Written by rjs, MarketWatch 666
Here are some selected news articles from the week ended 13 February 2021. Part 2 is available here.
This is a feature at Global Economic Intersection every Monday evening or Tuesday morning.
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Oil prices at 13 month high; US oil supplies at a 42 week low*; global oil supply and demand balanced
* Erroneously stated as a 45 week low last week.
Oil prices finished higher for a second straight week on progress towards a US economic stimulus package and on a big drop in US crude inventories….after rising 9% to $56.85 a barrel last week on ongoing OPEC production cuts and on the economic stimulus package making its way through Congress, the contract price of US light sweet crude for March delivery opened higher on Monday on supply cuts among key producers and hopes for further U.S. economic stimulus and never looked back, settling $1.12 higher at $57.97 a barrel while the global benchmark Brent crude settled above $60 a barrel for the first time since January of last year…US oil prices edged up early on Tuesday, reaching their highest in 13 months, as supply cuts by major producers and optimism over a recovery in fuel demand supported energy markets, with US crude rising 39 cents to $58.36 a barrel, led by gains in Brent, which rose for an eighth straight day and topped $61 a barrel…oil prices opened higher again on Wednesday on the American Petroleum Institute’s report of a larger than expected drop in crude inventories and held those gains as the EIA reported an even larger drop in oil supplies and finished trading 32 cents higher at $58.68 a barrel, with global prices posting the longest streak of price gains in over two years, supported by producer supply cuts and hopes that vaccine rollouts would drive a recovery in fuel demand….but the rally in oil prices snapped on Thursday after both OPEC and the International Energy Agency (IEA) said renewed lockdowns and the emergence of new coronavirus variants reduced the prospect of a swift demand recovery. and US crude settled 44 cents lower at $58.24 a barrel as technical analysis showed both benchmarks remained in overbought territory…nonetheless, the oil price rally resumed on Friday as progress towards a new stimulus boosted hopes for increased fuel demand, and then jumped to settle $1.23, or more than 2% higher at $59.47 a barrel, after the Houthis’ air force hit an airport and air base in Saudi Arabia with a drones attack…hence the March oil contract finished the week 4.6% higher, with US oil prices ending at their highest since early January of last year..
Natural gas prices also finished the week modestly higher, as forecasts for bitter cold over most of the Lower 48 threatened to turn the natural gas storage surplus into a deficit….after jumping 11.7% to $2.863 per mmBTU last week on forecasts for continuing below normal temperatures through the end of February, the contract price of natural gas for March delivery opened higher and pushed towards $3 early Monday, but pulled back from the highs on weather model volatility to settle just 1.9 cents higher at $2.882 per mmBTU…Monday’s reversal continued on Tuesday, with March gas prices shedding 4.7 cents with the brutal cold circulating through the Lower 48 seen fading before month’s end and a more seasonal pattern to follow thereafter…but natural gas prices rebounded on Wednesday to finish 7.6 cents higher at $2.911 per mmBTU as the frigid air penetrating the north/central United States stalled, leaving large population centers to bear sub-zero temperatures….gas prices then slipped 4.3 cents on Thursday as the cold air outbreak was seen weakening later this month and the weekly storage report disappointed traders, but rebounded again on Friday to close 4.4 cents higher at $2.912 per mmBTU, as bitter cold temperatures blanketed the Lower 48, and threatened to freeze off output throughout most of the country’s production basins, and thus finished the week 1.7% higher than the prior Friday’s close…
The natural gas storage report from the EIA for the week ending February 5th indicated that the amount of natural gas held in underground storage in the US fell by 171 billion cubic feet to 2,518 billion cubic feet by the end of the week, which left our gas supplies 9 billion cubic feet, or 0.4% below the 2,527 billion cubic feet that were in storage on February 5th of last year, and 152 billion cubic feet, or 6.4% above the five-year average of 2,366 billion cubic feet of natural gas that have been in storage as of the 5th of February in recent years….the 171 billion cubic feet that were drawn out of US natural gas storage this week was a bit less than the average forecast of a 175 billion cubic foot withdrawal from an S&P Global Platts survey of analysts, but way more than the 121 billion cubic foot withdrawal from natural gas storage seen during the corresponding week of a year earlier, and also more than the average withdrawal of 125 billion cubic feet of natural gas that have typically been pulled out of natural gas storage during the same week over the past 5 years…
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending February 5th indicated that despite a drop in our oil exports, we still had to withdraw oil from our stored commercial crude supplies for the tenth time in the past twelve weeks and for the 23rd time in the past thirty-five weeks…. our imports of crude oil fell by an average of 650,000 barrels per day to an average of 5,857,000 barrels per day, after rising by an average of 1,443,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 866,000 barrels per day to 2,617,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 3,240,000 barrels of per day during the week ending February 5th, 216,000 more barrels per day than the net of our imports minus our exports during the prior week…over the same period, the production of crude oil from US wells increased by 100,000 barrels per day to 11,000,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production appears to total an average of 14,240,000 barrels per day during this reporting week…
US oil refineries reported they were processing 14,793,000 barrels of crude per day during the week ending February 5th, 152,000 more barrels per day than the amount of oil they used during the prior week, while over the same period the EIA’s surveys indicated that a net of 973,000 barrels of oil per day were being pulled out of the supplies of oil stored in the US….so based on that reported & estimated data, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from storage, and from oilfield production was 420,000 barrels per day more than what our oil refineries reported they used during the week….to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a (-420,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the average daily supply of oil and the data for the average daily consumption of it balance out, essentially a balance sheet fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting that there must have been an error or errors of that magnitude in the oil supply & demand figures that we have just transcribed….furthermore, since last week’s fudge factor was at +575,000 barrels per day, there was a 995,000 barrel per day balance sheet difference in the unaccounted for crude oil figure from a week ago, which renders the week over week supply and demand changes we have just transcribed unreliable….however, since most everyone treats these weekly EIA figures as gospel and since these figures often drive oil pricing and hence decisions to drill or complete wells, we’ll continue to report them as published, just as they’re watched & believed to be accurate by most everyone in the industry…..(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 5,868,000 barrels per day last week, which was 12.0% less than the 6,671,000 barrel per day average that we were importing over the same four-week period last year…..the 973,000 barrel per day net withdrawal from our crude inventories was due to a 949,000 barrels per day withdrawal from our commercially available stocks of crude oil, and a 24,000 barrel per day withdrawal from our Strategic Petroleum Reserve, space in which is being leased for commercial purposes….this week’s crude oil production was reported to be 100,000 barrels per day higher at 11,000,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was 100,000 barrels per day higher at 10,500,000 barrels per day, while a 1,000 barrel per day decrease to 507,000 barrels per day in Alaska’s oil production had no impact on the rounded national total….last year’s US crude oil production for the week ending February 7th was rounded to 13,000,000 barrels per day, so this reporting week’s rounded oil production figure was 15.4% below that of a year ago, yet still 30.5% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016…
Meanwhile, US oil refineries were operating at 83.0% of their capacity while using those 14,793,000 barrels of crude per day during the week ending February 5th, up from 82.3% of capacity during the prior week…however, since US refinery utilization had averaged the lowest on record through 2020 and has barely recovered, the 14,793,000 barrels per day of oil that were refined this week were still 7.7% fewer barrels than the 16,020,000 barrels of crude that were being processed daily during the week ending February 7th of last year, when US refineries were operating at an also low 88.0% of capacity…
Wth the increase in the amount of oil being refined, the gasoline output from our refineries was higher for the 4th time in 12 weeks, increasing by 236,000 barrels per day to 8,656,000 barrels per day during the week ending February 5th, after our gasoline output had decreased by 253,000 barrels per day over the prior week…but since our gasoline production is still recovering from a multi-year low in the wake of this Spring’s covid-related lockdowns, this week’s gasoline output was still 6.3% lower than the 9,241,000 barrels of gasoline that were being produced daily over the same week of last year….meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 38,000 barrels per day to 4,660,000 barrels per day, after our distillates output had increased by 104,000 barrels per day over the prior week….but since our distillates’ production is also recovering from a three year low, that output was 3.7% less than the 4,837,000 barrels of distillates that were being produced daily during the week ending February 7th, 2020…
With the increase in our gasoline production, our supply of gasoline in storage at the end of the week increased for the 10th time in thirteen weeks, and for 14th time in 31 weeks, rising by 4,259,000 barrels to 252,153,000 barrels during the week ending February 5th, after our gasoline inventories had increased by 4,467,000 barrels over the prior week…our gasoline supplies increased this week even as the amount of gasoline supplied to US users increased by 87,000 barrels per day to 7,857,000 barrels per day, as our exports of gasoline fell by 43,000 barrels per day to 737,000 barrels per day, while our imports of gasoline rose by 99,000 barrels per day to 657,000 barrels per day….but even after this week’s inventory increase, our gasoline supplies were still 1.8% lower than last February 7th’s gasoline inventories of 261,049,000 barrels, and near the five year average of our gasoline supplies for this time of the year…
Even with the increase in our distillates production, our supplies of distillate fuels decreased for the 16th time in 24 weeks and for the 29th time in the past year, falling by 1,732,000 barrels to 161,106,000 barrels during the week ending February 5th, after our distillates supplies had decreased by 9,000 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 110,000 barrels per day to 4,308,000 barrels per day, and because our imports of distillates fell by 162,000 barrels per day to 356,000 barrels per day and because our exports of distillates rose by 13,000 barrels per day to 956,000 barrels per day…but even after this week’s inventory decrease, our distillate supplies at the end of the week were still 14.1% above the 141,222,000 barrels of distillates that we had in storage on February 7th, 2020, and about 7% above the five year average of distillates stocks for this time of the year…
Finally, even with the big drop in our oil exports, our commercial supplies of crude oil in storage (not including the commercial oil being stored in the SPR) fell for the 21st time in the past twenty-nine weeks, and for the 24th time in the past year, decreasing by 6,645,000 barrels, from 475,659,000 barrels on January 29th to 469,014,000 barrels on February 5th, the lowest oil inventory level since March 20th…but even after that decrease, our commercial crude oil inventories were about 2% above the five-year average of crude oil supplies for this time of year, and 38.4% above the prior 5 year (2011 – 2015) average of our crude oil stocks as of the first week of February, 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 during the lockdowns this spring after generally rising over the past two years, except for during the past 8 weeks and during the past two summers, after generally falling over the year and a half prior to September of 2018, our commercial crude oil supplies as of February 5th were still 6.0% more than the 442,468,000 barrels of oil we had in commercial storage on February 7th of 2020, 4.9% above the 447,207,000 barrels of oil that we had in storage on February 8th of 2019, and also 11.6% more than the 420,254,000 barrels of oil we had in commercial storage on February 2nd of 2018…
OPEC’s Monthly Oil Market Report
Thursday of this past week saw the release of OPEC’s February Oil Market Report, which covers OPEC & global oil data for January, and hence it gives us a picture of the global oil supply & demand situation after OPEC, the Russians, and other oil producers agreed to increase their oil production by 500,000 barrels per day during January from their prior commitment to cut production by 7.7 million barrels a day from an October 2018 peak, which had been earlier reduced from the 9.7 million barrels a day cuts they had imposed on themselves during May, June and July….again, before we look at what this month’s report shows us, we should again caution that estimating oil demand while the course of the Covid-19 pandemic remains uncertain is pretty speculative, and hence the demand estimates we’ll be reporting this month should again be considered as having a much larger margin of error than we’d expect from this report during stable and hence more predictable periods..
The first table from this monthly report that we’ll check is from the page numbered 47 of this month’s report (pdf page 57), and it shows oil production in thousands of barrels per day for each of the current OPEC members over the recent years, quarters and months, as the column headings indicate…for all their official production measurements, OPEC uses an average of estimates from six “secondary sources”, namely the International Energy Agency (IEA), the oil-pricing agencies Platts and Argus, the U.S. Energy Information Administration (EIA), the oil consultancy Cambridge Energy Research Associates (CERA) and the industry newsletter Petroleum Intelligence Weekly, as a means of impartially adjudicating whether their output quotas and production cuts are being met, to thereby avert any potential disputes that could arise if each member reported their own figures…
As can be seen from the above table of their oil production data, OPEC’s oil output increased by 181,000 barrels per day to 25,496,000 barrels per day during January, up from their revised December production total of 25,315,000 barrels per day…however, that December output figure was originally reported as 25,362,000 barrels per day, which therefore means that OPEC’s December production was revised 47,000 barrels per day lower with this report, and hence January’s production was, in effect, a rounded 134,000 barrel per day increase from the previously reported OPEC production figure (for your reference, here is the table of the official December OPEC output figures as reported a month ago, before this month’s revisions)…
From the table above, we can see that a 89,000 barrels per day increase in the Saudi’s production, an increase of 72,000 barrels per day in Venezuela’s output, and a production increase of 62,000 barrels per day from Iran were the major factors in OPEC’s January output increase, while several OPEC members failed to take advantage of the new agreement to increase production…recall that last year’s original oil producer’s agreement was to cut production by 9.7 million barrels per day from an October 2018 baseline for just two months early in the pandemic, during May and June, but that agreement had been extended to include July at a meeting between OPEC and other producers on June 6th….then, in a subsequent meeting in July, OPEC and the other oil producers agreed to ease their deep supply cuts by 2 million barrels per day to 7.7 million barrels per day for August and subsequent months, which was thus the agreement that covered OPEC’s output for the rest of 2020…the agreement for January’s production, which has now been extended to include February’s output, was to further ease their supply cuts by 500,000 barrels per day to 7.2 million barrels per day from that original baseline…however, war torn Libya and US sanctioned OPEC members Iran and Venezuela had been exempt from the production cuts imposed by these agreements, and as we can see above, Iran and Venezuela both saw major increases this month…
Since there had never seemed to be a published table or listing available of how much each OPEC member was expected to produce under the eased production cuts of August through December, or the new ones for January, we had been including the table that shows the original October 2018 reference production for each of the OPEC members (as well as other producers party to the mid-April agreement), as well as the production level each of those producers was expected to cut their output to during May, June, and July…we’ll include that table once again now, though with two modifications to that agreement since, it becomes more difficult to compute the production quotas that each of the OPEC members was expected to hold to in January:
The first column in the above table shows the oil production baseline, in thousands of barrel per day from which each of the oil producers was to cut from, a figure which is based on each of the producer’s October 2018 oil output, ie., a date before last year’s and the prior year’s output cuts took effect, and coincidently the highest monthly production of the era for most of the producers who are party to these cuts; the second column shows how much each participant had originally committed to cut during May and June in thousands of barrel per day, which was 23% of the October 2018 baseline for all participants except for Mexico, while the last column shows the production level each participant had agreed to after that cut…the producer’s agreement for August through December of last year amended the above such that each member would be allowed to reduce their production cut shown above (ie, the “voluntary adjustment” shown above) by 20%…for example, Algeria’s “cut” was expected to be 241,000 barrels per day from May thru July, which would reduce their oil production to 816,000 barrels per day over that period…under the agreement for August through December, Algeria would reduce their “cut” by 20%, or to 193,000 barrels per day, thus allowing them to produce 864,000 barrels per day during those months…with the agreement for January, Algeria would be able to reduce their production cut by another 5% from the “voluntary adjustment” figure shown above, or to 181,000 barrels per day, thus allowing them to produce 876,000 barrels per day during January….offhand, by comparing the above table’s voluntary allocation less 25% from the initial OPEC production cut, it appears that Equitorial Guinea, Gabon and Kuwait had all exceeded their revised allocation during January, but that the group as a whole still remained below the quota they would have been allowed to produce for the month…
The next graphic from this month’s report that we’ll highlight shows us both OPEC and world oil production monthly on the same graph, over the period from February 2019 to January 2021, and it comes from page 48 (pdf page 58) of the February OPEC Monthly Oil Market Report….on this graph, the cerulean blue bars represent OPEC’s monthly oil production in millions of barrels per day as shown on the left scale, while the purple graph represents global oil production in millions of barrels per day, with the metrics for global output shown on the right scale….
After the reported 181,000 barrel per day increase in OPEC’s production from what they produced a month earlier, OPEC’s preliminary estimate indicates that total global liquids production increased by a rounded 430,000 barrels per day to average 93.12 million barrels per day in January, a reported increase which apparently came after December’s total global output figure was revised down by 240,000 barrels per day from the 92.93 million barrels per day of global oil output that was reported a month ago, as non-OPEC oil production rose by a rounded 250,000 barrels per day in January after that revision, with oil production increases of 290,000 barrels per day from the OECD countries alone accounting for more than the total non-OPEC production increase in January…
After that increase in January’s global output, the 92.93 million barrels of oil per day that were produced globally in January were 7.33 million barrels per day, or 7.3% less than the revised 100.26 million barrels of oil per day that were being produced globally in January a year ago, which was the first month of additional production cuts of 500,000 barrels per day in an attempt to support prices (see the February 2020 OPEC report (online pdf) for the originally reported January 2020 details)…with this month’s increase in OPEC’s output, their January oil production of 25,496,000 barrels per day was at 27.4% of what was produced globally during the month, an increase from their revised 27.3% share of the global total in December….OPEC’s January 2020 production, which included 537,000 barrels per day from former OPEC member Ecuador, was reported at 28,858,000 barrels per day, which means that the 13 OPEC members who were part of OPEC last year produced 2,825,000, or 10.0% fewer barrels per day of oil in January 2021 than what they produced a year earlier, when they accounted for 28.8% of global output…
However, even after the increase in OPEC’s and global oil output that we’ve seen in this report, there was still a small shortfall in the amount of oil being produced globally during the month, as this next table from the OPEC report will show us…
The above table came from page 26 of the February Oil Market Report (pdf page 36), and it shows regional and total oil demand estimates in millions of barrels per day for 2020 in the first column, and OPEC’s estimate of oil demand by region and globally quarterly over 2021 over the rest of the table…on the “Total world” line in the second column, we’ve circled in blue the figure that’s relevant for January, which is their estimate of global oil demand during the first quarter of 2020… OPEC is estimating that during the 1st quarter of this year, all oil consuming regions of the globe will be using an average of 93.22 million barrels of oil per day, which is a 950,000 barrels per day downward revision from the 94.17 million barrels of oil per day of demand they were estimating for the first quarter a month ago (note that we have encircled this month’s revisions in green), still reflecting quite a bit of coronavirus related demand destruction compared to 2019, when global demand averaged 99.98 million barrels per day….but as OPEC showed us in the oil supply section of this report and the summary supply graph above, OPEC and the rest of the world’s oil producers were producing 93.12 million barrels million barrels per day during January, which would imply that there was a modest shortage of around 100,000 barrels per day in global oil production in January when compared to the demand estimated for the month..
In addition to the revision the first quarter’s global oil demand, you can see encircled in green that OPEC has also revised global demand for 2020 upwards by 250,000 barrels per day, which thus means that the supply shortfalls or surpluses that we previously reported for last year would need to be revised….a month ago we estimated a global shortage of around 370,000 barrels per day in global oil production during December, based on the figures that were published at that time…however, as we saw earlier, December’s global output figure was was revised down by 240,000 barrels per day from those figures, while global demand for the 4th quarter of 2020 was revised 330,000 barrels per day higher, so with those revised figures, we now find that global oil production in December was running roughly 940,000 barrels per day short of demand…
Besides figuring December’s revised global oil supply shortfall that’s evident in this report, the upward revision of 330,000 barrels per day to November’s global oil output means that the 1,210,000 barrels per day global oil output shortage we had previously figured for November would now be revised to a shortage of 1,540,000 barrels per day..,similarly, the 2,510,000 barrels per day global oil output shortage we had previously figured for October would now be revised to a shortage of 2,840,000 barrels per day once we account for the 330,000 barrels per day upward revision to fourth quarter demand…
As part that upward revision of 250,000 barrels per day in 2020 global demand, OPEC revised 3rd quarter 2020 demand higher by 220,000 barrels per day, revised 2nd quarter 2020 demand higher by 270,000 barrels per day, and revised first quarter 2020 demand higher by 170,000 barrels per day…those revisions mean that theglobal oil supply shortfall we had previously reported for the third quarter months would have to be revised higher by 220,000 barrels per day, that the large global oil surpluses we had previously reported for the second quarter months would have to be revised lower by 270,000 barrels per day, and that the record global oil surplus we had previously reported for March and the surpluses for the other first quarter months would have to be revised lower by 170,000 barrels per day…
This Week’s Rig Count
The US rig count rose for the 21st time in the past twenty-two weeks during the week ending February 12th, but for just the 23rd time in the past 48 weeks, and hence it is still down by virtually half over that forty-seven week period….Baker Hughes reported that the total count of rotary rigs running in the US rose by 5 to 397 rigs this past week, which was still down by 393 rigs from the 790 rigs that were in use as of the February 14th report of 2020, and was also still 7 fewer rigs than the all time low rig count prior to 2020, and 1,532 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began to flood the global oil market in their first attempt to put US shale out of business….
The number of rigs drilling for oil increased by 7 rigs to 299 oil rigs this week, after rising by 4 oil rigs the prior week, still leaving us with 372 fewer oil rigs than were running a year ago, and still less than a fifth of the recent high of 1609 rigs that were drilling for oil on October 10th, 2014….at the same time, the number of drilling rigs targeting natural gas bearing formations fell by 2 rigs to 90 natural gas rigs, which was also down by 20 natural gas rigs from the 110 natural gas rigs that were drilling a year ago, and just 5.6% of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008…in addition to those rigs drilling for oil or gas, one rig classified as ‘miscellaneous’ continued to drill in Lake County, California this week, while a year ago there were two such “miscellaneous” rigs deployed…
The Gulf of Mexico rig count increased by 1 to 17 rigs this week, with 15 of those rigs now drilling for oil in Louisiana’s offshore waters and 2 drilling for oil in Alaminos Canyon offshore from Texas…that was 6 fewer Gulf of Mexico rigs than the 23 rigs drilling in the Gulf a year ago, when 20 Gulf rigs were drilling for oil offshore from Louisiana, one rig was drilling for natural gas in the Mississippi Canyon offshore from Louisiana, another rig was drilling for natural gas in the West Delta field offshore from Louisiana, and one rig was drilling for oil offshore from Texas…since there are no rigs operating off of other US shores at this time, nor were there a year ago, this week’s national offshore rig figures are equal to the Gulf rig counts….however, in addition to those rigs drilling in the Gulf, one rig continues to drill through an inland body of water in Lafourche Parish, south of New Orleans, while a year ago there were no rigs drilling on US inland waters..
The count of active horizontal drilling rigs was up by 2 to 344 horizontal rigs this week, which was still less than a half of the 713 horizontal rigs that were in use in the US on February 14th of last year, and less than a third of the record of 1372 horizontal rigs that were deployed on November 21st of 2014…at the same time, the vertical rig count was up by 3 to 23 vertical rigs this week, but those were still down by 7 from the 30 vertical rigs that were operating during the same week a year ago….meanwhile, the directional rig count was unchanged at 18 directional rigs this week, and those were also down by 29 from the 47 directional rigs that were in use on February 14th of 2020….
The details on this week’s changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes…the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of February 12th, the second column shows the change in the number of working rigs between last week’s count (February 5th) and this week’s (February 12th) count, the third column shows last week’s February 5th 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 14th of February, 2020..
It appears that most of this week’s rig changes took place in Texas…checking first for the details on the Permian in Texas from the Rigs by State file at Baker Hughes, we find that there were 3 new rigs added in Texas Oil District 8, which corresponds to the core Permian Delaware, that one rig was added in Texas Oil District 8A, which encompasses the northern counties of the Permian Midland basin, and that another rig was added in Texas Oil District 7B, which includes the easternmost counties of the Permian in Texas, thus accounting for the 5 rig increase in the Permian nationally…elsewhere in Texas, there there was an oil rig added in Texas Oil District 1, there was another oil rig added in Texas Oil District 2, and there was a natural gas rig pulled out of Texas Oil District 4, which together account for the one rig addition in the Eagle Ford shale, which stretches in a narrow band through the southeast counties of the state…there was also a natural gas rig pulled out of the Haynesville shale in Texas Oil District 6, hence accounting for the two rig decrease in natural gas drilling…other changes nationally include the rig addition offshore from Louisiana, a rig addition in North Dakota’s Williston basin, and a rig pulled out of an Oklahoma basin that Baker Hughes does not identify…
Will drilling deal find new life? – The proposal to frack around LaDue Reservoir is off the table, but for how long? After a groundswell of objections, Akron Mayor Dan Horrigan last week removed the proposed legislation from the City Council agenda. The mayor said his action was prompted by concerns of people from both inside and outside of Akron. He was, however, “troubled” by the “misinformation used to stir up community concern when our primary objective is to safeguard the health, economic mobility and safety of our residents.” Misinformation? Perhaps the lack of information – timely information – resulted in the public outcry. Akron Public Service Director Chris Ludle told council members in January, when the proposal first hit the agenda, that the city had been working on the deal with DP Energy Auburn, LLC for about a year. Yet some council members said that was news to them. The proposal called for Akron to lease mineral rights to DP Energy, allowing the company to use hydraulic fracturing to pressurize wells to break up underground rocks at LaDue and release gas and oil deposits. The proposal involved 475 acres around LaDue in Geauga County, with the company paying Akron a one-time fee of $237,500, or $500 per acre, and 15 percent of the royalties on natural gas and oil extracted from the well. Drilling would not have been conducted on the city’s land, but mineral rights would have allowed the company to extract the underground resources. Though in Geauga County, LaDue is owned by Akron as part of its drinking water supply. The mayor, clearly unhappy about the public reaction and the need to nix the deal, emphasized the financial aspect, saying the city lost an opportunity to increase revenue and help keep utility bills in check for Akron residents. He also cited a need to finance a federally mandated $1.2 billion sewer project. That project price tag is a far cry from the one-time, quarter-million payment Akron would have received from DP Energy. The mayor denied the proposed deal had anything to do with campaign or political influence. But some critics pointed out that paperwork to create DP Auburn Energy was filed this year by former Akron councilman Patrick D’Andrea, a longtime friend of the mayor. It is clear this proposal was not vetted properly by the administration and council. With so many concerns, the proposal had to be stopped. There are too many unanswered questions. Geauga residents and officials need to keep a watchful eye out to ensure a drilling deal around LaDue remains off the table.
Unused Gas Well Spews What’s Suspected to Be Frack Waste, Killing Fish – Ohio regulators are working at a gas well that started spewing what’s believed to be brine water from fracking into the environment more than a week ago. The Ohio Department of Natural Resources, which regulates the oil and gas industry, said in an email that it was notified on Sunday, January 24 that fluid, what the agency called “produced brine,” was spraying out of an oil and gas well in the Crooked Tree area near Dexter City in Noble County. Brine is a salty byproduct of gas and oil production and can contain toxic metals and radioactive substances, according to US EPA. This video posted to Facebook by Amber Deem shows what she says is liquid spraying out of the well and pooling on the ground. Deem told The Allegheny Front in a phone call that the Parkersburg, West Virginia company where said she works owns this well, and that it hadn’t produced gas in years. Deem has now said she is awaiting advice from her attorney before commenting further. Chasity Schmelzenbach, director of Noble County Emergency Management, was informed by Ohio DNR about the incident at the well, which is owned by Genesis Resources LLC of Parkersburg. On Wednesday, January 27, the state was able to contain the spray in a collection system on-site, Schmelzenbach said, but not before the suspected brine killed fish in Taylor Fork, a small tributary. She said state regulators had wildlife experts at the scene. “The chloride counts are really high, that’s why the fish kill happened, they believe,” Schmelzenbach said. “Typically brine doesn’t kill fish, so the concentrations had to be pretty high in that small area.” Ohio DNR said brine continues to flow at the wellhead. So far it has collected, and disposed of more than 30,000 barrels of fluid from the site. The agency has not determined where the liquid originated, or why it suddenly started spewing from the old gas well. There have been no injuries or evacuations and the extent of impact to the environment is not yet known. Noble County is home to around ten frack wastewater injection wells, according to Schmelzenbach and state mapping, some a few miles from the incident. In late 2019,brine from an injection well in Washington County, Ohio migrated to several producing gas wells, some more than five miles away. Since 2017, there have been seven spills of frack waste in Noble County, including this one, according to Ohio EPA records.
Ohio Regulators Investigating Source of Brine Shooting from Well — Ohio environmental regulators investigating the source of brine that began shooting from a gas well in Noble County and continued to flow for almost two weeks before contractors were able to stop it. The Ohio Department of Natural Resources (ODNR) said preliminary testing indicates that the fluid was brine, which is a highly salty water that is produced during the hydraulic fracturing process and can contain chemicals, metals and radioactive substances. Brine can also be produced naturally from oil and gas operations that do not involve fracking, and the source of the spill is not yet known, according to a statement from Sarah Wickham, ODNR chief of communications. Contractors brought in by ODNR have so far collected about 40,000 barrels of fluid during their mitigation efforts. The ODNR was notified of the spill on Jan 24 and contractors were called in to build an emergency containment system, and begin mitigation efforts to prevent fluid from flowing into a nearby stream. However, about 500 fish and other aquatic species were killed. Within 48 hours, ODNR instructed the contractors to build a “more substantial system of containment structures, pipes and storage tanks to prevent the fluid from entering the environment,” until the flow was finally stopped on Feb. 4. The vertical well, Ohio Power/Gant 17-69, is owned by Genesis Resources of Parkersburg, W.Va. The well is located only a few miles from three underground injection wells, where fracking wastewater that can no longer be reused is injected into deep geological formations. Ohio is home to more than 200 injection wells, and much of Pennsylvania’s fracking waste is sent there. There are just 10 injection wells in Pennsylvania. In 2019, brine from an injection well in Washington County, Ohio, migrated to three producing wells at least five miles away. Washington County sits just to the south of Noble County in eastern Ohio. Efforts to add more injection wells in Pennsylvania have been met with opposition from environmental groups. Plans to put an injection well in Indiana County stalled after a legal fight with the township and an environmental group, while the state Department of Environmental Protection in 2020 approved plans for well in Plum Borough, Allegheny County, after a six-year battle. These types of wells are often controversial, as there is research indicating that they may negatively affect groundwater quality and cause unintended seismic activity in the area near the well, and Ohio’s experience may prove valuable in determining their future use in Pennsylvania.
Lorain County pipeline Nexus continues attempts to reduce tax bill – Lorain County is in the midst of a dispute with Nexus over attempts by the company to devalue pipeline infrastructure which has troubled local officials. Lorain County Commissioner Matt Lundy said Feb. 3 a move by Nexus in challenging the value of its natural gas pipeline could have a devastating impact on local school districts with reduced tax revenue. Attempts by the company to reduce the valuation from an original assessment of $127 million down to around $50 million is a problem, Lundy said. The Ohio Department of Taxation already has reduced the company’s assessment to $111 million, he said. “But the big part of their presentation was tax dollars that were going to come into Lorain County because of the value of that pipe in that system,” Lundy said. “And I’m disappointed to see that once again, Nexus is back at the table in the state with the Ohio Department of Taxation seeking Reduced values and lower values.” Under the proposed plan, Lorain County alone could lose $955,000 in annual tax revenue with local school districts taking big revenue hits. Firelands Local School District would lose $606,200; Keystone Local Schools; $915,000; Midview Local Schools would drop $882,000; and Oberlin City Schools is set to lose over $1 million annually. This an economic impact that Lundy says will hurt schools and communities. “The sad part is that these kinds of fights can go on for years, and while the fight goes on for years, the company can make the assertion that they’re only going to pay what they think the value is,” he said. “So, this is going to have a very negative impact on our schools and on our communities.” Lundy encourages residents to write to their legislators and tell them the concern and the impact it will have. The Nexus Gas Transmission is a 256-mile natural gas transmission pipeline that crosses through parts of Michigan and Ohio, including Lorain and Medina counties. Lundy previously called the actions by the company a “bait and switch” stating it has not held up its end of the bargain in the commitments made to Lorain County. The pipeline has been operational since 2018 following fierce opposition from the city of Oberlin. In a previous statement to The Morning Journal on the pipeline assessment in December 2019, Nexus spokesperson Adam Parker said the company was committed to paying a “fair and justified tax.” “Consistent with how individuals, homes and businesses are taxed, our property tax assessment should reflect the true market value of the pipeline,” Parker said. “After reviewing the preliminary assessment, we have elected to file a petition for reassessment through the formal process established by the Ohio Department of Tax. “Nexus is committed to paying a fair and justified property tax based on the true market value of the pipeline, and looks forward to developing future economic and taxing opportunities in Ohio.”
Panel discusses economic future of oil and gas – Martins Ferry Times Leader – An organization affiliated with environmentalist groups says it soon will produce studies suggesting that the oil and gas industry is on an economic decline and that a proposed ethane cracker plant should not become a reality in Eastern Ohio.Panelists from the Ohio River Valley Institute, a think tank focused on “lasting job growth, clean energy, and more inclusive civic structures for northern Appalachia,” held a discussion Wednesday. Speakers at the economic forum included: Kathryn Hipple, professor of finance at Bard College and former financial analyst with the Institute for Energy Economics and Financial Analysis; John Hanger, energy consultant and former Pennsylvania Secretary of Environmental Protection; and Anne Keller, former Wood-Mackenzie petrochemical analyst and current industry consultant.Sean O’Leary, senior researcher at the institute, said their topic was whether the “Shale Crescent”region of Ohio, West Virginia and Pennsylvania will realize the promise of economic renewal or if it’s on the verge of failing.”We are a very new organization. We are a think-tank, and we are devoted to developing policy in the areas of economic development, energy, and also the democratization of election processes as well as policymaking and regulatory processes. In pursuit of that, we’re going to be hosting forums like this one.” O’Leary said the group will be publishing three reports in the coming weeks. On Feb. 10 it will release an economic analysis of the effects of the fracking boom on 22 counties in Ohio, Pennsylvania and West Virginia that produce the majority of natural gas.
The Utica Shale: Ohio’s Under-Appreciated Economic Machine – The Utica Shale has never really gotten the level of attention and respect it probably deserves as a major U.S. resource of natural gas and natural gas liquids (NGLs). “We sometimes feel like the Utica is kind of the ‘red-headed stepchild’ of the shale industry,” Mike Chadsey told me when we talked last week, reminding me that, himself being a red-head, it’s ok for him to use that comparison. Mike is the Director of Public Relations for the Ohio Oil and Gas Association, the major trade association for the industry in the Buckeye State.The Utica’s proximity to and co-existence with the immense Marcellus Shalenatural gas formation has a great deal to do with its not getting so much attention for being such a major resource play. But for Ohio, the Utica has been the main driver of a renaissance of an industry that started there decades before the famousSpindletop discovery kicked off the oil business in Texas in 1901. Long before then, Cleveland had become a major commerce center for the early U.S. oil industry, with the state home to one the largest refining centers on earth. Ohio has been an oil and gas state for a long, long time. The past decade has seen another boom in the state, this time centered around not oil, but natural gas and the various liquids elements contained in the rich production from the Utica Shale formation. Instead of new refineries, Ohio has seen an array of new natural gas processing and fractionating plants constructed, along with billions in new investments by a booming chemicals and plastics sector that uses natural gas and NGLs as feedstock. Centered in the Southeastern quarter of Ohio, the boom in the Utica that kicked off in earnest in 2011 had resulted in over $86 billion in new capital investments and created over 200,000 new jobs for Ohio citizens by the end of 2019. Unemployment rates that had stood as high as 15.5% in 2009 had dropped into the 5% to 6% rangeten years later. But then, of course, the bust of 2020 hit, and the Utica region was hit hard like every other shale region in the United States. The collapse of global crude demand that began a year ago resulted in a corresponding collapse in new industry capital investment as companies rushed to cut costs wherever they could. Those cuts impacted company head counts, causing some of those employment gains of the prior decade to be lost.
Report: Ohio fracking counties saw declines in jobs, population and income – A decade earlier, the oil and gas industry was touted as being the savior for the Ohio River valley region, which had weathered the crumbling of the steel industry and watched helplessly as the coal industry declines.The millions of dollars invested in the Marcellus and Utica region were supposed to translate into local wealth in the form of more jobs, higher incomes and more people moving into the region.However, a new report released Wednesday by an independent think tank based in Johnstown, Pennsylvania, the Ohio River Valley Institute, showed that 22 counties in Ohio, Pennsylvania, and West Virginia responsible for 90% of Appalachia’s oil and gas production saw their share of the nation’s jobs, personal income and population all decline.”In many respects, it’s the region that should have theoretically benefited the most from development,” said Sean O’Leary, a native of Wheeling, West Virginia, and senior researcher of the institute’s 27-page report.In fact, Ohio fared the worst of the three states examined for economic success. Seven eastern Ohio counties – Belmont, Carroll, Guernsey, Harrison, Jefferson, Monroe and Noble – were the hardest hit amongst those analyzed, experiencing a net job loss of more than 8% and a population loss of more than 3%. Mike Chadsey, director of public relations for the Ohio Oil and Gas Association, disagreed with the report’s conclusions, saying the industry has worked to revive Appalachia.”There are certainly people who take this as gospel. But all you have to do is look at the unemployment numbers from the state, from when oil and gas started in the shale development and unemployment went down,” he said. “We know that people found jobs. We know that people are getting $5,000 to $7,000 an acre to lease their property. What they did with that was create all these family foundations and community foundations so they can reinvest their money.”Unemployment data doesn’t tell the full story, O’Leary said. “The reason the region’s unemployment rate dropped during the period wasn’t because they were adding jobs. It’s because people were moving away and the number looking for jobs was declining,” he said.
Report: Shale gas boom counties saw little growth in local jobs, income | Pittsburgh Post-Gazette -In the last decade, Pennsylvania, West Virginia and Ohio produced a tsunami of natural gas that exceeded even the most optimistic projections. That wealth of gas was supposed to translate into newly thriving local economies.According to a report released Wednesday by the Ohio River Valley Institute, the local renaissance never happened.Instead, counties that pumped out nearly all of the Appalachian region’s natural gas lagged on traditional measures of local prosperity: They had less personal income and job growth than the states as a whole and the nation over that time period, and their populations declined.”It is a case of economic growth without prosperity, the defining characteristic of the resource curse,” the institute said. The new think tank advocates for the region to shift away from fossil fuel extraction to clean energy. It is a project of the Johnstown-based Community Foundation for the Alleghenies and has received funding from the Heinz Endowments.Using data from the U.S. Bureau of Economic Analysis, the report looked at 22 counties in the three states between 2008 and 2019, a period when natural gas drilling in the Marcellus and Utica shales began, surged and subsided. In those years, the region went from being a marginal natural gas producer to one of the world’s largest. The 22 counties produced 90% of the states’ total gas output during the study period. Their gross domestic product – the value of the goods and services produced within their borders – grew by 60% over the decade – more than triple the national growth rate.But the communities were not rewarded with proportionate growth in jobs, income or people, according to the report. Over the study period, jobs in the 22 counties at the heart of the shale boom grew by just 1.7%, compared to 10% nationally and nearly 4% in the three states. Personal income in the major shale counties increased by 14.3% – roughly on par with the states, but seven percentage points less than the nation as a whole. Meanwhile, population in the shale counties dropped by 2.4%. “This extreme disconnect between economic output and local prosperity raises the question of whether the Appalachian natural gas industry is capable of generating or even contributing to broadly shared wellbeing,” the report said. Sean O’Leary, the main author of the Ohio River Valley Institute report, said one of the remarkable things about the Bureau of Economic Analysis data is how clear it is. “There is almost no math going on here,” he said. “All that I did was pull the numbers for the years 2008 and 2019 and look at the change over that time.” “It is just blindingly obvious.” Still, John Hanger, a former policy director for Gov. Tom Wolf who led the Pennsylvania Department of Environmental Protection during the first years of shale development, said when he saw the report he found it “shocking.” It “explodes in a fireball of numbers the claims that the gas industry would bring prosperity to Pennsylvania, Ohio or West Virginia,” he said. Mr. O’Leary said the economic disconnect may have been obscured by the fact that “the money was real.””The money did get invested to drill all the wells and pump all the gas,” he said. But, “it didn’t land in these local economies.”
CNX Resources (CNX) 2020-End Proved Reserves Up 13% to 9.55 Tcfe – CNX Resources Corporation announced that it has increased total proved reserves by 13% year over year to 9.55 trillion cubic feet equivalent (Tcfe). The company added 2,247 billion cubic feet equivalent (Bcfe) of proved reserves through extensions and discoveries, which helped it in replacing more than 440% of 2020 net production of 511 Bcfe. CNX Resources’ proved reserve has a reserve life ratio of 18.69 years, based on 2020 production. CNX Resources’ strong performance is based on stable production from Marcellus and Utica shale assets. Production from these shales enables the company to meet its production goal. Replenishment of production through the addition of new proved reserves will allow the company to sustain momentum over the long term.CNX Resources’ 94.6% of the proved reserve is natural gas. Moreover, the company has a very low-cost structure. Drilling and completion costs incurred in 2020 for extensions and discoveries were $480 million. Finding and development cost of the added proved reserves stands at 21 cents per thousand cubic feet (Mcfe), which will give the company a competitive advantage. CNX Resources – through its efficient technology – has been able to explore and expand proved reserves annually for the last five years. At 2016-end, proved reserves of the company were 6.25 Tcfe. At 2020-end, the metric totaled 9.55 Tcfe, reflecting an increase of 52.8% in the last five years. Over the last five years, it was able to lower average cost per Mcfe to $1.64 at 2020-end from $2.32 at 2016-end.
Range Resources assessed $294K penalty for well-status error – Pittsburgh Business Times – The Pennsylvania Department of Environmental Protection fined Range Resources Corp. $294,000 over what the DEP said was incorrectly classifying a Fayette County well as inactive. The civil penalty came in a consent agreement between DEP and Range Resources, one of the largest natural gas producers in southwestern Pennsylvania. The agreement covers one conventional natural gas well, Shirocky No. 1 in Fayette County, that Range had asked for inactive status but provided information that it both expected to have it become active at a later date and an internal memo that said it wouldn’t. DEP said that the well, if there was no plan to use it in the future, should have been plugged. Range said a former employee’s error was responsible for the miscommunication. A DEP subpoena to Range found 42 conventional wells – ones that aren’t drilled into the Marcellus or Utica Shale using current drilling methods – were designated inactive between 2013 and 2017 but production never was resumed. DEP said they should be considered not inactive but instead plugged. “It’s the law: inactive wells need to be viable for future use,” said DEP Secretary Patrick McDonnell in a statement. “If wells are not viable for future use, then they should be classified as abandoned wells and are required to be plugged.”
Northern Oil Enters Appalachia as India’s Reliance Exits – India’s Reliance Industries Ltd. has agreed to divest its entire stake in 64,000 net acres in the Appalachian Basin, continuing its exodus from unconventional oil and natural gas assets in the United States. Northern Oil and Gas Inc. (NOG) agreed to acquire the nonoperated stake from Reliance Marcellus LLC in exchange for $175 million and 3.25 million warrants to purchase its common stock at a price of $14.00/share.EQT Corp., which acquired the properties in a broader deal last year when it bought Chevron Corp.’s Appalachian portfolio in Pennsylvania and West Virginia, would operate the assets. The assets are expected to produce 100-110 MMcfe/d this year, and consist of 102.2 net producing wells, another 22.6 wells in process and 231 net undrilled locations in the core of the Marcellus and Utica shale plays, NOG said. The deal gives NOG entry to the Appalachian Basin and complements its stakes in 183,000 acres in the Williston and Permian basins. The company primarily invests in nonoperated minority working and mineral interests. “Our cash purchase price for these assets only ascribes value for producing wells and the large inventory of wells-in-process, with significant upside value on the undeveloped properties,” said NOG COO Adam Dirlam. “The joint venture (JV) structure allows Northern significant input and clarity on the development plans for these assets on a multiyear basis.” NOG plans to finance the transaction with a combination of equity and debt. The deal is expected to close in April.
Public input blocked on shale gas wastewater permitting – Cathy Lodge has some questions and concerns about new state wastewater storage and reuse permits issued to three shale gas developments near her home in Robinson Township, Washington County, but didn’t get an opportunity to voice them. People living near 46 other shale gas operations granted permits in December and January were similarly silenced when the Pennsylvania Department of Environmental Protection decided to not follow its newly adopted notification and public participation protocols for the 10-year general permits known as ” WMGR123.” The wastewater storage and reuse authorizations, approved on Dec. 23 and Jan. 4, allowed shale gas wastewater operations to expand, without pre-permitting public notification and review, at existing shale gas facilities in 15 counties, including Washington, Greene, Fayette, Westmoreland and Butler in southwestern Pennsylvania. “If DEP is going to allow WMGR123 permits and waste processing and storage at wellpads, I definitely want every opportunity possible to voice my concerns prior to them issuing approvals,” Ms. Lodge said. “Getting the opportunity to comment on the permits was something I was looking forward to.” In a Feb. 4 letter to the DEP, Ms. Lodge joined five environmental groups in asking the DEP to immediately suspend the permit approvals, publish public notices of its permit decisions and initiate a 60-day public comment period. Groups signing the letter include the Environmental Integrity Project, PennFuture, Mountain Watershed Association, Earthworks and Center for Coalfield Justice.They requested a formal response from the DEP by Feb. 11. “CCJ believes that public notice and the opportunity to comment ensures that communities have a voice in the environmental decisions that affect them,” Veronica Coptis, executive director of Center for Coalfield Justice, said in an email response to questions. “The DEP’s failure to notify and include impacted communities in the decision making process for these WMGR123 authorizations that will last 10 years is unacceptable.” According to the letter, the DEP’s approval of the 49 permits deprived the organizations’ members and shale gas field residents of the opportunity to review site-specific permit applications and voice concerns before the permits were granted about the potential impacts of oil and gas facilities on their health, environment and public safety.
A Decade Into the Fracking Boom, Pennsylvania, Ohio and West Virginia Haven’t Gained Much, a Study Says – After fracking companies invested billions chasing the natural gas boom across West Virginia, Ohio and Pennsylvania, what do people living in the middle of the most prolific gas fields have to show for it, more than a decade later?That’s the question the Ohio River Valley Institute, an independent think tank based in Johnstown, Pennsylvania, working to advance a more prosperous, sustainable and equitable Appalachia, asked in a report published on Wednesday.Its answer: In short, not much. To be sure, the report found that new horizontal drilling techniques involving hydraulic fracturing in the Marcellus and Utica shale formations, which helped reshape the nation’s oil and gas fortunes, produced a lot of economic growth. But it largely failed to bring the things that help people and local communities the most: jobs, personal income gains and population growth.The natural gas industry hasn’t been an engine for economic prosperity, said Sean O’Leary, the institute’s senior researcher and principal author of the report, and “there is no basis on which we can see that it even can be, going into the future.”It was unable to deliver on local prosperity even though gas production itself exceeded the most optimistic projections, he said. The optimistic projections included a 2010 American Petroleum Institute report projecting robust job growth that was seized on by officials in Pennsylvania, Ohio and West Virginia to usher in the industry. But the institute found that jobs in the 22 counties that account for 90 percent of the production in the three states increased by only 1.7 percent, according to data from the U.S. Bureau of Economic Analysis, while nationally the number of jobs grew by 10 percent.O’Leary does not dispute that the oil and gas industry employs people in each state, but questions where they are located and how many of the jobs are new.He said the institute’s report seeks to reveal true measures of economic prosperity in the counties most affected by the gas boom. In order to do that, the institute focused on counties that produce the most gas and where natural gas production is a more significant part of the local economy.Those counties were Doddridge, Harrison, Marshall, Ohio, Ritchie, Tyler and Wetzel in West Virginia; Belmont, Carroll, Jefferson, Guernsey, Harrison, Monroe and Noble in Ohio; and Bradford, Greene, Lycoming, Sullivan, Susquehanna, Tioga, Washington and Wyoming in Pennsylvania.In general, the report found an increase in economic growth as measured by their share of gross domestic product, but job growth and personal income lagged behind, as did population growth.
Fracking Counties Economic Impact Report – Ohio River Valley Institute – A new Ohio River Valley Institute report titled, “Appalachia’s Natural Gas Counties: Contributing more to the U.S. economy and getting less in return” quantifies the decade-long failure of natural gas boom in the Marcellus and Utica fields to deliver growth in jobs, income, and population to the 22 Ohio, Pennsylvania, and West Virginia counties that produce more than 90% of the region’s natural gas.Contrary to the predictions of the oil and natural gas industry, which a decade ago published economic impact studies saying the expected boom in natural gas production would give rise to over 450,000 new jobs in Ohio, Pennsylvania, and West Virginia, data from the U.S. Bureau of Economic Analysis show that jobs in the 22 counties crept up by a paltry 1.7% while nationally the number of jobs grew by 10%.It should not have been this way. Natural gas production in the region substantially exceeded the projections contained in the industry studies. And economic output in the 22 counties grew by 60%, more than three times the rate of output growth nationally. But little of the income generated by that growth entered local economies. Between 2008 and 2019, as the counties’ contribution to the nation’s economy grew from $2.46 per thousand dollars of output to $3.31, their piece of the national economic pie got smaller.
Their share of the nation’s personal income fell by 6.3%, from $2.62 for every $1,000 to $2.46.
Their share jobs fell by 7.5%, from 2.8 in every 1,000 to 2.6.
Their share of the nation’s population fell by 9.6%, from 3.2 for every 1,000 Americans to 2.9 for every thousand.
Ohio’s seven eastern counties – Belmont, Carroll Guernsey, Harrison, Jefferson, Monroe, and Noble – were the hardest hit seeing a net job loss of over 8% and a population loss of over 3%. Pennsylvania’s eight primary gas counties – Bradford, Greene, Lycoming, Sullivan, Susquehanna, Tioga, Washington, and Wyoming – did better with a net 4.5% gain in jobs. Although that was slightly less than the statewide average gain of 4.6%. And it did not prevent a population decline of 1.4%.Only in West Virginia did the natural gas counties – Doddridge, Harrison, Marshall, Ohio, Ritchie, Tyler, and Wetzel – outperform the state for personal income and jobs. But even then, the rate of growth was less than half the national average and the population loss was greater than the population loss in the state as a whole.John Hanger, former Pennsylvania secretary of Environmental Protection and policy director to Governor Tom Wolf, called the report’s findings “shocking”. “This report documents that many Marcellus and Utica region fracking gas counties typically have lost both population and jobs from 2008 to 2019. This report explodes in a fireball of numbers the claims that the gas industry would bring prosperity to Pennsylvania, Ohio or West Virginia. These are stubborn facts that indicate gas drilling has done the opposite in most of the top drilling counties,” said Hanger.Kathy Hipple, Bard College professor of finance and former analyst at the Institute for Energy Economics and Financial Analysis, said, “This detailed report is another indictment of fracking. The business case for fracking has never been proven. The Appalachian shale gas producers have been spectacularly unsuccessful financially, despite impressive production gains. Many have filed for bankruptcy. Others have taken massive write-offs. This financial failure of the natural gas sector extends to local communities.” Hipple concluded, “Simply put, the natural gas industry has not delivered the promised benefits for producers, investors – or local communities.”
Somerset County Opposes Tennessee Gas Compressor Station – Last night Somerset County passed a resolution (see attached) that opposes the West Milford and Wantage Compressor Station that Tennessee Gas Pipeline Company plans to build. Tennessee Gas Pipeline Company’s proposal includes modification and expansion of the Wantage Compressor Station in Sussex County, New Jersey, including installation of one Solar Titan 130 turbine with an ISO rating of 20,500 hp and auxiliary facilities. This is part of TGP’s East 300 Upgrade that also includes a new compressor station in the Highlands Region of West Milford. “Somerset County has stood up for our health and environment by opposing TGP’s fossil fuel compressor stations. They are the first county and government entity that has passed a resolution to oppose these fossil fuel projects. The compressor stations increase GHG’s, climate impacts, and will have damaging impacts to our air and water. In their resolution, Somerset County raised the fact that the TGP Compressor stations go directly against Governor Murphy’s EO 100 to reduce GHG’s and move to 100% clean energy by 2050. One site for the compressor is in the middle of the Highlands Preserve right next to a C1 stream and above the Wanaque and Monksville reservoir. A leak or accident will be detrimental to the critical drinking water and to nearby communities,” saidJeff Tittel, Director of the New Jersey Sierra Club. “We thank Somerset County for protecting the Highlands and the drinking water for almost 3 million people.On June 20th, Tennessee Gas Pipeline Company L.L.C filed with the Federal Energy Regulatory Commission seeking the issuance of a certificate of public convenience and necessity to construct, install, modify, operate, and maintain certain compression facilities located in New Jersey and Pennsylvania. “These compressor facilities release harmful air pollutants such as NOx, PM2.5, Sox, VOCs, HAPs such as formaldehyde, benzene, and GHG’s. Benzene can cause headaches, asthma attacks, and worsen symptoms for people with respiratory problems. Chromium, benzene and hydrocarbons can get into industrial stormwater runoff that will increase pollution and flooding.” The New Jersey Sierra Club, Skylands Sierra Club, Sustainable West Milford, North Jersey Pipeline Walkers, Food & Water Watch, held a town hall against the 2 compressor stations with close to 200 people, including government officials from West Milford.
Environmental Groups Sue Federal Regulators Over Western Mass. Pipeline Plan – Environmental groups are challenging a federal agency’s decision to allow natural gas expansion in central Massachusetts, arguing legal precedent – and a change in regulatory leadership — is on their side.On Friday, the Washington, D.C. Court of Appeals will hear oral arguments from two groups opposed to the proposed expansion of a compressor station in Agawam, which the Federal Energy Regulatory Commission (FERC) approved in 2019.The project in question is a proposal from the Tennessee Gas Pipeline Company, LLC – a subsidiary of energy giant Kinder Morgan – to build 2.1 miles of new natural gas pipeline and replace two small compressors with a larger unit at its Agawam site. The company says these upgrades will allow it to deliver more natural gas for distribution in the greater Springfield area, and as such, “alleviate capacity-constrained New England gas markets.”Opponents of the project, meanwhile, want the panel of appellate judges to nullify the permit issued by FERC, saying the project will contribute to climate change, prolong our dependence of fossil fuels, and harm local residents by increasing pollution in an area already known for poor air quality and pose public safety risks. They also argue that FERC violated federal law and disregarded legal precedent by allowing the project to move forward.”The National Environmental Policy Act requires FERC to meaningfully evaluate greenhouse gas emissions from fossil fuel production and transportation projects,” wrote petitioners, Berkshire Environmental Action Team and Food & Water Watch, in court documents.A spokesperson for FERC declined to comment.
As new information arises, RCC Big Shoal case may enter criminal court — Criminal charges may become a factor as the Pike County Fiscal Court continues to seek full repayment of a $400,000 loan a previous administration made to the principals of a company whose promised natural gas to liquid fuel plant never materialized. On Feb. 5, Pike Commonwealth’s Attorney Bill Slone confirmed to the News-Express that his office, along with Kentucky State Police, have launched an investigation into the circumstances involved in RCC Big Shoal’s failure to repay the loan from the county. Slone said he has been aware of the case for some time, but as information has arisen recently, he began to feel as though an investigation is warranted. Slone said his office has begun an investigation along with the KSP Special Investigations Branch, which has assigned a detective to assist.While the criminal charges could ultimately result in jail time if those charged are found guilty, Slone said his goal is the same as that of Pike County Judge-Executive Ray Jones and the current Pike County Fiscal Court. “My goal is to get the county’s money back,” he said. RCC Big Shoal principals David Farmer and Bill Johnson were able to obtain a $400,000 loan from the administration of former Pike County Judge-Executive Wayne T. Rutherford with promises of building a natural gas-to-fuel plant in the Big Shoal area of Pike County. The project never materialized and the majority of the loan remains unpaid.
Chesapeake Energy emerges from bankruptcy and shifts back to natural gas (Reuters) – U.S. shale producer Chesapeake Energy Corp on Tuesday exited Chapter 11 bankruptcy with business plan that nods to its founders’ emphasis on natural gas after a recent push into crude oil. Once the second-largest U.S. natural gas producer, Chesapeake was felled by a long slide in gas prices and heavy debts from overspending on deals. Two years ago it paid $4 billion in a bet on shale oil firm WildHorse Resource Development. But oil prices fell after the deal closed. The company plans to focus 85% of this year’s spending on gas fields in the U.S. Northeast and Louisiana, and will let its oil output decline, Chief Executive Doug Lawler said in an interview. It aims to spend between $700 million and $750 million per year on new projects that could generate $400 million in annual free cash flow, he said. Chesapeake filed for court protection last June and won approval last month for a plan that shed about $7.7 billion in debt. It was unable to invest enough in operations to turn a profit while simultaneously paying down $9 billion in debt. That “led us to make decisions that weren’t always the best,” said Lawler, who took over the firm in 2013.
Appalachian Fracking Boom Was a Jobs Bust, Finds New Report – DeSmog – The decade-long fracking boom in Appalachia has not led to significant job growth, and despite the region’s extraordinary levels of natural gas production, the industry’s promise of prosperity has “turned into almost nothing,” according to a new report. The fracking boom has received broad support from politicians across the aisle in Appalachia due to dreams of enormous job creation, but a report released on February 10 from Pennsylvania-based economic and sustainability think tank, the Ohio River Valley Institute (ORVI), sheds new light on the reality of this hype.The report looked at how 22 counties across West Virginia, Pennsylvania, and Ohio – accounting for 90 percent of the region’s natural gas production – fared during the fracking boom. It found that counties that saw the most drilling ended up with weaker job growth and declining populations compared to other parts of Appalachia and the nation as a whole.Shale gas production from Appalachia exploded from minimal levels a little over a decade ago, to more than 32 billion cubic feet per day (Bcf/d) in 2019, or roughly 40 percent of the nation’s total output. During this time, between 2008 and 2019, GDP across these 22 counties grew three times faster than that of the nation as a whole. However, based on a variety of metrics for actual economic prosperity – such as job growth, population growth, and the region’s share of national income – the region fell further behind than the rest of the country. Between 2008 and 2019, the number of jobs across the U.S. expanded by 10 percent, according to the ORVI report, but in Ohio, Pennsylvania, and West Virginia, job growth only grew by 4 percent. More glaringly, the 22 gas-producing counties in those three states – ground-zero for the drilling boom – only experienced 1.7 percent job growth.”What’s really disturbing is that these disappointing results came about at a time when the region’s natural gas industry was operating at full capacity. So it’s hard to imagine a scenario in which the results would be better,” said Sean O’Leary, the report’s author. The report cited Belmont County, Ohio, as a particularly shocking case. Belmont County has received more than a third of all natural gas investment in the state, and accounts for more than a third of the state’s gas production. The industry also accounts for about 60 percent of the county’s economy. Because of the boom, the county’s GDP grew five times faster than the national rate. And yet, the county saw a 7 percent decline in jobs and a 2 percent decline in population over the past decade.
Near Complete Mountain Valley Pipeline Needed, D.C. Circuit Told –Natural gas users, landowners, and the environment would benefit from finishing construction on the Mountain Valley Pipeline and putting the infrastructure into service, the company and other intervenors in a lawsuit to stop the pipeline told the D.C. Circuit. Green groups, including the Sierra Club and Appalachian Voices, argue falling demand for natural gas and surplus pipeline capacity undermines the company’s claim that the project will serve the public interest. They seek an emergency motion blocking the Federal Energy Regulatory Commission’s orders allowing construction to continue. But the arguments against the project are based on “cherry-picked snippets from an earnings report’…
With construction slowed, MVP continues erosion control from the air – For the third winter in a row, helicopters are dropping grass seeds and mulch along the route of the Mountain Valley Pipeline in an effort to curb erosion on the unfinished project. Heavy traffic of the company’s helicopters has been reported by residents of Franklin County in recent days. Mountain Valley says the erosion control efforts are needed as construction of the natural gas pipeline continues to be delayed by legal challenges of its permits from environmental groups. “Due to ongoing project delays, previous temporary stabilization measures must be periodically refreshed to maintain and protect the ROW [right of way],” company spokeswoman Natalie Cox wrote in an email this week. Helicopters are being used to distribute a liquid mixture of seeds and mulch, a measure that has been approved by state and federal regulators as the best way to preserve construction areas, she said. Although Mountain Valley says it hopes to complete work on the $6 billion project by the end of this year, legal hurdles remain as opponents say the 303-mile long pipeline will scar the scenic landscape of Southwest Virginia, pollute its waters and endanger protected species of bats and fish. The company has agreed to stop all work – with the exception of stabilization and erosion control effects – until Feb. 22, the date by which an appellate court is being asked to rule on approvals from Federal Energy Regulatory Commission. In 2017, FERC approved the pipeline to run through the Virginia counties of Giles, Craig, Montgomery, Roanoke, Franklin and Pittsylvania. At the time, the pipeline was slated for completion by late 2018.
Appalachia’s top natural gas-producing counties falling further behind economically, report says – A new study of Appalachian natural gas production suggests that the region’s natural gas boom hasn’t kept the top gas-producing counties in the Ohio Valley from lagging behind the rest of the nation economically. The Ohio River Valley Institute, a nonprofit think tank, released an analysis Wednesday finding that, while those counties’ rates of gross-domestic-product growth more than tripled that of the country between 2008 and 2019, their collective shares of the nation’s personal income, jobs and population all declined.”What we’re seeing is almost the definition of the resource curse, and that is great economic growth with very little, if any, impact on local measures of prosperity,” Sean O’Leary, senior researcher at the institute, said of the report during a webinar last week that focused on the so-far unrealized dream of a petrochemical boom in Appalachia.The report attributes much of the increase in gross domestic product – the total value of goods and services – in 22 counties in West Virginia, Ohio and Pennsylvania to an Appalachian natural gas production boom powered by the advent of hydraulic fracturing, or “fracking,” that exceeded high industry expectations but did not come close to bringing the number of jobs to the region expected to coincide with the boom.Combined job growth in those 22 counties – including Doddridge, Harrison, Ohio, Ritchie, Tyler and Wetzel in West Virginia – was only 1.7% between 2008 and 2019, the report notes, questioning the economic value of the Appalachian natural gas industry to the region.Only in Doddridge County, population 8,448, per 2019 U.S. Census Bureau data, did gains in shares of income, jobs, and population come close to matching the region’s contributions to economic production, the report found. It offered hypotheses that exporting labor and materials, lower natural gas prices than expected and lack of anticipated progress toward petrochemical and plastics manufacturing in the region are contributing to the economic stagnation in “Frackalachia.””This extreme disconnect between economic output and local prosperity raises the question of whether the Appalachian natural gas industry is capable of generating or even contributing to broadly shared wellbeing,” the report reads. “And, if it is not, should it continue to be the focus of local and regional economic development efforts?”
West Virginia Sen. Manchin to President Biden: Avoid major curbs to natural gas fracking, horizontal drilling – The chairman of the Senate Energy and Natural Resources Committee, seen by many as the likely key vote in the Senate for the Biden administration on contested issues, has asked the president to steer clear of major natural gas fracking and horizontal drilling reforms. “Technologies like hydraulic fracturing and horizontal drilling have allowed our country to more efficiently tap into our rich, domestic energy resources that reside in the vast shale plays across the country, including in my home state of West Virginia,” wrote Joe Manchin, D-W.Va. who, as a moderate, is a critical vote in the 50-50 makeup of the Senate. “These technologies catalyzed a ‘shale revolution’ in the U.S. that has propelled a surge in domestic oil and gas production, culminating in the U.S. becoming a net total energy exporter in 2019 for the first time in 67 years. This energy security affords your administration with expanded geopolitical tools and strengthens our national security,” Manchin wrote. The senator also pointed to a U.S. Geological Survey estimate of 214 trillion cubic feet of natural gas in the Marcellus and Utica shale formations that hasn’t been discovered yet and could be recovered. “Responsible production of our abundant resources is critical. That includes using existing technologies and continuing to innovate new ways to reduce methane flaring and leaks from oil and gas systems and expanding our energy infrastructure and gathering lines to instead get that product to market,” Manchin wrote. “I also strongly support advancing carbon capture, utilization and sequestration technologies, including for natural gas applications, to further reduce emissions,” he wrote. “I encourage you to bear in mind these many benefits of responsible domestic natural gas production as you consider any future executive or administrative action, and I look forward to working with you to achieve our shared goals of energy security, economic growth and global emissions reductions,” Manchin wrote.
Natural gas company announces plan to expand to Knox, Waldo counties –Summit Natural Gas of Maine plans to invest $90 million to extend its service into the Midcoast. “The Midcoast is one of the last commercial centers in Maine without natural gas service, which is why Summit is committed to bringing this energy option to communities along Route 1,” Summit CEO Kurt Adams said in a news release Friday. “We are very excited to help Belfast, Camden, Rockland, and other towns in the region strengthen their economies while providing them with a lower emission fuel alternative.” The company said it hopes to break ground on the pipeline in the fall and that roughly 100 jobs will be created in the Midcoast during construction of the pipeline. Service is expected to start for residential and commercial customers in late 2022 following the completion of the project’s initial phase. Summit hopes to have made service available to more than 6,500 customers and extended its footprint into the towns of Lincolnville and Northport by 2026. Town officials in Rockport and Belfast welcomed the project. “Just as businesses require a variety of fuel sources to meet their unique energy needs, folks in the Midcoast will now have an additional option for heating their homes as they see fit,” Town Manager William Post said in the release.
Westchester County Unanimously Opposes Danskammer Plant Expansion – — Last night, the Westchester County Board of Legislators unanimously voted in favor of a resolution opposing the massive expansion of the Danskammer fracked gas power plant in Newburgh.With the passage of last night’s resolution, Westchester County has become the first county in New York to unanimously come out in opposition to the dirty Danskammer plant’s expansion aims. In doing so, the county has joined the chorus of municipalities across the state calling for Governor Cuomo to deny the plan its desired expansion permits.Legislator Catherine Parker (D – Harrison, Larchmont, Mamaroneck, New Rochelle, Rye), chief sponsor of the resolution and chair of the Board’s Planning, Economic Development and Energy Committee said, “New York State’s recently passed the Climate Leadership and Community Protection Act establishing programs, obligations and targets to meet zero emissions by 2050. Expanding the Danskammer plant to a full time, fossil fuel facility is exactly the wrong thing to do if we’re serious about a clean, sustainable future, and about meeting those goals.”Legislator Ruth Walter (D – Bronxville, Yonkers), chair of the Board’s Environment and Health Committee, said, “Although this plant will not be in Westchester, pollution and climate change do not observe County lines. The plant’s expansion would add 2 million tons of greenhouse gas emissions annually to our atmosphere, drastically harming air quality in the region and exacerbating climate change and with gallons of diesel fuel and aqueous ammonia are proposed to be stored on-site, there’s a significant threat to the water quality for all of us downstream on the Hudson.”
U.S. LNG Exports Eclipse Pipeline Takeaway for Only Second Time Since 1998, EIA Says -U.S. exports of liquefied natural gas (LNG) outstripped natural gas exports by pipeline in November, marking only the second time that has happened in more than 20 years, the U.S. Energy Information Administration’s (EIA) said in a new report.LNG exports exceeded gas delivered via pipeline by nearly 1.2 Bcf/d in November, as demand from Asia for the super-chilled fuel mounted ahead of winter.Based on shipping data, preliminary estimates for December and January “suggest a continuation of this trend,” EIA said in its Natural Gas Monthlyreport.LNG feed gas volumes increased in both December and January, NGI data show, as Asian demand further intensified amid the onset of a particularly harsh stretch of cold temperatures.Last November and December, Lower 48 LNG exports set two consecutive monthly records at 9.4 Bcf/d and 9.8 Bcf/d, respectively, EIA said. Average LNG exports over the course of January held at 9.8 Bcf/d and surpassed 11 Bcf on several days.When LNG exports last topped those by pipeline, which was last April, they did so by only 0.01 Bcf/d, EIA said. Prior to that, LNG had not eclipsed pipeline exports since 1998. In its January Short-Term Energy Outlook, EIA forecast that U.S. LNG exports would exceed gas delivered by pipeline in the first and fourth quarters of this year – spanning the typical months of peak demand – and on an annual basis in 2022. The agency said from November through January, monthly U.S. LNG volumes nearly tripled the average levels in the summer months of 2020.EIA forecast that U.S. LNG exports would average 9.8 Bcf/d this month, on par with January’s record level, before tapering to seasonal lows amid milder temperatures in the spring. The agency’s outlook calls for LNG exports to average 8.5 Bcf/d over 2021 and climb to 9.2 Bcf/d in 2022 amid continued strong demand from Asia as well as Europe. The relative ascension of LNG is particularly notable because pipeline exports are strong as well. Total U.S. gross exports by pipeline averaged 7.9 Bcf/d in the first 11 months of 2020, EIA noted, 3% higher than during the same period of 2019.
Cheniere Seeks OK to Ramp Third Corpus Christi LNG Train – Cheniere Energy Inc. has requested FERC approval to place the third train in service next month at its Corpus Christi liquefied natural gas (LNG) export terminal in South Texas, which would ramp up capacity by 4.5 million metric tons/year (mmty). The company requested permission in a letter filed with the Federal Energy Regulatory Commission on Wednesday to bring the train online by March 12. The third train would bring total output at the facility to 15 mmty. Cheniere in December loaded the first commissioning cargo from the third train. Cheniere sanctioned the third train in 2018, the same year the Corpus terminal produced its first LNG. In November 2019, the company moved up its timeline to complete the third train to the first half of 2021, several months ahead of schedule. A sixth train also is under construction at its Sabine Pass LNG terminal in Louisiana, which was 71% complete at the end of September. The sixth train would boost production capacity at that facility to 30 mmty. Global LNG supply grew by 100 million tons (Mt) between 2016 and 2020, driven largely by Australia, Qatar and the United States, according to data intelligence firm Kpler. Despite the pandemic, LNG supply last year grew by 4 Mt, driven mainly by U.S. growth. U.S. capacity is expected to increase to 71 mmty this year, driven by the Corpus expansion and more operating efficiencies at existing terminals, according to Kpler. Winter demand for LNG is strong, and feed gas deliveries to U.S. terminals have been at or near capacity most of the season. Domestic exports reached 6.14 Mt in January during a cold snap in the northern hemisphere that drove up demand, rebounding from a low of 1.97 Mt in July when prices were down amid a supply surplus. Higher demand has left natural gas storage stocks in Asia and Europe lower, while the global economy continues to recover from low points brought on by Covid-19 last year. LNG buying this year is expected to remain above 2020 levels, supporting U.S. exports. Recent NGI data showed U.S. LNG in the money both in Asia and Europe through the remainder of the year.
U.S. energy regulator to create environmental justice position: chairman (Reuters) – The chairman of the U.S. Federal Energy Regulatory Commission said on Thursday the panel will create a senior position on environmental justice, to make sure new energy projects, such as pipelines and liquefied natural gas facilities, do not unfairly harm minority communities. “I believe that the Commission should more aggressively fulfill its responsibilities to ensure our decisions don’t unfairly impact historically marginalized communities,” Richard Glick, a Democrat recently appointed to head the panel by President Joe Biden, told reporters during a teleconference. While the panel is required to consider green justice issues under the National Environmental Policy Act, Glick said in recent years, it has not always emphasized its responsibility. “I thought we really haven’t taken the issue too seriously especially with regards to a couple of LNG projects,” Glick said. He did not name the projects as they are pending. Glick said the FERC would be spending more time considering whether fossil fuel projects would expose nearby residents to a lot of particulate pollutants such as nitrogen oxide, or NOX. FERC should consider whether pollution impacts on communities could be mitigated by moving the projects or installing more pollution controls, Glick said.
Natural Gas Traders Unswayed by Record-Breaking Cold Penetrating Lower 48 – Weather model volatility left natural gas traders flummoxed on Monday, with double-digit increases early in the session nearly erased by the close. With the frigid cold descending from Canada into the Lower 48 seen possibly continuing into March, though, the March Nymex gas futures contract settled 1.9 cents higher than Friday at $2.882. April edged up 2.1 cents to $2.862. Spot gas prices also retreated across most of the country, though trading in the Northeast was notably volatile. New England cash traded as high as $14.000, but NGI’s Spot Gas National Avg. dropped 2.5 cents to $3.985. Even with big swings in the weather data, there’s little argument that the next couple of weeks are poised to be the coldest the country has experienced in years. The issue in the near term is that the European model initially pushed back the arrival of the next bout of extreme cold, shedding demand from the outlook for this week and for later in the month. However, by the afternoon, the model added it all back and then some, with February remaining on track to be in the top 5 coldest on record, according to Bespoke Weather Services. ” … the other key is that we do not yet see warming to even normal yet at the end of the runs,” the forecaster said. “If cold continues beyond day 15 and into March, we should see a steady climb in prices, at least when smoothed out.” NatGasWeather expressed frustration in Monday’s price action. The firm pointed out that the Global Forecast System added 25 heating degree days (HDD) since before Sunday’s open and the latest European ensemble data is now 133 HDDs colder compared with the 30-year average for the coming 15 days, which is “by far the coldest it’s been the past several years. “So, clearly, other factors are driving today’s selling since very cold/bullish weather patterns and a tight balance are finally working in concert, and it still isn’t good enough for a sustained rally.” Supporting that theory is the quickened pace that storage inventories have fallen in the final weeks of the traditional withdrawal season, which wraps at the end of March. Even with some deviations in the 15-day forecast, market observers expect a hefty withdrawal in the next three government storage reports. Analysts at The Schork Group indicated the “early whisper number” for the next Energy Information Administration (EIA) report is in the mid-180s Bcf, while the following two reports could fetch draws well into the 200s Bcf. This would bring total working gas in storage to 2,000 Bcf by Feb. 19. “This is significant,” The Schork Group said. “As a result, the odds of finishing this winter above the five-year avarage have collapsed.”
Natural Gas Futures Take Back Seat to Cash as ‘Punishing’ Cold Drives Largest Increases ‘In Years’ – Intraday natural gas price volatility was on full display midweek as traders assessed the impacts of a substantial, though likely temporary, decline in export demand and the potential for a more moderate end-of-February following some of the coldest weather in years. After tumbling to a $2.741/MMBtu intraday low, the March Nymex gas futures contract bounced and eventually settled 7.6 cents higher at $2.911. April tacked on 5.6 cents to reach $2.879. Spot gas prices mounted some of the largest gains in years as the frigid air penetrating the north/central United States stalled, leaving large population centers to bear sub-zero temperatures. NGI’s Spot Gas National Avg. climbed $1.040 cents to $4.835. Weather model fluctuations are nothing new, but when it’s the dead of winter and a polar vortex has plunged into the Lower 48, gas traders take notice. So it’s no surprise that March futures trading has been erratic in recent days. On Wednesday, the prompt month fell early as overnight weather models erased some demand from the 15-day outlook. Prices then bounced when some of that demand was added back to the midday forecast and went on to climb even further once the European model’s afternoon run not only recovered the demand it lost overnight but added significantly more to the outlook. The March contract closed at the session high after dropping to $2.74. “So, now that prices are back to $2.90, is a return run to $3.00 possible?” asked NatGasWeather. A move back to $3.000 may be more plausible if it weren’t for lower export demand. Ahead of the Arctic being pushed farther south into Texas, heavy fog has clouded the Gulf Coast much of this week. This has prompted many key ports and waterways to impose shipping restrictions because of visibility levels, according to Wood Mackenzie. Liquefied natural gas (LNG) demand has steadily fallen since the start of the week, reaching 10.3 Bcf by Wednesday, off from 11.3 Bcf on Monday. Wood Mackenzie attributed most of the decline to Sabine Pass liquefaction facilities partially shutting down operations at the second production unit. There remains a moderate-to-high fog and visibility threat through Thursday; however, “current LNG inventory levels may help limit any further declines,” the firm said.
“Supply Is Frozen” – Polar Vortex Sparks Massive Spike In NatGas/Electricity Costs – As a ‘deep chill’ from a polar vortex split spills into much of the central US, spot natural gas and electricity prices are spiking quicker than Robinhood pajama traders pumping penny stocks, low-float biotechs, and, of course, GameStop and other meme stocks in recent weeks. The week’s biggest story is the plunge in temperatures across the Great Plains from Canada to Texas, resulting in skyrocketing demand for natgas and electric markets as tens of millions of Americans crank up their thermostats to stay warm.“One of the main stories is the very cold temperatures and the expanse of the cold,” Marc Chenard, a senior branch forecaster at the US Weather Prediction Center, told Bloomberg.“Most of the country will be at or below average except Florida.”BAMWX explains a series of winter storms are possible” from Denver to Dallas to Chicago to Cleveland to Mid-Atlantic and Northeast states through next week.“An overwhelming signal seems to be developing for a major winter storm from the Deep South to the Ohio Valley into the NE early next week. Here are our 3-7 day hazards map and a blend of models 75th percentile data. Worth note deterministic data showing major snow numbers. #Snow,” BAMWX’s official Twitter account tweeted. The reason the extreme weather is so critical to note is that the colder temperatures have prompted wellhead freeze-offs, cutting production receipts just when they’re most needed by customers’ demand for heating. Frigid temperatures caused equipment failures, temporarily shutdowns and flaring at four natural gas processing plants in the West Texas shale play, filings with the Texas Commission on Environmental Quality show.
US working natural gas volumes in underground storage decline 171 Bcf: EIA | S&P Global Platts – Last week’s draw from US working natural gas in storage proved strong enough to reduce the year-on-year surplus to a deficit while the possibility for the largest weekly draw ever is on the horizon. Stay up to date with the latest commodity content. Sign up for our free daily Commodities Bulletin. Sign Up Storage inventories declined 171 Bcf to 2.518 Tcf for the week-ended Feb. 5, the US Energy Information Administration reported Feb. 11. The withdrawal was a bit below the 175 Bcf draw expected by an S&P Global Platts’ survey of analysts, but above the five-year average withdrawal of 125 Bcf, according to EIA data. Storage volumes now stand 9 Bcf, or 0.4%, below the year-ago level of 2.527 Tcf and 152 Bcf, or 6.4%, above the five-year average of 2.366 Tcf. The pull was less than the 192 Bcf dip reported the week prior as demand was down 2.2 Bcf/d, with residential and commercial declines accounting for the bulk of the declines, according to S&P Global Platts Analytics. Gas-fired generation dropped 800 MMcf/d as a rally in spot prices led to gas losing market share to coal generation. The NYMEX Henry Hub March contract dipped 5 cents to $2.85/MMBtu in trading following the release of the weekly storage report. The upcoming summer strip, April through October, fell 5 cents to average $2.92/MMBtu, up about 3 cents from the week prior. Still, gas prices rose across the board this week. Strong cash market gains from robust demand and production freeze-offs have helped to elevate market forwards. Henry Hub cash prices spiked to more than $5 in Feb. 11 trading while regional markers in the Midcontinent, Rockies, and Texas sailed past $10. The upcoming two storage reports should erase the surplus to the five-year average for the first time since 2019 – placing end-of-March inventories on course to potentially come in below 1.5 Tcf. Platts Analytics’ supply and demand model currently forecasts a 265 Bcf withdrawal for the week ending Feb. 12, which would prove more than 100 Bcf above the five-year average draw. Colder-than-normal weather has increased week-on-week demand by 12.6 Bcf/d relative to the prior week. The residential-commercial sector paced the demand growth – averaging 9.8 Bcf/d above the prior week while gas-fired generation rose 1.6 Bcf/d as wind generation fell and loads increased. In addition, widespread freeze-offs from severe cold and wind have taken 1.5 to 2 Bcf/d of production offline currently in the Midwest and Texas. With the worst of the cold weather slated to hit the Midwest and Texas this weekend and early next week, further price spikes are likely, which could force demand-side curtailments to balance on the likelihood of additional production freeze-offs. A very early forecast for the week ending Feb. 19 points to a 365 Bcf withdrawal. The largest weekly storage drop on record stands at 359 Bcf during the week ended Jan. 5, 2018. During that week, a “bomb cyclone” blasted its way across the US, prompting freeze-offs and pipeline-related outages in Appalachia, Permian, Anadarko, and the Bakken, resulting in a 3 Bcf/d drop in production.
Natural Gas Forwards Brush Off Ice, Snow Draping Lower 48; Higher Prices Still to Come – Bitterly cold temperatures blanketed the Lower 48, and the deep freeze threatened to curb output throughout most of the country’s production basins. Long-held storage surpluses have quickly eroded and export demand continues to fire on all cylinders. It was, by all considerations, the perfect storm to send natural gas futures rocketing sharply higher. And yet, in anti-climatic fashion, natural gas futures failed to sustain a $3 handle during the Feb. 4-12 period, slipping a couple of cents on the week to settle Friday at $2.912/MMBtu. The rest of the curve also barely budged, with modest losses at the front of the curve and meager gains further out. U.S. markets moved similarly, with very small changes across the majority of forward curves. Instead, all the wild swings happened in the cash markets this week, with prices screaming higher as sub-zero temperatures draped across a large swath of the country’s midsection. With a train of winter blasts tracking through the Lower 48 and heading east, there were the usual price gains in the Northeast, but market hubs in the normally quiet Midcontinent market also got in on the action. By Friday, spot gas at Oneok Gas Transmission, or OGT, had surged as high as $600 as the mercury in Oklahoma was set to fall to near zero overnight. Up to 10 inches of snow also was possible. It’s not that futures traders haven’t expressed at least some enthusiasm for the winter blast. March Nymex futures have made brief appearances above $3.000/MMBtu on a couple of occasions. It’s just that prices quickly reversed course any time that level was reached. The prompt month settled Wednesday at $2.911 and then continued to languish through Friday. Forward Look – Learn More “The coldest pattern of the past two years keeps getting sold after each bounce to $3. The back end of the forecast being warm weighted for Feb. 22-27 does stand out,” said NatGasWeather. “However, there’s still three much larger-than-normal draws lined up that will flip surpluses of 152 Bcf to deficits over 200 Bcf, which isn’t bearish.”
Drilling will stop on controversial oil well 150 miles from South Florida after company finds the well too dry – A company will stop drilling a controversial oil well it started in December about 150 miles from the South Florida coast, after saying it did not find a valuable oil source. Bahamas Petroleum Company began drilling the exploratory well off the west coast of Andros Island on Dec. 20, despite wide criticism from Bahamian conservation groups as well as a group of U.S. Representatives led by Alcee Hastings. After six weeks of drilling, the company said it found oil, but a not a commercial quantity of it. BPC plans to plug and abandon the well in the next few days and move its drillship, Stena IceMax, away from the site. The Port of Palm Beach was used as a hub for a supply ship assisting the Stena IceMax during its drilling. The project drew concern in Florida over the possibility that a spill could cause major problems for tourism, fishing, diving, coral reefs, wildlife and the environment, particularly in South Florida and the Florida Keys. The drilling shutdown is good news for the project’s opposition. “Offshore drilling in the Bahamas is dangerous for both the country’s tourism-driven economy and its pristine waters,” said Diane Hoskins, offshore drilling campaign director for Oceana, an international organization that advocates for ocean conservation. “We hope the Bahamian government takes this as a sign to stop this senseless journey. The United States and the Bahamas have a shared interest in preventing the associated devastation to our climate, coastal communities and economy.” Despite the victory for conservationists, the battle isn’t over. BPC said it hasn’t yet decided whether or not to drill in the area again in the future, saying its focus now is to shut down the well it was working on.
Shelby Co. Commissioners delay vote on controversial Byhalia Pipeline – Plans for the controversial Byhalia Pipeline remain up in the air, despite another night of fiery debate. Shelby County Commissioners were set to vote on whether to sell two parcels of property for the Byhalia Pipeline project Monday but delayed a vote which would allow the Byhalia Connection Company to purchase land in area code 38109. Opponents argue the pipeline could pollute the water in the neighborhood, while the company argues it could boost the economy. “An oil spill would be devastating to this community and there is nothing, no safety measures to prevent a spill from occurring,” said Justin Pearson. Content Continues Below Pearson is the co-founder of Memphis Communities Against Pipeline. The organization protested outside of the Shelby County Commissioner meeting urging leaders to keep a moratorium in place that would block interested buyers like the Byhalia Connection Company from purchasing two parcels of land in area code 38109. The company plans on building a 49-mile crude oil pipeline that would run from Memphis to Marshall County, Mississippi. “We’ve been inside the community and we have yet to find a single resident who says ‘oh I do want a crude oil pipeline going through my water, oh I want a crude oil pipeline going through our neighborhood and disrupting our future,'” said Pearson.
Byhalia Pipeline Project Gets Final Permit, Can Begin Construction –The Byhalia Connection Pipeline now has all permits needed to begin construction, company officials said Tuesday. The 49-mile pipeline is proposed to run from the Valero refinery near Presidents Island to Marshall County, Mississippi. It’s a joint venture between Valero and Plains All American Pipeline. It would connect several other pipelines and, eventually, carry crude oil to the Gulf of Mexico. The project needed approval from the Tennessee Department of Environment and Conservation, which officials said it received. The pipeline also needed approvals from U.S. Army Corps of Engineers offices in Tennessee and Mississippi. The project received those permits “as of last week,” said Katie Martin, communications manager with Plains All American Pipeline. The company notified elected officials about the permits Monday but could not release the information publicly until today, following the release of the company’s earnings. “Following more than 10,000 hours of environmental field study and analysis, the Byhalia Connection Pipeline project has obtained the U.S. Army Corps of Engineers Nationwide Permit 12, a federal permit only available for projects that will have minimal impacts on the environment,” Martin said. “Obtaining the Nationwide Permit 12 is a key step in the project; we look forward to safely and responsibly building and operating a pipeline that will be a long-term benefit to the community.” With permits in hand, Martin said the company can begin construction. Though, it hasn’t decided when construction would begin, she said. Once it begins, the company has projected construction would take nine months. However, some properties have not yet been secured by the company. A court hearing on a lawsuit from a group of landowners was slated to begin this week.
Oil company files plan to build tanks, pipeline over historic slave cemeteries – Thick woods overtook the old St. Rosalie Plantation house more than 70 years ago.But to the people of Ironton, a community of modest homes just south of those woods, St. Rosalie remains a powerful symbol of Black heritage in the heart of what used to be a bastion of White supremacy — Plaquemines Parish.And now, plans to build a new oil export facility on St. Rosalie are raising concerns about whether a key part of that heritage could be erased.Nearly 200 years ago, a free Black man named Andrew Durnford owned and operated a sugar plantation at St. Rosalie, along the west bank of the Mississippi River. Durnford died a few years before the Civil War and left the plantation to his widow and children. Records show the Durnfords enslaved Black workers, but also paid them wages during the Civil War. Once emancipated, those workers founded the town of Ironton just south of the plantation.Durnford and his family were laid to rest in above-ground tombs in one spot on the St. Rosalie property, close to where La. 23 now passes by. About a quarter-mile closer to the river, enslaved people were buried in an area of unmarked graves.The existence of the historic graves was no secret. Documents stored in the Tulane University Archives include lists of workers’ names and references to the enslaved people who died at St. Rosalie. Official maps in the 1920s and 1940s clearly marked two cemetery locations, and Ironton residents who hunted in the woods there knew exactly where the burial grounds were. “We would see the graves,” said Wilkie DeClouet, a retired Jefferson Parish sheriff’s deputy who lives in Ironton. “We knew the graves was there, but we know to go around and you respect that kind of stuff.”
The Sunniest City in Texas is Expanding … Natural Gas Production –The Newman Power Station, a natural gas plant just across the Texas border in El Paso, is responsible for nitrogen oxide and volatile organic compound emissions, which can form ozone, or smog. Last August, El Paso had one of itsworst days of air pollution in nearly 20 years, as ozone and particulate matter levels spiked sharply. Although it’s likely that the summer’s record-breakingWest Coast wildfire season contributed to the pollution peak, El Paso’s air quality has been worsening over the past few years, driven mainly by local sources like cars, refineries, and industrial plants. In 2020, data from the Environmental Protection Agency (EPA) shows that compared to its five-year average, the El Paso region experienced 20 fewer “good” air quality days per year and four more “bad” air quality days, which can be dangerous for vulnerable populations. “The power plant has been here as long as I can remember,” says Lara, who grew up in Chaparral and now lives in nearby Las Cruces. “It affects me, and my family and friends, the people I care about in this community.” She worries that in the future, her son might develop asthma, as she has from breathing in excess pollution. Her father, who has lived near the plant for three decades, developed a chronic lung condition that leaves him winded. Last year, El Paso Electric, the company that owns and operates Newman Power Station, proposed upgrading the plant with more efficient generators and decommissioning older, more polluting equipment that is, in some cases, more than 60 years old. While the company says that the new generators will lead to a 25 percent reduction in greenhouse gas emissions, the plant will still create ozone-causing emissions. In December, the New Mexico Public Regulations Commission, which oversees utilities, rejected El Paso Electric’s proposal, saying that the plant would be obsolete within a few years under the state’s clean energy mandates. By 2045, El Paso Electric will not be able to sell any natural gas-generated electricity to its New Mexico customers-and the state agency won’t make residents pay for a project they can’t use. But nothing is stopping the company from selling all of its natural gas power to Texas, and making Texans pay the full price. The Texas Public Utility Commission has already approved the plan to upgrade the power plant. A representative from El Paso Electric told the Observer that the company is moving ahead on the upgrade as it waits for a final air permit from the Texas Commission on Environmental Quality (TCEQ).
US Oil, Natural Gas Permitting Drops 10% in January, but Majors in Permian Record Six-Month High Lower 48 onshore oil and gas permit approvals fell by 10% in January versus December to 1,688, with declines seen across all of the major basins, according to the latest monthly statistics compiled by Evercore ISI. The Permian Basin and Eagle Ford Shale combined to account for 52% of the total permit count, said the Evercore team of researchers led by James West. Among the oil-heavy plays, filings in the Permian fell by 99 or 12% month/month (m/m), while the Eagle Ford saw a drop of 73 or 35%. Permits in the Denver-Julesburg (DJ)/Niobrara formation fell by 73 or 35% m/m, and the Bakken Shale saw a reduction of 29 or 43% from the prior month. The Rockies region also included a 45% decline in the Powder River Basin (PRB) to 53 permits. The Permian decline was driven by independent exploration and production (E&P) companies, as permits granted to majors in the basin actually rose by seven to a six-month high of 47. ExxonMobil, Chevron Corp. and Royal Dutch Shell plc accounted for 25, nine and 11 Permian permits, respectively. Denver-based independent Ovintiv Inc. also saw an increase in Permian permits, up 15 or 49% m/m. As for the larger independents working in the basin, Occidental Petroleum Corp. (Oxy), Devon Energy Corp. and Pioneer Natural Resources Co. saw their permit counts fall by 47, 40 and 25, or 59%, 56% and 63%, respectively. The Eagle Ford decline was driven in large measure by Marathon Oil Corp. and ConocoPhillips, whose permit totals plummeted by 32 and 21, respectively, or 72% and 73%. The Bakken permit total of 38 was the lowest count since 2009, with the dropoff driven mainly by Marathon, ConocoPhillips and Devon. The report follows the sale by Equinor ASA of its Bakken portfolio in a deal valued at around $900 million, suggesting that sentiment around the Williston Basin may be cooling. The DJ/Niobrara decline was led by publicly traded companies, with only filed one permit for the basin, Evercore researchers said. The PRB downtrend, meanwhile, was led by Oxy, EOG Resources Inc. and privately held Anschutz Exploration Corp., whose permit counts fell by 85%, 47% and 90%, respectively.
US oil, gas rig count rises by 1 rig to 457, with improved oil prices a boost to E&Ps– The US oil and gas rig count moved up one to 457 in the week ending Feb. 10, rig data provider Enverus said, as growth slowed from double-digit rig increases in the previous two weeks, even with WTI oil prices improving toward $60/b. The week’s single net rig add came on the oil side, as rigs chasing that commodity moved up three to 338, while those chasing natural gas were down two to 119. The rig count had seen double-digits gains in four of the past nine weeks, growing by 26 over the previous two weeks, as operators added rigs to maintain production. Nationwide rig totals have risen 64% since the early July low of 279, according to Enverus. Among the eight largest plays for the week ended Feb. 10, the Permian showed the most change, with three rigs added for a total 208, marking the highest count for the basin since early May 2020. Three plays added one rig: the Eagle Ford Shale (35 rigs) in South Texas, the DJ Basin (10) in Colorado and the Utica Shale (10), mostly in Ohio. The Marcellus Shale (32) mostly in Pennsylvania, and the Bakken Shale (13), mostly in North Dakota, each shed two rigs. Rig totals in both the Haynesville Shale (50) of East Texas/Northwest Louisiana, and the SCOOP/STACK (16) of Oklahoma were unchanged on the week. WTI oil, which plunged into the $20s/b as the pandemic took hold last March and was in the $40s/b for most of H2 2020, is now trading in the $58/b range, providing some comfort for E&P operators after a worrisome year. For the week ended Feb. 10, WTI averaged $57.62/b, up $3.91 week on week; while WTI Midland averaged $58.54/b, up $3.96; and the Bakken Composite price averaged $56/b, up $5, according to S&P Global Platts. Natural gas prices also fared well. Prices at Henry Hub averaged $3.29/MMBtu, up 43 cents; while prices at Dominion South averaged $3.04/MMBtu, up 45 cents. Although commentary on fourth-quarter earnings calls seemed “restrained,” in the words of one analyst, upstream executives showed a clearly optimistic attitude for the industry near term.
U.S. Oilfield Workforce Climbs in January for Fifth Consecutive Month – Employment in the U.S. oilfield services (OFS) and equipment sector climbed for the fifth consecutive month in January, according to preliminary data from the Bureau of Labor Statistics (BLS) and analysis by the Energy Workforce and Technology Council. “After shedding nearly 102,000 jobs from March to August due to pandemic-related demand destruction, the upstream oil and gas industry has added back approximately 21,000 positions over the past five months,” the Council noted. An estimated 8,421 jobs were added in January. The sector gained an estimated 5,717 jobs in October, 3,651 in November, and 933 in December, the BLS data showed. “OFS sector employment rose 1.4% in January as companies reopened some production to prepare for expected demand increases as more people are vaccinated,” researchers noted. “Uncertainty remains because of the high number of Covid-19 cases, which continue to suppress demand.” The monthly Oilfield Services and Equipment Employment Report, compiled and published by the Council, which represents 600 OFS members, estimated job losses from demand destruction because of Covid-19 now total 81,061. Since January 2020, about 80,014 jobs have been lost across the domestic OFS sector. Estimated OFS sector jobs in the United States declined from 706,528 in February 2020 to 625,467 last month, down 11.5%. “Losses were heaviest in April, when the sector shed 57,294 jobs – the largest one-month total since at least 2013,” the Council noted. “The jobs lost in 2020 represent annual wages of approximately $15.4 billion.” Job losses were heaviest among companies that provide support services for oil and gas extraction. This portion of the OFS sector has cut 72,580 jobs since the pandemic’s onset – 89.5% of the sector’s total job losses. OFS job losses last year were estimated to be heaviest in Texas, down 56,200, and in Louisiana, which lost 10,800 jobs. The states are the two leaders for oil and gas production, the Council noted. According to the BLS data, oil and gas jobs cut last year also were in order Oklahoma, 9,800; Colorado, 5,200; New Mexico, 4,800; California, 4,700; Pennsylvania, 4,600; North Dakota, 4,000; Wyoming, 2,900; Ohio, 2,100; Alaska, 2,000; and West Virginia, 1,900.
Lower 48 DUC Count Falling to ‘Normal’ by Year’s End, Says Raymond James – The Lower 48’s ample supply of drilled but uncompleted wells, aka DUCs, is coming down at a quick pace and is expected to reach “normal” levels by year’s end, tightening the oil supply according to Raymond James & Associates Inc. In a note to clients, Raymond James analyst John Freeman made the case that the U.S. Energy Information Administration (EIA) may be overstating the number of actual DUCS not yet completed. The EIA in the most recent Drilling Productivity Report for December said the total DUC inventory across seven main Lower 48 regions stood at 7,298, down from 7,443 in November. However, the EIA’s DUC count is 22% “too high and contains many older wells that are likely to never be completed,” according to Freeman. The federal data contains a “plethora of DUCs drilled back as far as 2014 that are ‘dead in the water.'” Even if the older DUCs were to be finished, they “would not produce at near the rate as wells drilled with cutting-edge technology and lateral lengths.” In addition, the escalation in mergers and acquisitions last year across the exploration and production (E&P) sector consolidated a lot of onshore acreage. That has led E&Ps to build larger, more efficient pads with more wells. The additional wells have created a more “normal” DUC inventory than years past. What Freeman sees in Raymond James data is the DUC inventory reaching “normal levels by the end of this year” at the current pace that E&Ps are finishing them. That would require “more spending to hold completions levels flat in 2022 and constraining supply growth.” The pandemic created a historic cut to energy demand, which led to a tremendous work-in-progress inventory of DUCs, he noted. Finishing those wells began in earnest in the second half of 2020, as E&Ps eschewed more development capital spending to concentrate on what they had in inventory.
Experts say Joe Biden’s energy moves could benefit Texas | The Texas Tribune – Surrounded by refineries and chemical plants that make up the Houston Ship Channel, the Republican leader of the U.S. House stood last week along what he called “one of America’s success stories.” A cadre of Texans in Congress flanked U.S. Rep. Kevin McCarthy of California to continue a campaign of criticisms they’ve lobbed at President Joe Biden’s climate-focused agenda. Biden’s swift moves to combat global warming have brought equally quick criticisms from state officials that Texas oil and gas jobs are in danger. But their comments often ignore that there is a global push in the free market – not just from the White House – to limit reliance on fossil fuels. And their rhetoric belies the benefits Texas’ oil and gas sector could see from Biden’s early moves. “Unfortunately, our economic bedrock of oil and gas is under attack by an administration that is bent on eliminating millions of jobs,” said U.S. Rep. Brian Babin, R-Woodville, one of seven Texas lawmakers who joined McCarthy last week in front of one of the busiest cargo ports in the world. Even before Biden took office last month, Texas lawmakers had forecasted doom and gloom for the state’s energy industry, projecting the sector’s demise at the hands of the new president. Even Texas Democrats have swiftly pushed back against Biden’s early moves aimed at protecting the environment. However, the percentage of jobs in the oil and gas industry had begun steadily declining, both in Texas and nationwide, long before Biden took office. At the beginning of 2020 – before the coronavirus pandemic and a global drop in the demand for oil – the share of jobs in the Texas oil and gas field had fallen to about 1.8%. Over the last decade, the percentage of jobs that are in the oil and gas industry has steadily declined, both in Texas and nationwide. The industry in Texas was especially affected after Saudi Arabia in 2014 ramped up oil production, leading American oil producers to cut jobs while still producing lots of oil. A majority of Americans have said they are interested in a clean and safe environment. Their spending habits increasingly demonstrate that, which experts say poses a much larger threat to the Texas oil and gas industry than Biden does. And, in the short term, Biden’s moves may help Texas, some say. “Basically every executive action Biden’s taken is good for Texas oil and gas,” said Michael Webber, energy professor at the University of Texas at Austin.
Democratic state lawmakers want to tax flared, vented natural gas. Texas oil industry says no. -Environmental groups are pushing state lawmakers to impose a new tax: a 25% levy on gas that is vented or flared as part of the oil extraction process. Currently, this byproduct of oil production is exempt from state taxes normally levied on natural gas production, as it is burned off and released into the atmosphere instead of being captured and brought to market.Groups such as the Environmental Defense Fund and Earthworks are hoping to curb this release of greenhouse gases by making it more expensive for energy producers to flare or vent gas than it would be to invest in the necessary infrastructure to capture and transport it.”Texas is one of the top oil and gas producing states, and as a byproduct of pulling oil out of the ground, this gas comes out – the same gas we use in our homes to cook our food,” said state Rep. Vikki Goodwin, an Austin Democrat who wrote a bill to tax flared or vented gas. “But for oil producers, they see it as a waste product. Rather than figuring out how to sell it or how to use it on-site, they’re basically just throwing it away.” In addition to leading the nation in oil and gas production, Texas is a leader in the amount of natural gas that is vented and flared, according to the U.S. Department of Energy. In 2019, Bloomberg reported that oil producers in the Permian Basin were burning off enough gas to power every residence in the state.The industry and its regulators have since taken steps to tamp down the practice. Several oil and gas companies and trade associations formed a coalition aimed at limiting flaring and methane emissions, and the Texas Railroad Commission, which regulates the oil and gas industry, adopted rules requiring more detailed disclosures from companies seeking flaring permits.In light of those steps, Todd Staples, president of the Texas Oil and Gas Association, said a tax on flared or vented gas could create unnecessary burdens for companies that are already moving toward eliminating the practice. But environmental groups, concerned by the volume of pollutants being released into the atmosphere, say the energy industry in Texas is not moving quickly enough to make changes in the face of the growing threat of climate change. “This is a common sense bill that needs to be passed,” said Sharon Wilson, a senior field advocate at Earthworks. “It is unnecessary to be wasting this product, and it is an intense pollutant that is having an impact not just locally, but globally.”
Texas Group Sets Goal to End Routine Flaring – A group of organizations linked to the Texas oil and gas industry on Wednesday reported that they aim to end routine natural gas flaring in the state by 2030.The announcement from the Texas Methane and Flaring Coalition follows a decision Tuesday by the state’s energy regulator to defer flaring requests from various operating companies. A Bloomberg article posted to Rigzone deems the stance taken by the Railroad Commission of Texas (RRC) “uncharacteristically critical” of the industry practice.Calling flaring “‘a necessary last resort during an upset,'” one commissioner quoted in the Bloomberg article pointed out the RRC should be more vigilant about not approving flaring requests outside such situations. Another commissioner expressed similar sentiments.In a written statement emailed to Rigzone, the Coalition noted that it “considers routine flaring to be flaring of natural gas from new and existing wells/facilities during normal production operations when gas gathering, processing, or infrastructure are insufficient or unavailable.” Additionally, the group stated that it “supports industry’s continued progress to end routine flaring and shares a goal of ending this practice by 2030.” To be sure, it noted that certain situations warrant flaring for safety and environmental protection reasons. Members of the Coalition include more than 40 Texas operators as well as the following seven trade associations: Panhandle Producers and Royalty Owners Association (PPROA), the Permian Basin Petroleum Association (PBPA), the South Texas Energy and Economic Roundtable (STEER), the Texas Alliance of Energy Producers, the Texas Independent Producers and Royalty Owners Association (TIPRO), the Texas Oil and Gas Association (TXOGA), and the Texas Pipeline Association (TPA).
4.2-magnitude earthquake in Oklahoma, officials say — A 4.2 magnitude earthquake in Oklahoma was the largest in a swarm of temblors to rattle the state Friday, officials say. The large quake rumbled shortly before noon near Garfield and Noble counties, about 80 miles north of Oklahoma City, according to the U.S. Geological Survey. It was among about a dozen earthquakes in the area from late morning to early afternoon, geologists say. Hundreds reported feeling the quakes. A resident in Covington, which is near the epicenter, said the shaking knocked items off the walls of her home while others felt the earthquake as far as 30 miles away in Enid, the Enid News & Eagle reported. Earthquakes aren’t unusual for Oklahoma. Last year, about three dozen above a 3.0 magnitude were reported in the state, the newspaper reported. Oklahoma has experienced a “surge in seismicity” since 2009, even topping California for more 3.0-magnitude quakes from 2014-2017, according to the U.S. Geological Survey. “While these earthquakes have been induced by oil and gas related process, few of these earthquakes were induced by fracking,” U.S. Geological Survey officials say. Most temblors in the state are caused by wastewater disposal from oil and gas production in which fluid is injected deep below drinking water aquifers, officials say. About 90% of wastewater that’s injected is a byproduct of oil extraction process, not waste frack fluid, officials say.
Big Oil Gets to Teach Climate Science in American Classrooms – – If you were an elementary school student in Oklahoma, you might meet Petro Pete, a cartoon child outfitted in the overalls and hard hat of an oil rig worker. Through Pete, you might learn things like “having no petroleum is like a nightmare!” Meanwhile Pete’s trusty blue dog, Repete, assures the animal kingdom that “the humans learned their lesson and now they don’t leave behind a mess when they drill for oil.” Who would you have to thank for these important academic messages? Oklahoma Oil & Natural Gas, a fossil fuel industry trade group. In Ohio, children may complete a word search sponsored by the state’s oil and gas industry, with answers such as “lubricants” and “carbon black,” while in New Jersey students in grades three through six may receive a workbook titled “Natural Gas: Your Invisible Friend.” The National Energy Education Development Project, backed by 100 oil and gas industry players, promotes lessons on fracking using Jell-O and other fun foods as teaching aids. The stakes for how children and young adults learn about climate change-the science, the politics, the implications-are extremely high. Environmentalists know this. So, clearly, do fossil fuel companies. “Industry groups recognized the value of classrooms for marketing and propaganda decades ago,” says Carroll Muffett, president and chief executive of the Center for International Environmental Law. “It’s where you shape someone’s understanding of your product and of your company and of your issues. In a school context, you’re shaping their understanding of the world.” One of the many ironies of K-12 education on climate change is that among the parents, at least, there’s little discord. More than 80% of parents said that they want schools to teach their children about climate change, according to a 2019 NPR/Ipsos poll. That survey also found that whether people have children or not, nine out of 10 Democrats and two-thirds of Republicans agree that the subject needs to be taught in schools. Yet the forces trying to suppress accurate science teachings remain relentless, says Elizabeth Allan, president of the National Science Teaching Association. Allan teaches climate change to many students in Oklahoma whose parents work in the oil industry, and they come to class with preconceived ideas about what climate change is and isn’t. “When I’m talking to them, it doesn’t lessen the science,” she says, “or the need for them to understand or examine fossil fuels and human contributions to it.”
Biden administration delays Trump rule allowing companies to pay less money for drilling on federal lands – The Biden administration is delaying a Trump administration rule that was expected to result in the oil and gas industry paying less money for drilling on public lands and waters. The administration announced on Thursday that the rule, which was slated to go into effect next Tuesday, will now not become effective until April 16. Interior will also start a 30-day comment period to allow for “additional engagement” on the rule. “The Trump administration sought to allow corporations to pay less money for the oil and gas resources they extract from public lands, which deprives American taxpayers from a fair return and would result in lost tax revenue for state and local governments,” a department spokesperson said in a statement. “As part of the ongoing review directed by President Biden, the Department of the Interior is reviewing this rule to ensure that corporations aren’t unfairly pocketing money that is owed to the American public,” the spokesperson added. The rule, which was finalized in January, changed the way that royalties companies pay to the government for drilling on federal property is calculated and was expected to decrease how much the government collects by $28.9 million each year. This amounts to less than 0.5 percent of the total federal oil and gas royalties it collected in 2018, the rule notes. When he proposed the rule in August, then-Interior Secretary David Bernhardt said in a statement that it would provide “regulatory certainty and clarity to States, Tribes and stakeholders, removing unnecessary and burdensome regulations for domestic energy production.” The rule’s promulgation followed a request from a leading industry lobbying group, the American Petroleum Institute, for changes to how royalties are calculated.
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