically low outages following the initial Covid shock," the firm wrote in a note to clients. "Against the backdrop of the tightest inventory levels in decades, low spare capacity and a much less elastic shale sector, this points to the skew of large energy price moves shifting to the upside, reinforcing the case for a rising allocating to commodities in portfolios." Earlier this month, Goldman Sachs said that Brent can reach $100 per barrel by the third quarter, adding to a number of Wall Street firms calling for triple-digit oil. Barclays noted that while prices may be reacting in part to a "geopolitical premium," the underlying fundamentals are fueling the push higher. OPEC and its oil-producing allies have been returning crude to the market, but the group's been unable to ramp up production to hit its targets. Meanwhile, U.S. shale oil growth has slowed, and omicron hasn't been the demand hit that was initially expected. Additionally, inventory levels remain depleted. The Energy Information Administration said Wednesday that crude oil inventories rose by 2.4 million barrels during the week ended Jan. 21. The Street was expecting an increase of just 150,000 barrels, according to estimates compiled by FactSet.
Oil Hits 7 Year High Amid International Concerns | Rigzone -- Brent oil surged above $90 for the first time in seven years before paring as the market fretted over Russia-Ukraine tensions. Futures in New York closed 2% higher, with the global benchmark touching $90 a barrel earlier in the session on Wednesday. Concerns are mounting over a possible Russian incursion into Ukraine, with U.S. President Joe Biden saying he’d consider sanctioning Vladimir Putin if the Russian leader orders an invasion. A potential conflict carries large risks for financial markets -- especially energy commodities such as natural gas and oil. Inventories at the largest U.S. oil hub fell 1.8 million barrels for the third week in a row while total domestic stockpiles rose modestly. The oil market’s structure has surged in recent days, signaling tight supply. “How the sanctions would impact Russian oil production getting into the market is the concern,” said Rob Thummel, Tortoise portfolio manager. “In a global oil market that’s having a hard time with supply keeping up with the demand, less Russian oil supply would temporarily push up prices.” Crude is having a volatile week, slumping Monday then rebounding Tuesday. Prices are at a seven-year high with demand continuing to recover from the pandemic as mobility picks up. A string of Wall Street banks including Goldman Sachs Group Inc. have forecast oil will hit $100 a barrel this year as the global market tightens. Adding to tighter market constraints, OPEC+ is expected to stick to their plan and ratify another modest production increase next week. Prices: West Texas Intermediate for March delivery rose $1.75 to settle at $87.35 a barrel in New York. Brent for March settlement rose $1.76 to settle at $89.96 a barrel. In the EIA weekly report, Cushing crude stockpiles fell for the third week in a row last week to 31.7 million barrels, getting close to the 30--million-barrel level that traders watch as a warning signal for low inventories. Draws in the storage hub are a key reason why the WTI prompt spread is rallying to levels last seen in November.
Easing Ukrainian Tensions Doesn't Halt Oil Rally - Following an explosive rally triggered by fears of an imminent Russian invasion in the Ukraine and potential disruption to European gas supplies, oil futures nearest delivery on the New York Mercantile Exchange and Brent crude traded on the Intercontinental Exchange advanced early Thursday following an offer of a "diplomatic path" out of the crisis from the United States and the North Atlantic Treaty Organization -- a move Russia described as a positive step to diffuse the tensions. Russia's foreign minister Sergei Lavrov said this morning that it will take some time for Moscow to analyze NATO's response and it would not rush to make any decision. Germany, the European Union's largest economy, has so far refused to send weapons to the Ukraine, saying there could never be a military solution to this crisis. Germany draws more than half of its gas imports from Russia against around 40% on average for the European Union, according to EU's statistics agency Eurostat. That alone limits options to sanction Moscow should it invade Ukraine considering the risk Moscow could retaliate by cutting off the supply. Nord Stream 2 -- the natural gas pipeline completed late last year that still awaits formal approval by German regulators, would double the capacity for Russian gas exports to the country. The geopolitical concerns for oil futures comes ahead of a handful of economic data, with investors awaiting the release of the first estimate of U.S. gross domestic product for the fourth quarter and durable goods orders for the final month of 2021, with both reports on tap for an 8:30 AM ET release. High-frequency data suggests U.S. economic growth softened in the first weeks of the year, hammered by the vicious spread of Omicron and worker absenteeism amid ever-changing quarantine guidelines from the U.S. Centers for Disease Control and Prevention. Weekly jobless claims jumped by more than 40% to 286,000 in the first three weeks of January, with fresh data to be released this morning. Consumer sentiment has weakened once again at the start of the year as inflation surged to the highest level in 40 years at 7% in December. Against this backdrop, U.S. Federal Reserve signaled it was readying the first interest rate hike in more than three years later in the first quarter, as it unwinds ultra-easy monetary policy. Beginning in February, the Fed will increase its holdings of Treasury securities by at least $20 billion per month and mortgage ?backed securities by at least $10 billion per month, reducing total monthly purchases by $30 billion. In early trade, West Texas Intermediate futures for March delivery advanced $0.88 to trade near $88.24 per barrel (bbl), and international crude benchmark Brent crude jumped above $90 bbl, gaining $0.93 in overnight trade. NYMEX February RBOB futures rallied 2.15 cents to $2.5442 gallon, and the front-month ULSD contract surged 2.8 cents to $2.7720 gallon.
Oil falls from seven-year high as Russia tensions offset Fed tightening - Oil prices fell on Thursday after Brent crude hit a seven-year high above $90 a barrel, as the market balanced concerns about tight worldwide supply with expectations the U.S. Federal Reserve will soon tighten monetary policy. Global benchmark Brent fell 62 cents to settle at $89.34 a barrel, while U.S. crude closed 74 cents lower at $86.61 a barrel in a volatile session with both contracts see-sawing between positive and negative territory. Prices had surged on Wednesday, with Brent climbing above $90 a barrel for the first time in seven years amid tensions between Russia and the West. Threats to the United Arab Emirates from Yemen's Houthi movement had added to oil market jitters. Russia, the world's second-largest oil producer, and the West have been at loggerheads over Ukraine, fanning fears that energy supplies to Europe could be disrupted, although concerns are focused on gas supplies rather than crude. Russia said it was clear the United States was not willing to address Moscow's main security concerns in their standoff over Ukraine, but kept the door open for dialogue. U.S. Under Secretary of State for Political Affairs Victoria Nuland said the United States hopes Russia will study what Washington has offered and come back to the table. "The market is very erratic on headlines on the Russia-Ukraine situation," said Phil Flynn, senior analyst at Price Futures Group. "There's uncertainty about what's going to happen." Weighing on prices, the U.S. Federal Reserve said on Wednesday it was likely to raise interest rates in March and planned to end its bond purchases that month to tame inflation. The U.S. dollar climbed after the announcement, making oil more expensive for buyers using other currencies. On Thursday, the dollar index climbed to the highest since July 2021. "A more pronounced price slide is being prevented by the Ukraine crisis, as there are still concerns that Russian oil and gas deliveries could be hampered in the event of a military escalation," Commerzbank said after the morning price dip. The market is starting to turn its attention to a Feb. 2 meeting of the Organization of the Petroleum Exporting Countries (OPEC) and allies led by Russia, a group known as OPEC+. OPEC+ is likely to stick with a planned rise in its oil output target for March, several sources in the group told Reuters. It has raised its output target each month since August by 400,000 barrels per day (bpd) as it unwinds record production cuts made in 2020. However, the group has faced capacity constraints that have prevented some members from producing at their quota levels.
Oil Futures Reverse Higher Friday Morning -- Oil futures nearest delivery reversed higher in early morning trade Friday, with all petroleum contracts heading for their sixth consecutive weekly advance spurred by falling U.S. crude oil stockpiles and heightened geopolitical risk related to tensions along the Russian-Ukrainian border and the threat of another missile attack on Gulf oil infrastructure from Iranian backed Houthis militia in Yemen. Near 7:30 a.m. ET, West Texas Intermediate futures for March delivery advanced $0.62 to $87.24 per barrel (bbl), and international crude benchmark Brent crude edged above $90 bbl -- the highest trade since July 2014. NYMEX RBOB February contract gained 2.64 cents to $2.5474 gallon and the front-month ULSD contract rallied 3.49 cents or 2.3% to $2.8294 gallon, supported by ongoing robust U.S. demand for middle distillates. Total crude oil stockpiles held by industrialized countries declined for the third consecutive month in December, according to the International Energy Agency, which has pressed inventories to their lowest level in seven years. In the United States alone, inventories held in Cushing storage tanks -- the delivery point for WTI futures -- stand at their lowest since October 2018 and 30% below the five-year average. Globally, OPEC+ producers have struggled to raise shut-in crude production in line with their agreed monthly quota of 400,000 bpd, with several key members of the alliance, including Russia and Nigeria, are speculated to have hit their output ceiling. A structural supply deficit from OPEC+ producers, as well as laggard recovery of U.S. shale output means oil prices could go even higher. Investors will look towards the next OPEC+ meeting on Feb. 2 for the group's decision on production and output levels for March. The alliance is expected to maintain its gradual unwinding of production cuts and proceed with its planned 400,000 barrel-per-day (bpd) output hike for the final month of the first quarter. Amid tightening fundamentals, the oil market is particularly sensitive to the risk of supply disruption. Tensions between Russia, a major oil producer, and Ukraine, a major conduit for natural gas supplies to the European Union, have been partly responsible for driving the Brent contract above $90 bbl. Limiting the upside for the oil complex is a rallying U.S. dollar index that gained 0.18% against a basket of foreign currencies in early trading to trade near 97.420. The greenback rallied Thursday on better-than-expected reading on U.S. gross domestic product that surged 6.9% in the final three months of 2021 compared with an expected 5.7% annual growth rate. The reading marked the fastest expansion of U.S. GDP since the third quarter 2020 when the economy roared back from pandemic-induced lockdown measures.
Oil heads for sixth weekly gain amid supply concerns --Oil prices rose on Friday, set for their sixth weekly gain, amid concerns of tight supplies as major producers continue their policy of limited output increases amid rising fuel demand. Brent crude futures settled 69 cents, or 0.77%, higher at $90.03 per barrel, after falling 62 cents during the previous day. However, prices did reach $91.04 earlier in that session, the highest since October 2014. U.S. West Texas Intermediate (WTI) crude futures settled 21 cents higher at $86.82 per barrel, having declined 74 cents on Thursday. WTI also reached a seven-year high of $88.54 earlier in the session. Both Brent and WTI are set to rise for a sixth week, the longest weekly streak since October, when Brent prices climbed for seven weeks while WTI gained for nine. This year, prices have gained about 15% amid geopolitical tensions between Russia, the world's second-largest oil producer and a key natural gas provider to Europe, and the West over Ukraine as well as threats to the United Arab Emirates from Yemen's Houthi movement that have raised concerns about energy supply. "Where Brent crosses $90 level, we see some selling from a sense of accomplishment, but investors start buying again when the prices fall a little as they remain cautious about possible supply disruptions due to rising geopolitical tensions," said Tatsufumi Okoshi, senior economist at Nomura Securities. "The market expects supply will stay tight as the OPEC+ is seen to keep the existing policy of gradual increase in production," he said The market is focusing on a Feb. 2 meeting of the Organization of the Petroleum Exporting Countries (OPEC) and allies led by Russia, a group known as OPEC+. OPEC+ is likely to stick with a planned rise in its oil output target for March, several sources in the group told Reuters. An increase in oil output by producer nations cashing in on expensive crude has depleted the cushion of spare capacity that protects the market from sudden shocks and raised the risk of price spikes or even fuel shortages. "OPEC has been struggling to increase output in line with the agreed rise in quotas ... In effect, spare capacity is at a level which may not be enough to cover any geopolitical disruptions," analysts from ANZ Research said in a note on Friday. "We see the market remaining in deficit in Q1 2022. With supply constraints likely to be a feature of the oil market for a while, we see markets pricing in a sizeable risk premium," said ANZ, adding that it raised its short-term oil price target to $95 per barrel. On the demand side, crude oil imports in China, the world's biggest importer of the commodity, could rebound by a much as 7% this year, reversing 2021's rare decline as buyers step up purchases for new refining units and to replenish low inventories, analysts and oil company officials said.
UAE repels drone attack, while Iranian-backed rebels vow more- Yemen’s Iranian-backed Houthi group targeted the United Arab Emirates on Monday for the second time in a week, raising concerns of an escalation in the oil-exporting region even as the Gulf nation said it had intercepted the strike. Oil gained, remaining near the highest levels since 2014 as geopolitical tensions and the prospect of improving demand pushed crude to five straight weekly gains. Brent crude traded near $90 a barrel on Monday after reports of the attack. Shrapnel fell over scattered areas of Abu Dhabi after military defenses repelled two ballistic missiles, but there was no damage or loss of life, the UAE Defense Ministry said in a statement. The UAE said it had destroyed the launchers in Yemen’s northern Al Jawf region, more than 1,270 kilometers (790 miles) from Abu Dhabi, immediately after the missiles were fired and was “taking all necessary procedures to protect the country.” The strike comes barely a week after Abu Dhabi suffered its first deadly attack in Yemen’s seven-year conflict, with the Houthis warning international investors to leave and vowing to expand their range of targets in a country that’s built its economy and attracted millions of expatriates on the back of its reputation as a safe harbor in a volatile region. The U.S. embassy in Abu Dhabi issued a rare alert urging its “citizens in the United Arab Emirates to maintain a high level of security awareness” and offering detailed advice on how to cope with missile strikes. The escalation comes at a critical time for regional diplomacy; Iran’s longtime support of the Houthis means the incidents could upset fragile diplomatic efforts to ease frictions with Gulf Arab neighbors as well as broader negotiations to restore Tehran’s 2015 nuclear deal with world powers. Houthi spokesman Yahya Saree said in a televised speech on its Al-Masirah TV Monday that the group targeted the Al Dhafra military air base in Abu Dhabi and attacked several targets in the UAE’s commercial capital of Dubai using drones. There was no confirmation of any attack on Dubai. Last week’s missile and drone attack on Abu Dhabi killed three people and wounded six, igniting a fire at the airport and setting fuel trucks ablaze. Drones have made it possible to conduct small, targeted assaults that slip through multibillion-dollar defense systems designed to deter more advanced weapons. The physical damage -- both on land and at sea -- is usually minimal but the reputational impact could still be huge for the UAE, OPEC’s third biggest oil producer.
Scores killed in Saudi-led airstrikes, highlighting US-Saudi war crimes --The last few days have seen a sharp escalation in the number of airstrikes by the Saudi-led coalition against its impoverished, southern neighbour Yemen, with a series of horrific attacks on civilian infrastructure and buildings that have played no part in the seven-year-long war. The attacks amount to crimes under the Fourth Geneva Convention. On Friday, a Saudi airstrike on a detention center in Saada, northern Yemen, housing African migrant workers transiting through Yemen to Saudi Arabia, killed at least 82 people and wounded 266 more, with the number of casualties expected to climb as paramedics dig through the rubble. A separate attack on a telecommunications center in the port city of Hodeidah shut down the country’s internet and killed three children playing nearby. Netblocks, which monitors internet blockages, described Yemen as experiencing “a nation-scale collapse of internet connectivity,” while the aid agency, the Norwegian Refugee Council, described the strike as “a blatant attack on civilian infrastructure that will also impact our aid delivery.” Earlier this week, the UN said that this month’s violence could soon surpass that witnessed in December, when 358 civilians were killed or injured, as a result of an alarming number of airstrikes, drones and rockets used against civilians and non-military targets. According to the humanitarian aid organization Save The Children, the last three months of 2021 witnessed a 60 percent increase in civilian casualties. There has been ferocious fighting in the Marib and Shabwa districts in southern Yemen, the last regional stronghold of the Saudi-backed government and location of most of the country’s oil reserves, as the Houthis reached the outskirts of Marib city. Its fall would signify the definitive end of the regime headed by President Abdu Rabbu Mansour Hadi, who long ago fled to Riyadh. In the last few days, pro-Hadi fighters, aided by scores of Saudi airstrikes and UAE-funded and trained proxies, including the Giants Brigade, have pushed back the Houthis, killing hundreds of Houthi fighters. This in turn prompted the Houthis to launch a drone attack on Abu Dhabi, capital of the United Arab Emirates (UAE), on Monday that killed three people and wounded six. On Tuesday, Saudi air strikes killed 20 people, including several civilians, in the capital and largest city Sanaa, where Houthi websites show horrifying scenes of women, children and the elderly alongside ruined homes, hospitals and clinics without medication and operating theaters lit by flashlights because there is no electricity. Other strikes on water treatment facilities have left more than 120,000 people in the capital without access to clean drinking water. None of these atrocities could have been carried out without the fighter jets, bombs, weaponry, materiel, training, maintenance and logistical support, including targeting intelligence and aerial refuelling for Saudi planes, supplied by the US and UK. Washington and London have backed the Saudi-led coalition in its onslaught which began in 2015, providing it with political and diplomatic cover at the UN.
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