Oil, Gas, And Fracking News Reads: 22December 2019 – Part 1

Written by rjs, MarketWatch 666

Here are some selected news articles from the week ended 21 December 2019.

This article is a feature every Monday evening on GEI.

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November had largest fracking drop in 57 months; natural gas rigs fell to 3 year low while oil rigs rose most in 22 months

Oil prices hit three month highs on three days this week on their way to rising for the 6th time in seven weeks, but gave up most of their gains for the week in Friday profit taking ahead of the holidays…after rising 1.5% to a three month high at $60.07 a barrel on hopes for a US-China trade deal last week, the benchmark price of US light sweet crude for January delivery opened lower and slipped to $59.17 as confidence about the U.S.-China trade deal was tempered by the agreement’s limited nature and lack of details, but then recovered later in the session to settle 14 cents higher at a three-month closing high of $60.21 a barrel on renewed trade optimism boosted by the better U.S. manufacturing and services data released earlier…oil prices then moved higher for a fourth consecutive day on Tuesday in a positive response to further details on the trade agreement between the U.S. and China and finished 73 cents higher at another 3 month high of $60.94 a barrel after Trump’s economic adviser Larry Kudlow predicted U.S. exports to China would double under the deal…after a Tuesday evening report from the API indicated surprise large build of crude inventories, oil prices opened lower on Wednesday, but recovered midday after the EIA reported crude oil inventories had actually decreased by an expected 1.1 million barrels and ended down just a penny at $60.93 a barrel …oil prices were back at three-month highs again on Thursday as thawing US-China trade relations supported financial markets, as trading in the January oil contract ended 29 cents higher at $61.22 a barrel, while the contract for February US oil finished 33 cents higher at $61.18 a barrel…however, oil prices moved sharply lower on Friday after Baker Hughes reported that the number of active U.S. rigs drilling for oil rose by 18, the biggest jump in 22 months, and as oil traders took profits ahead of upcoming holidays and oil ended down 74 cents, or 1.2%, at $60.44 a barrel…nonetheless, oil prices still finished up slightly for the week, with US crude 37 cents or less than one percent higher when compared to last Friday’s close, while the February oil contract was 46 cents higher on the week…

Natural gas prices also ended a bit higher this week, after hitting an all time low the prior Monday…after recovering from $2.158 per mmBTU to close the week 1.6% lower at $2.296 per mmBTU last week, the price of natural gas for January delivery rose 4.5 cents to $2.341 per mmBTU on Monday on forecasts confirming cold weather and high heating demand this week, despite an outlook showing next week would be warmer than previously expected…but trading on the longer term forecast came to the fore on Tuesday, as natural gas prices slid 2.2 cents, and then fell another 3.3 cents on Wednesday as a forecast for this December’s total demand (GWDD) to be very close to the warm December of a year ago hit prices again….prices even fell another 1.3 cents on Thursday, despite an EIA report that withdrawals from natural gas inventories were much greater than expected…but natural gas prices reversed on Friday when the forecasts did, rising 5.5 cents to close the week 1.4% higher at $2.328 per mmBTU, as weather models began to feature colder changes through early January…

The natural gas storage report for the week ending December 13th from the EIA indicated that the quantity of natural gas held in storage in the US decreased by 107 billion cubic feet to 3,411 billion cubic feet by the end of the week, which left our gas supplies still 618 billion cubic feet, or 22.1% higher than the 2,793 billion cubic feet that were in storage on December 13th of last year, but 9 billion cubic feet, or 0.3% below the five-year average of 3,420 billion cubic feet of natural gas that have been in storage as of the 13th of December in recent years….the 107 billion cubic feet that were withdrawn from US natural gas storage this week was somewhat more than the average forecast for a 93 billion cubic feet withdrawal by analysts surveyed by S&P Global Platts, but was below the average 112 billion cubic feet of natural gas that have been pulled from natural gas storage during the second week of December over the past 5 years. as well as below the 132 billion cubic feet withdrawal reported during the corresponding week in 2018…

The Latest US Oil Supply and Disposition Data from the EIA

US oil data from the US Energy Information Administration for the week ending December 13th indicated that because of an increase in our oil exports and a decrease in our oil imports, we had to pull oil out of our stored commercial supplies to meet our refining needs for the fourth time in the past fourteen weeks…our imports of crude oil fell by an average of 308,000 barrels per day to an average of 6,579,000 barrels per day, after rising by an average of 899,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 233,000 barrels per day to an average of 3,633,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 2,946,000 barrels of per day during the week ending December 13th, 541,000 fewer barrels per day than the net of our imports minus our exports during the prior week…over the same period, the production of crude oil from US wells was reportedly unchanged at 12,800,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production totaled an average of 15,746,000 barrels per day during this reporting week..

US oil refineries were reportedly processing 16,562,000 barrels of crude per day during the week ending December 13th, 35,000 fewer barrels per day than the amount of oil they used during the prior week, while over the same period the EIA reported that a net average of 155,000 barrels of oil per day were being pulled out of the supplies of oil stored in the US….hence, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from oilfield production, and from storage was still 661,000 barrels per day less than what our oil refineries reported they used during the week….to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA inserted a (+661,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting an error or errors of that magnitude in the oil supply & demand figures we just transcribed…however, since the media treats these figures as gospel and since they drive oil pricing and hence decisions to drill for oil, we continue to report them, just as they’re seen & believed by most everyone else (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) indicated that the 4 week average of our oil imports rose to an average of 6,411,000 barrels per day last week, still 15.1% less than the 7,549,000 barrel per day average that we were importing over the same four-week period last year….the 155,000 barrel per day net withdrawal from our total crude inventories was due to a withdrawal of 155,000 barrels per day from our commercially available stocks of crude oil, while the quantity oil stored in our Strategic Petroleum Reserve was unchanged……this week’s crude oil production was reported to be unchanged at 12,800,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was unchanged at 12,300,000 barrels per day, while a 7,000 barrel per day decrease to 481,000 barrels per day in Alaska’s oil production was not large enough to impact the final rounded national total…last year’s US crude oil production for the week ending December 14th was rounded to 11,600,000 barrels per day, so this reporting week’s rounded oil production figure was 10.3% above that of a year ago, and 51.9% 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…

US oil refineries were operating at 90.6% of their capacity in using 16,562,000 barrels of crude per day during the week ending December 13th, the same capacity utilization as the prior week, and well below the recent normal for the second week of December…as a result, the 16,562,000 barrels per day of oil that were refined this week was 4.9% below the 17,408,000 barrels of crude per day that were being processed during the week ending December 14th, 2018, when US refineries were operating at 95.4% of capacity….

With US refinery inputs consistently below those of a year ago, we’ll include here a graph of those, so we can try to see what has been happening…

The graph above of US refinery throughput came from a newsletter emailed daily by John Kemp, senior energy analyst and columnist with Reuters, which you can sign up for free here; it shows US refinery throughput in thousands of barrels per day by “day of the year” for the past ten years, with the past ten year range of our refinery throughput for any given date shown as a light blue shaded area, and the median of our refinery throughput, or the middle of the 10 year daily range, traced by the blue dashes over each day of the year….the graph also shows the number of barrels of oil refined for each week in 2018 traced by a yellow line, with our year to date oil refining for each week of 2019 traced by the red graph…we can thus see that with a few exceptions, 2018’s refining in yellow had been at the top of the historical range for most of the year, and that pace of refining in 2018 was generally beating the records set in 2017 (not shown)…however, with the sanctions imposed on Venezuelan crude at the end of January of this year, US Gulf coast refineries, which are configured to process the heavy sour crude that Venezuela produces, could not come up with adequate replacements for that crude to run at their optimum pace, and as you see, US refineries ran nearly 5% below the prior year’s pace through winter and spring, ultimately buying boatloads of Urals crude from the Russians to replace the Venezuelan crude they’d lost…then, just when those refineries were starting to get back to near normal early this fall, the Keystone pipeline carrying heavy sour crude from Canada sprung a leak and was shut down, again interrupting the flow of the type of crude those refineries need to run at their optimum...there has been an effort to replace that loss with releases from the Strategic Petroleum Reserve, but that was only marginally successful…but even though the Keystone pipeline has been up and running again for weeks now, US refinery utilization still continues nearly 5% below the prior year’s seasonal norms……

Even with the decrease in the amount of oil being refined, gasoline output from our refineries was higher, increasing by 87,000 barrels per day to 9,840,000 barrels per day during the week ending December 13th, after our refineries’ gasoline output had decreased by 188,000 barrels per day the prior week….but even with this week’s increase in gasoline output, our gasoline production was 4.8% lower than the 10,334,000 barrels of gasoline that were being produced daily over the same week of last year….on the other hand, our refineries’ production of distillate fuels (diesel fuel and heat oil) fell by 156,000 barrels per day to 5,072,000 barrels per day, after our distillates output had decreased by 35,000 barrels per day over the prior week…hence, after this week’s decrease in distillates output, our distillates’ production for the week was 6.0% below the 5,393,000 barrels of distillates per day that were being produced during the week ending December 14th, 2018….

With the increase in our gasoline production, our supply of gasoline in storage at the end of the week increased for the 6th time in twelve weeks and for the 12th time in 26 weeks, rising by 2,529,000 barrels to 237,297,000 barrels during the week to December 13th, after our gasoline supplies had increased by 5,405,000 barrels over the prior week….our gasoline supplies increased by less this week even though our exports of gasoline fell by 326,000 barrels per day to 590,000 barrels per day, because our imports of gasoline fell by 60,000 barrels per day to 519,000 barrels per day and because the amount of gasoline supplied to US markets increased by 529,000 barrels per day to 9,411,000 barrels per day….after this week’s increase, our gasoline supplies were 3.1% higher than last December 14th’s inventory level of 230,103,000 barrels, while they remained roughly 5% above the five year average of our gasoline supplies for this time of the year…

Even with the decrease in our distillates production, our supplies of distillate fuels rose for the 3rd time in 12 weeks and for 13th time in the past 37 weeks, increasing by 1,509,000 barrels to 125,096,000 barrels during the week ending December 13th, after our distillates supplies had increased by 4,118,000 barrels over the prior week…the increase in our distillates supplies was less this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, rose by 389,000 barrels per day to 4,120,000 barrels per day, while our exports of distillates fell by 156,000 barrels per day to 915,000 barrels per day, and while our imports of distillates rose by 16,000 barrels per day to 178,000 barrels per day….after this week’s inventory increase, our distillate supplies were 4.3% higher than the 119,900,000 barrels of distillates that we had stored on December 14th, 2018, while remaining 7% below the five year average of distillates stocks for this time of the year…

Finally, this week’s decrease in oil imports, combined with the increase in oil exports, meant our commercial supplies of crude oil in storage fell for the fourteenth time in twenty-seven weeks and for the nineteenth time in 47 weeks, decreasing by 1,085,000 barrels, from 447,918,000 barrels on December 6th to 446,833,000 barrels on December 13th…even after that decrease, our crude oil inventories were nearly 4% above the five-year average of crude oil supplies for this time of year, and were over 34% higher than the prior 5 year (2009 – 2013) average of crude oil stocks after two weeks of December, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first rose above 400 million barrels…since our crude oil inventories had generally been rising over this past year, except for the summer, after generally falling until then through most of the prior year and a half, our oil supplies as of December 13th were still 1.2% above the 441,457,000 barrels of oil we had stored on December 14th of 2018, and 2.4% above the 436,491,000 barrels of oil that we had in storage on December 15th of 2017, but at the same time were 8.0% below the 485,449,000 barrels of oil we had in commercial storage on December 16th of 2016…

This Week’s Rig Count

The US rig count increased for just the 2nd time in the past 18 weeks over the week ending December 20th, but still remains 24.9% below the count at the end of last year….Baker Hughes reported that the total count of rotary rigs running in the US increased by 14 to 813 rigs this past week, which was still down by 267 rigs from the 1080 rigs that were in use as of the December 21st report of 2018, and 1,116 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 their attempt to flood the global oil market…

The number of rigs drilling for oil increased by 18 rigs to 667 oil rigs this week, which was the biggest oil rig increase since February 9 2018, but still left 198 fewer oil rigs than were running a year ago, and much less than 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 decreased by 4 rigs to 125 natural gas rigs, which was the least number of natural gas rigs deployed since December 9th, 2016, an hence a 3 year low for natural gas drilling, down by 72 gas rigs from the 197 natural gas rigs that were drilling a year ago, and way down from 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 & gas, three rigs classified as ‘miscellaneous’ continued to drill this week; one on the big island of Hawaii, one in Washoe County, Nevada, and one in Lake County, California, in contrast to a year ago, when there were no such “miscellaneous” rigs deployed..

Offshore drilling activity in the Gulf of Mexico increased by one rig to 24 rigs this week, with the addition of another rig in Louisiana waters…as a result, the 23 rigs that are drilling in Louisiana waters plus the one that was drilling offshore from Texas this week matches the Gulf of Mexico rig count of a year ago, when 23 rigs were drilling offshore from Louisiana waters and one rig was drilling in Texas waters…since there are no rigs deployed off US shores elsewhere, nor were there a year ago, the Gulf of Mexico count for both years is also equal to the national total in both cases..

In addition to the rigs drilling in offshore waters, one rig also started drilling through an inland body of water in southern Louisiana this week, the first such inland waters rig in 7 weeks…however, that was still down by 2 from the inland waters count of a year ago, when three such rigs were drilling in southern Louisiana…

The count of active horizontal drilling rigs was up by 13 rigs to 706 horizontal rigs this week, which was still 234 fewer horizontal rigs than the 940 horizontal rigs that were in use in the US on December 21st of last year, and also well down from 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 2 to 56 vertical rigs this week, but those were still down by 13 from the 69 vertical rigs that were operating during the same week of last year….on the other hand, the directional rig count was was down by 1 to 51 directional rigs this week, and those were down by 20 from the 71 directional rigs that were in use on December 21st of 2018…

The details on this week’s changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes…the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of December 20th, the second column shows the change in the number of working rigs between last week’s count (December 13th) and this week’s (December 20th) count, the third column shows last week’s December 13th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running 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 21st of December, 2018…

As you can see from the above, the return of oil rigs to Texas’s Permian and Eagle Ford was what made the difference this week, in contrast to the falling rig count we’ve seen over most of this past year…25 oil rigs were started up in those two basins alone, while 4 natural gas rigs were shut down at the same time, with three of those gas rigs coming out of the Eagle Ford, which has 3 natural gas rigs remaining, while the Permian saw it’s only natural gas rig stacked…meanwhile, a net of ten rigs were added in Texas Oil District 8, or the core Permian Delaware, and another 5 rigs began operating in Texas Oil District 7B, which is usually thought of as east of the main Permian play but which now has 6 rigs deployed…with another rig added in New Mexico, we can figure that two of that total of 16 rigs were not actually targeting the Permian, but outside of digging thru the North America Rotary Rig Count Pivot Table (xls) for the individual well records, we can’t say for sure which ones on the basis of the summaries we’re provided with…outside of the natural gas rigs pulled from those two Texas basins, another gas rig was shut down in Pennsylvania’s Marcellus, while a natural gas rig was added in a basin not tracked separately by Baker Hughes (most likely in Louisiana or Oklahoma, as those are the states with unaccounted for increases)…we should also note that another rig was shut down in Mississippi this week, and the state now has 4 rigs operating, which puts their count below the 6 rigs that were operating in Mississippi a year ago, a reversal from last week when the year ago total was lower, as the rig count in Mississippi has been quite volatile, ranging from 1 rig to 6 rigs and back again over the past year…

DUC well report for November

Monday of this past week saw the release of the EIA’s Drilling Productivity Report for December, which includes the EIA’s November data for drilled but uncompleted oil and gas wells in the 7 most productive shale regions…for the ninth month in a row, this report showed a decrease in uncompleted wells nationally in November, as both drilling of new wells and completions of drilled wells decreased…..for the 7 sedimentary regions covered by this report, the total count of DUC wells decreased by 131 wells, falling from a revised 7,705 DUC wells in October to 7,574 DUC wells in November, which now represents 2.1% fewer DUCs than the 7,740 wells that had been drilled but remained uncompleted as of the end of November of a year ago…this month’s DUC decrease occurred as 1,069 wells were drilled in the 7 regions that this report covers (representing 87% of all U.S. onshore drilling operations) during November, down by 36 from the 1,148 wells that were drilled in October and the lowest number drilled since June 2017, while 1,200 wells were completed and brought into production by fracking, a decrease of 155 well completions from the 1,355 completions seen in October and the least completions since January, and the largest drop in completions since February 2015….at the November completion rate, the 7,574 drilled but uncompleted wells left at the end of the month now represents a 6.3 month backlog of wells that have been drilled but are not yet fracked, up from the 5.6 month backlog of a month ago…

Both oil producing regions and natural gas producing regions saw DUC well decreases in November, while 2 of the major basins saw minor DUC increases…the number of DUC wells remaining in the Oklahoma Anadarko decreased by 58, falling from 737 at the end of October to 679 DUC wells at the end of November, as 61 wells were drilled into the Anadarko basin during November while 119 Anadarko wells were being fracked….meanwhile, DUC wells in the Eagle Ford of south Texas decreased by 24, from 1,421 DUC wells at the end of October to 1,397 DUCs at the end of November, as 154 wells were drilled in the Eagle Ford during November, while 178 already drilled Eagle Ford wells were completed….in addition, the Permian basin of west Texas and New Mexico saw its total count of uncompleted wells fall by 20, from 3,579 DUC wells at the end of October to 3,559 DUCs at the end of November, as 468 new wells were drilled into the Permian, while 488 wells in the region were being fracked….at the same time, the drilled but uncompleted well count in the Niobrara chalk of the Rockies’ front range decreased by 10 to 490, as 160 Niobrara wells were drilled in November while 170 Niobrara wells were completed….on the other hand, DUC wells in the Bakken of North Dakota increased by 2, from 758 DUC wells at the end of October to 760 DUCs at the end of November, as 100 wells were drilled into the Bakken in November, while 98 of the drilled wells in that basin were being fracked…

Among the natural gas producing regions, the drilled but uncompleted well count in the Appalachian region, which includes the Utica shale, fell by 25 wells, from 497 DUCs at the end of October to 472 DUCs at the end of November, as 81 wells were drilled into the Marcellus and Utica shales during the month, while 106 of the already drilled wells in the region were fracked….however, the natural gas producing Haynesville shale of the northern Louisiana-Texas border region saw their uncompleted well inventory increase by 4 wells to 217, as 45 wells were drilled into the Haynesville during November, while 41 Haynesville wells were fracked during the same period….thus, for the month of November, DUCs in the five major oil basins tracked by in this report (ie., the Anadarko, Bakken, Niobrara, Permian, and Eagle Ford) decreased by a net of 110 wells to 6,885 wells, while the uncompleted well count in the natural gas basins (the Marcellus, Utica, and the Haynesville) decreased by 21 wells to 689 wells, although as this report notes, once into production, more than half the wells drilled nationally will produce both oil and gas…

Columbia Gas planning $135 million pipeline project for central Ohio— Columbia Gas is proposing construction on a new $135 million pipeline to be built in central Ohio. The company says a new supply of gas is needed in order to keep providing reliable service to old and new customers in the region. The project, which is called the Columbus Northern Loop project, is designed to bring natural gas from pipelines east of where supplies are plentiful to areas north and west of Columbus. The company says several other recent projects have already been finished, which have set the stage for the Northern Loop project. A company spokesperson says the project will cost $135 million, but could not offer any further breakdown regarding exact costs, stating that the project is in the early planning stages. The final phase is currently in the planning stages and will run from southern Delaware County to southwest Union County, where it will connect to the existing gas distribution system. Another part of the initiative, called the Marysville Connector project, is designed to bring natural gas to Union County. Columbia Gas says it will meet with property owners, public officials and other community members during the construction. Crews are planning to conduct land surveys and meet with property owners to gather information regarding where the new line could be located. The company says it hopes to have approval for the complete project secured by 2021. Construction would start in 2022 and the gas lines would go into service sometime during that same year.

Exxon Well Blast Caused Huge Methane Leak in Ohio, Study Shows –An Exxon Mobil Corp. natural gas well in Ohio released more methane into the atmosphere during a blowout in 2018 than some countries do in a year, according to a team of American and Dutch scientists. Using data from satellites, the researchers found that a well explosion in Belmont county on Feb. 15 of that year discharged the potent greenhouse gas at a rate of about 80 tons an hour and lasted for nearly 20 days. The end result was more methane in the air than the oil and gas industries of France, Norway and the Netherlands emit over a 12-month period, according to a study published Monday in the Proceedings of the National Academy of Sciences. “We deeply regret the event occurred and have instituted systematic well design and monitoring procedures to prevent it from happening again,” Exxon said in response to questions. Methane is 84 times more conducive to global warming than carbon dioxide over a 20-year period. All the world’s biggest oil and gas companies, including Exxon, have pledged to reduce methane emissions, which they see as an Achilles Heel for the industry.Satellites are beginning to track large accidental emissions that until recently remained undetected. A similar study this year unveiled a giantmethane plume in Asia. “Our work demonstrates the strength and effectiveness of routine satellite measurements in detecting and quantifying greenhouse gas emission from unpredictable events,” the scientists said in the study. “In this specific case, the magnitude of a relatively unknown yet extremely large accidental leakage was revealed.”

A Methane Leak, Seen From Space, Proves to Be Far Larger Than Thought – The first satellite designed to continuously monitor the planet for methane leaks made a startling discovery last year: A little known gas-well accident at an Ohio fracking site was in fact one of the largest methane leaks ever recorded in the United States. The findings by a Dutch-American team of scientists, published Monday in the Proceedings of the National Academy of Sciences, mark a step forward in using space technology to detect leaks of methane, a potent greenhouse gas that contributes to global warming, from oil and gas sites worldwide. The scientists said the new findings reinforced the view that methane releases like these, which are difficult to predict, could be far more widespread than previously thought. “With a single observation, a single overpass, we’re able to see plumes of methane coming from large emission sources,” Scientists also said the new findings reinforced the view that methane emissions from oil installations are far more widespread than previously thought. The blowout, in February 2018 at a natural gas well run by an Exxon Mobil subsidiary in Belmont County, Ohio, released more methane than the entire oil and gas industries of many nations do in a year, the research team found. The Ohio episode triggered about 100 residents within a one-mile radius to evacuate their homes while workers scrambled to plug the well. At the time, the Exxon subsidiary, XTO Energy, said it could not immediately determine how much gas had leaked. But the European Space Agency had just launched a satellite with a new monitoring instrument called Tropomi, designed to collect more accurate measurements of methane. The satellite’s measurements showed that, in Ohio in the 20 days it took for Exxon to plug the well, about 120 metric tons of methane an hour were released. That amounted to twice the rate of the largest known methane leak in the United States, from an oil and gas storage facility in Aliso Canyon, Calif., in 2015, though that event lasted longer and had higher emissions overall.

New satellite technology reveals Ohio gas leak released 60K tons of methane – A new report revealed that the first satellite designed to monitor the earth with a new instrument called TROPOMI for methane leaks discovered that an accident at a fracking site in Belmont County, Ohio, in February 2018 resulted in one of the worst methane leaks ever recorded in the US. The methane released into the atmosphere from the Ohio fracking site exceeded the annual output of all but three European countries.The findings were published on Monday in the Proceedings of the National Academy of Sciences by scientists from the EDF, SRON Netherlands Institute for Space Research, Vrije Universiteit Amsterdam, the Netherlands Organization for Applied Scientific Research, and Utrecht University.The article is titled, “Satellite observations reveal extreme methane leakage from a natural gas well blowout.” Methane is a potent human-made greenhouse gas that is responsible for more than 25% of global warming. The oil and gas industry is the largest source of methane. In the first two decades after its release, methane is 84 times more potent than carbon dioxide.As the Environmental Defense Fund (EDF) reports, “Emissions from the Ohio event would have totaled about 60,000 tons. That figure is comparable to one-quarter of the entire state of Ohio’s reported annual oil and gas methane emissions.”The EDF continues: For example, a five-year series of studies organized by EDF recently concluded that emissions from the US oil and gas sector were a full 60% higher than EPA estimates. These factors underscore the importance of regular, widespread monitoring and measurement, and explain the rapidly growing interest in space-based instruments, which have the potential to provide comprehensive estimates of methane emissions, how much, and where. TROPOMI provides a more accurate way to track methane leaks. And bravo to the Dutch and American scientists for uncovering the truth about the extent of the Ohio leak’s damage. The bad news: This leak was incredibly damaging to the environment. Further, the fact that emissions from fossil fuels turned out to be much worse than we originally thought, in general, is extremely alarming.

Scientists Say Blowout At Ohio ExxonMobil Site Was Worst Methane Leak In US History – Details are finally being revealed about a terrible blowout that occurred last year at a natural gas site in Ohio. The incident happened at a site owned by an ExxonMobil subsidiary known as XTO Energy, and was reportedly one of the largest leaks of its kind in the history of the country.The full extent of the blowout was never reported by the company but was discovered later by a group of scientists looking over satellite data of the area. A team of 15 Dutch and American researchers found that a blowout occurred on Feb. 15, 2018, at a natural gas well in Belmont County, Ohio. The leak that caused the blowout was reportedly the result of controversial fracking practicing at the well. The data showed that the methane emission rate of the leak was about 120 ± 32 metric tons per hour, which is twice the emission rate of the largest accidental methal leak in United States history, the Aliso Canyon event that took place in California in 2015.At the time of the leak, over 100 residents who were within a mile of the site were forced to evacuate their homes as workers rushed to get the situation under control. Meanwhile, XTO Energy did their best to downplay the severity of the situation, and insist that it was not possible for them to calculate exactly how much methane was leaked.Steven Hamburg, EDF’s chief scientist and one of the new study’s co-authors told the New York Times that these types of incidents probably occur on a regular basis, and researchers are hoping to be able to better understand precisely when they do happen so they can form a better opinion about whether or not fracking natural gas is safe and environmentally friendly. “Is this a once a year kind of event? Once a week? Once a day? Knowing that will make a big difference in trying to fully understand what the aggregate emissions are from oil and gas,”Hamburg said.

A Fracking Explosion In Ohio Created One Of Worst Methane Leaks In History – WOSU – In February 2018, an explosion at a fracking site in Belmont County, near the Ohio-West Virginia border, forced residents within a 1-mile radius to evacuate their homes for several weeks. A study this week in the Proceedings of the National Academy of Sciences revealed that the accident resulted in one of the largest methane leaks ever recorded in the U.S. Powhatan Point fire chief Tom Nelms was among the first to respond after the explosion. “At that time, that day, there were probably 50-80 people,” Nelms said. The fire lasted for three days, but some people weren’t able to return to their homes for weeks. Nelms says he knew the methane leak was a big deal, but at the time no one really understood the magnitude of it. Until now. A satellite designed to monitor Earth for methane leaks revealed that accident was one of the largest leaks recorded in the U.S.“The blowout and the period of time it was occurring contributed 60,000 tons of methane to the atmosphere, and it represents in the case of Ohio one-quarter of the annual emissions coming from the oil and gas industry,” says Steven Hamburg, one of the study authors and the chief scientist at the Environmental Defense Fund.In fact, the Belmont County incident released more methane than the reported emissions of oil and gas industries of entire European countries.“Methane is responsible for one-quarter of the warming that we’re currently experiencing,” Hamburg says. “It’s a very potent but short lived green house gas, so reducing those emissions will have the biggest impact on slowing the rate of warming.” He says because of the nature of the odorless, colorless gas, it’s really hard to know when a leak has occurred. “None of us pay attention to that which we can’t see or measure,” he says. “We’re giving the tools to be able to measure and quantify emissions around the globe which we didn’t have before.” The fracking site is owned by Exxon Mobil subsidiary XTO Energy. In an emailed statement, a spokeswoman for Exxon says they “regret the incident occurred, and have instituted systematic well design and monitoring procedures to prevent it from happening again.” Hamburg says this satellite can be used not just to hold companies like Exxon accountable, but also to help them reduce their methane emissions. That, he says, is in everyone’s best interest.

Gulfport Energy Corporation Announces Divestiture of Non-Core Assets for a Total Value in Excess of $100 Million and Provides an Update on Accretive Debt Repurchases — Gulfport Energy Corporation announced today that the Company has entered into agreements to divest certain non-core assets and provided an update on the continuation of discounted debt repurchases. Gulfport recently entered into a definitive agreement to divest its water infrastructure assets across its SCOOP position to a third-party water service provider. Gulfport expects to receive $50 million in cash upon closing and has an opportunity to earn potential additional incentive payments in excess of $50 million over the next 15 years, subject to Gulfport’s ability to meet certain thresholds which will be driven by, among other things, the Company’s future development program and future water production levels. The agreement contains no minimum volume commitments. The Company anticipates closing the transaction during January 2020. Scotiabank served as financial advisor to Gulfport on the divestiture of its water infrastructure assets. Separately, Gulfport also recently entered into an agreement to divest certain non-operated interests in the Utica Shale for approximately $29.0 million in cash. The Company anticipates closing the transaction prior to year-end 2019. In addition, the previously announced sale of certain overriding royalty interests associated with assets Gulfport held in the Bakken closed on December 11, 2019 and, net of purchase price adjustments, Gulfport received approximately $7 million of total proceeds.

The Plastics Pipeline: A Surge of New Production Is on the Way – – As public concern about plastic pollution rises, consumers are reaching for canvas bags, metal straws, and reusable water bottles. But while individuals fret over images of oceanic garbage gyres, the fossil fuel and petrochemical industries are pouring billions of dollars into new plants intended to make millions more tons of plastic than they now pump out. Companies like ExxonMobil, Shell, and Saudi Aramco are ramping up output of plastic – which is made from oil and gas, and their byproducts – to hedge against the possibility that a serious global response to climate change might reduce demand for their fuels, analysts say. Petrochemicals, the category that includes plastic, now account for 14 percent of oil use, and are expected to drive half of oil demand growth between now and 2050, the International Energy Agency (IEA) says. The World Economic Forum predicts plastic production will double in the next 20 years.“In the context of a world trying to shift off of fossil fuels as an energy source, this is where [oil and gas companies] see the growth,” said Steven Feit, a staff attorney at the Center for International Environmental Law, an advocacy group. And because the American fracking boom is unearthing, along with natural gas, large amounts of the plastic feedstock ethane, the United States is a big growth area for plastic production. With natural gas prices low, many fracking operations are losing money, so producers have been eager to find a use for the ethane they get as a byproduct of drilling.“They’re looking for a way to monetize it,“ Feit said. “You can think of plastic as a kind of subsidy for fracking.”America’s petrochemical hub has historically been the Gulf Coast of Texas and Louisiana, with a stretch along the lower Mississippi River dubbed “Cancer Alley”because of the impact of toxic emissions . Producers are expanding their footprint there with a slew of new projects, and proposals for more. They are also seeking to create a new plastics corridor in Ohio, Pennsylvania, and West Virginia, where fracking wells are rich in ethane. Shell is building a $6 billion ethane cracking plant – a facility that turns ethane into ethylene, a building block for many kinds of plastic – in Monaca, Pennsylvania, 25 miles northwest of Pittsburgh. It is expected to produce up 1.6 million tons of plastic annually after it opens in the early 2020s. It’s just the highest profile piece of what the industry hails as a “renaissance in U.S. plastics manufacturing,” whose output goes not only into packaging and single-use items such as cutlery, bottles, and bags, but also longer-lasting uses like construction materials and parts for cars and airplanes.

Environmentalists Question Future Gas Storage Hub In Light Of Federal Spending Language – Language included in the federal spending deal Congress passed this week could imperil a major natural gas storage project planned for the Ohio Valley that is seeking a $1.9 billion federal loan guarantee, according to environmental advocates. In June, an amendment by Democratic Reps. Ilhan Omar from Minnesota and Pramila Jayapal of Washington, sought to clarify requirements for the Department of Energy’s Title XVII Innovative Energy Loan Guarantee Program. The program was designed to finance clean energy and advanced technology projects. The amendment stipulates the program should only be used “for projects that avoid, reduce or sequester air pollutants or anthropogenic emissions of greenhouse gases and employ new or significantly improved technologies as compared to commercial technologies in service in the United States upon issuance of the loan guarantee.” Language from the amendment was included in the guidance document, or manager’s report, associated with the $1.4 trillion spending package snaking its way through Congress this week. The newly-passed spending package, which the president is expected to sign, provides $29 million to the Title XVII program. A screenshot of the manager’s report associated with the 2020 federal spending bill package, H.R. 1865. Some environmental groups argue the new language makes it clear the so-called Appalachian Storage and Trading Hub, a fossil fuel storage project, should not qualify. The project, which has been in the works for nearly a decade, would provide underground storage for natural gas liquids like ethane, which are used to make plastics and other products. It has the support of West Virginia’s Congressional delegation and Justice administration. Project developers are currently seeking a federally-backed $1.9 billion loan under the Title XVII program.

Pennsylvania correlates natural gas fracking with quakes – Pennsylvania environmental regulators say there‘s a likely correlation between a natural gas company‘s fracking operation and a series of minor earthquakes in western Pennsylvania last year. The state‘s Department of Environmental Protection revealed its findings Friday. The quakes were recorded in April in Lawrence County, about 50 miles north of Pittsburgh and three-quarters of a mile from a natural gas well owned by Houston-based Hilcorp Energy Co. They were too weak to be felt by humans and no damage was reported. Fracking is a method to extract gas or oil from underground shale rock. It has been tied to earthquakes in neighboring Ohio and other states, but never in Pennsylvania, the nation‘s No. 2 natural gas-producing state. Hilcorp stopped fracking at the well pad after the quakes.

Pa. rule to tackle air pollution from oil and gas wells advances – A proposed rule to cut down on air pollution released by Pennsylvania’s thousands of existing oil and gas wells is expected to eliminate tens of thousands of tons of methane emissions each year – but it won’t target the greenhouse gas directly nor will it require leak surveys at the vast majority of the state’s older wells.The state’s environmental rule-making board voted to advance the proposal on Tuesday for a period of public comment that will open early next year.The long-anticipated rule was promised by Gov. Tom Wolf in 2016 as part of a broader strategy to shrink the amount of climate-warming gases wafting out of both new and existing equipment used for producing Pennsylvania’s oil and gas.Instead of directly curbing methane, the regulation builds on a federal rule that targets smog-forming gases called volatile organic compounds released from tanks, pumps, compressors and leaky parts.Natural gas is mostly methane – a greenhouse gas that is 86 times more damaging at trapping heat in the atmosphere than carbon dioxide in the first two decades after it is released. Tamping down methane leaks from the oil and gas sector is seen as a relatively quick, cheap and effective step among more dramatic shifts in energy use that will be necessary to avoid the worst effects of climate change.“The new regulations will help identify and prevent leaks from existing wells and infrastructure, while protecting the environment, reducing climate change and helping businesses reduce the waste of a valuable product,” Mr. Wolf said. Unprocessed gas from Marcellus and Utica shale wells in Pennsylvania can range from 75% to 98% methane and from 0.1% to 10% volatile organic compounds by volume, according to state Department of Environmental Protection data.Volatile organic compounds are building blocks for ground-level ozone pollution, or smog, “a public health and welfare hazard that contributes to asthma and other lung diseases such as emphysema and chronic bronchitis,” DEP Secretary Patrick McDonnell said.DEP says the proposed controls will reduce volatile organic compound emissions by about 4,400 tons per year and methane emissions by about 75,600 tons per year.The annual methane reductions are the greenhouse gas equivalent of taking 364,000 passenger vehicles off the road for a year.

Pa. DEP and major oil companies agree: Trump administration shouldn’t roll back methane rules – Pittsburgh Post-Gazette – Several groups that often are at odds over environmental rules are on the same side when it comes to easing methane regulations at oil and gas sites.The Pennsylvania Department of Environmental Protection joined major oil and gas companies, environmental groups and lawmakers from both parties last week in urging the Trump administration not to go through with itsproposal to eliminate methane control requirements from well sites and pipelines across the country.The U.S. Environmental Protection Agency is proposing to roll back rulesadopted in 2016 that require companies to identify and stop methane leaks from new and modified oil and gas production, pipeline and storage equipment.The agency said existing controls on a separate class of chemicals that is also present in oil and gas – called volatile organic compounds, or VOCs – make direct regulation of methane redundant and unnecessary.The agency is also proposing an alternate rule to exempt the oil and gas storage and transmission sector from both the methane and volatile organic compound regulations.But major companies that would see restrictions lifted on their operations if EPA finalizes the rule – including Royal Dutch Shell, ExxonMobil, Total, Equinor and Canonsburg-based Equitrans Midstream – wrote that they want national rules directly targeting methane. Several of the companies said that easing methane regulations will erode public confidence in natural gas as a cleaner fossil fuel at a time when addressing climate change is an international priority. Comments on the proposals were due last week.

U.S. Chamber of Commerce warns of ‘catastrophic’ consequences of a potential fracking ban in Pa. – A new report from the U.S. Chamber of Commerce warns that Pennsylvania could lose as many as 600,000 jobs if the state ever moved to ban fracking, the controversial practice used to extract natural gas from the earth.Such a policy would have “catastrophic” consequences, according to Marty Durbin,president of the chamber’s Global Energy Institute.The study, which does not take into account climate or public health concerns, concluded Keystone State would lose 65,000 oil and natural gas jobs alone between 2021 and 2025, and take a $261 billion hit to the state GDP. That’s roughly a third of the state’s current GDP, according to federal data.The document also looked at a number of other oil and gas-producing swing states that will play a critical role in the 2020 elections. Nationally, the study predicted higher energy prices, a $7.1 trillion GDP hit, and 19 million jobs lost by 2025, if the U.S. banned the industrial process. The numbers include both direct and indirect effects. “In 2016, the notion was considered an extreme position, but today unfortunately we’ve seen many mainstream presidential candidates join in,” Durbin said in a press call.

DEP Sounds Alarm Over Revised Climate Change Predictions – In a new sobering report on climate change, the state Department of Environmental Protection on Thursday suggested the impact of rising seas could be much more dramatic along the New Jersey coast than previously projected, and twice as severe as elsewhere on the globe. The study, commissioned by DEP and prepared by Rutgers University and leading climate-change experts, portrayed a scenario that might force state policymakers to take more aggressive actions to deal with rising ocean levels. Whether that includes potential limits on building in coastal areas – as advocated by some conservation groups – remains to be seen. But the increasing likelihood coastal areas will be flood-prone in the future may boost those prospects. ‘’New Jersey has much to lose if we do not act quickly and decisively to adapt to the realities of climate change,’’ said DEP Commissioner Catherine McCabe. “These projections now serve as important baselines for developing policy directions, including changes to land use regulation that New Jersey adopt to address these challenges.’’ The report examines a variety of scenarios, based on differing greenhouse-gas emission rates. The highest – consistent with current global greenhouse gas-emission scenarios – projects a rise in sea levels ranging from 2.3 feet to as much as 6.3 feet by 2100, under the most aggressive carbon-pollution scenario. Perhaps more worrying, McCabe suggested so much greenhouse gas has already been spewed and baked into global warming predictions that severe effects by mid-century are inevitable.

Permanent ban on fracking proposed – A bill introduced Friday by Sen. Jennifer Metzger, D-Middletown, in the state Senate would permanently ban horizontal drilling, hydraulic fracturing and gelled propane hydraulic fracturing in New York state. New York is home to the Marcellus Shale, a source of oil and gas that also lies beneath much of Ohio, West Virginia and Pennsylvania. Roughly 18,700 square miles of the shale formation are in New York state. Metzger’s legislation also bans a practice called gelled propane fracturing, which uses propane gas because it is heavier than air.Metzger writes in her legislative justification that the legislation codifies the findings of the state DEC’s 2015 State Environmental Quality Review act findings statement on horizontal drilling and hydraulic fracturing. Metzger said since 2015, there have been additional studies that show public health harms related to hydraulic fracturing and horizontal drilling, including increased hospitalization rates, respiratory illness, reproductive risks including low birth weight and preterm births and dangers to at-risk populations. “The evidence is clear: Horizontal drilling and HVHF pose significant and unacceptable risks to New York’s drinking water, air quality, environment, climate, and public health,” Metzger wrote.“The legislative ban on Horizontal Drilling and High-Volume Hydraulic Fracturing (HVHF) and Gelled Propane Hydraulic Fracturing (GPHF) aligns with New York’s long tradition of pioneering leadership on environmental protection, public health, and climate change.” Metzger also cites the 2016 EPA report, “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States,” as evidence of environmental issues. In 2010, Congress asked the EPA to investigate the safety of hydraulic fracturing. A draft report was issued in 2015 followed by the final report in 2016.

U.S. denies N.Y. rehearing request on Constitution natgas pipe permit – (Reuters) – U.S. energy regulators have denied New York’s request for a rehearing on its decision that state environmental regulators waived their authority to issue or deny a water quality certification for Williams Cos Inc’s Constitution natural gas pipeline: * The U.S. Federal Energy Regulatory Commission (FERC) last week reaffirmed its prior decision, which New York had challenged. FERC had ruled that the New York Department of Environmental Conservation (NYDEC), because it took more than a year to reach a decision, waived its authority under section 401 of the U.S. Clean Water Act. * Officials at the NYDEC and Williams were not immediately available for comment. * Analysts at Height Capital Markets in Washington, D.C., said “the project still has a long road ahead given New York’s resistance to fossil fuel infrastructure development.” * Constitution and other gas pipelines into New York have been stuck in a nationwide battle between energy companies seeking more pipelines and environmental groups and New York Governor Andrew Cuomo, who favor boosting investment in energy efficiency and renewables. * In addition to Constitution, other gas pipelines have also been held up due to state opposition, including National Fuel Gas Co’s Northern Access from Pennsylvania to New York and Williams’ Northeast Supply Enhancement from Pennsylvania to New Jersey and New York. * Constitution is designed to transport 0.65 billion cubic feet per day of gas 125 miles (201 kilometers) from the Marcellus shale in Pennsylvania to New York. In 2018, New York state consumed about 3.7 bcfd of gas, up from 3.4 bcfd in 2017, according to federal energy data.

Fracking ban: Massive win or missed opportunity? – Tuesday marked five years since Gov. Andrew Cuomo’s administration first said it would ban large-scale hydraulic fracturing, the controversial method used to free gas from underground rock formations like the Marcellus Shale that stretches across the Southern Tier and Catskills. New York’s decision made it the first shale-bearing state to back a ban. And it put an end to a remarkable six-year period of debate, study and protest, where activists, landowners and gas companies clashed everywhere from small-town board meetings in the Southern Tier to the halls of power in Albany. The announcement – slowly unveiled at the state Capitol during a two-hour meeting of Cuomo’s cabinet a month after he was re-elected – was a huge victory for environmentalists and activists who galvanized across the state to fight for a ban. They warned the chemicals injected deep underground in the fracking process, as well as the associated boost in truck traffic and industrial activity, had the potential to wreak havoc on the state’s pristine waters, air and landscape. This is the story of how a single governmental decision five years ago has helped shape energy policy in New York and continues to affect the landowners, activists, regulators and energy industry representatives who spent years working to make their case.

U.S. natgas futures rise 2% on cold forecasts for this week and in January – U.S. natural gas futures rose 2% on Monday on forecasts confirming cold weather and high heating demand this week, despite an outlook showing next week will be warmer than previously expected. Traders noted the latest weather forecast also called for a likely return of cold in January. Front-month gas futures for January delivery on the New York Mercantile Exchange (NYMEX) rose 4.5 cents, or 2.0%, to settle at $2.341 per million British thermal units, the highest since Dec. 5. For the year, the front-month was on track to drop about 20%, which would be its third annual decline in a row and its biggest fall since 2017, when the contract lost about 21%. Meteorologists projected the weather in the U.S. Lower 48 states will turn from colder than normal from Dec. 17-19 to warmer from Dec. 21-29 before turning colder again on Dec. 31. That is much warmer than last week, when the outlook was for colder from Dec. 17-22 and Dec. 27-28. With the weather expected to moderate, Refinitiv predicted demand in the Lower 48 states, including exports, would fall from an average of 127.0 billion cubic feet per day this week to 121.4 bcfd next week. That is much lower than Refinitiv’s forecast on Friday of 127.4 bcfd for this week and 127.6 bcfd for next week. Gas flows to liquefied natural gas (LNG) export plants rose to 8.0 bcfd on Sunday from 7.9 bcfd on Saturday, according to Refinitiv data. That compared with an average of 8.0 bcfd last week and an all-time high of 8.2 bcfd on Dec. 8 with the ramp-up of new liquefaction trains at Freeport LNG’s plant in Texas and Cameron LNG’s plant in Louisiana. Separately, Kinder Morgan Inc’s Elba Island LNG export plant in Georgia sent out its first cargo over the weekend. Pipeline flows to Mexico, meanwhile, eased to 5.0 bcfd on Sunday from 5.1 bcfd on Saturday, according to Refinitiv data. That compares with an average of 5.4 bcfd last week and an all-time daily high of 6.2 bcfd on Sept. 18.

Warmer Weather Hits Natural Gas Prices Again –The natural gas market did well in shrugging off warmer changes in the weather forecast since last week, but yet another day with a lowering of projected weather demand finally sent prompt month prices back under the 2.30 level, at least as of this writing. Daily warmer forecast adjustments have been a common theme recently, with last night’s weather models making no exception to this “rule”. Last night’s forecast demand profile from the GEFS and ECMWF EPS, compared to 24 hours prior: All of the warmer changes now have us projecting this December’s total demand (GWDD count) to be very close to the warm December one year ago. This has been quite the change from the anomalous cold seen back in November, but the warming was something we had alerted clients to even back in early November, as the cold pattern was in full stride. With less than two weeks left in December, and the holidays looming, attention is now on January, and whether cold makes a triumphant return to give a boost to natural gas prices, or if warm continues to win out.

US natgas production projected to slow considerably – The just-released EIA December Drilling Productivity Report (DPR) forecasts natural gas production from the U.S.’s seven most productive basins/plays will rise just 77 million cubic feet per day from December to January – a month-to-month increase that in previous reports neared 1 billion cubic feet per day. Total gas production from the seven basins/plays in January will creep up to 85.60 billion cubic feet per day (Bcf/d), from 85.52 Bcf/d in December, the Energy Information Administration’s monthly projection shows. (All numbers are rounded.) The oil and gas industry slowdown manifests itself in another jaw-dropping way within the new DPR, Kallanish Energy reports. Gas production in Appalachia (the Marcellus and Utica Shale plays combined) is expected to actually drop 74 Mmcf/d from December to January. Total production will slide to 33.43 Bcf/d, from 33.51 Bcf/d. Other basins/plays seeing production dialed back from December to January include the Anadarko, down 132 Mmcf/d, to 7.52 Bcf/d, and the Eagle Ford Shale play, down 69 Mmcf/d, to 6.78 Bcf/d in January. The Permian Basin’s natural gas production during the December-to-January timeframe is projected to increase by 213 Mmcf/d, to 17.08 Bcf/d, from 16.86 Bcf/d in December. The Haynesville Shale is expected to rise 123 Mmcf/d from December to January, to 12.09 Bcf/d, from 11.96 Bcf/d. The Niobrara gas production is projected to increase 13 Mmcf/d, to 5.59 Bcf/d, from 5.58 Bcf/d. Bakken natural gas production should barely move, according to the new DPR, increasing just 3 Mmcf/d, to 3.12 Bcf/d in January from 3.12 Bcf/d in December.

US working natural gas in underground storage decreases by 107 Bcf: EIA – US working natural gas volumes in underground storage dropped by 107 Bcf last week, which was more than market expectations, as NYMEX Henry Hub futures made only modest gains following the announcement. Storage inventories fell to 3.411 Tcf for the week ended December 13, the US Energy Information Administration reported Thursday morning. The pull was more than an S&P Global Platts’ survey of analysts calling for a 93 Bcf draw. Responses ranged for a draw of 80 Bcf to 102 Bcf. The withdrawal was below the 132 Bcf pull reported during the corresponding week in 2018, as well as the five-year average draw of 112 Bcf, according to EIA data. As a result, stocks were 619 Bcf, or 22.1%, above the year-ago level of 2.793 Tcf and 9 Bcf, or 0.3%, below the five-year average of 3.420 Tcf. The balance-of-winter NYMEX Henry Hub strip continues to reflect an oversupplied market, although historically the market has been quick to rebalance when prices move too much in either direction. Between last week and this week, prices got as high as $2.31/MMBtu Monday, but quickly retreated on mild weather forecast updates. The draw was more than the 73 Bcf pulled from working gas in storage reported for the week ended December 6. US supply-demand fundamentals for the week ended December 13 were roughly 3.4 Bcf/d tighter than the week before as colder weather boosted demand from the residential and commercial and power sectors while LNG feedgas demand continued higher, according to S&P Global Platts Analytics. Balances moved much tighter on a rise in weather-driven heating demand. Total supplies are up 0.7 Bcf/d on the week to an average 96.6 Bcf/d, with much of the increase driven by a rise in net Canadian imports to meet higher demand. Downstream, total demand is up 7.4 Bcf/d on the week at an average 116.8 Bcf/d, with gains driven primarily by higher home heating demand and a roughly 1.6 Bcf/d increase in power plant deliveries, according to Platts Analytics. LNG feedgas demand hit new highs in recent weeks on increased deliveries in the Gulf Coast region, setting a record of 8.5 Bcf/d Wednesday. LNG feedgas demand is up 0.1 Bcf/d for the week ending December 20 compared with the week prior. A Platts Analytics forecast calls for a massive draw of 143 Bcf for the week ending December 20, which would be more than 40 Bcf stronger than the five-year average.

EIA’s 107 Bcf Storage Draw Trims Losses for Natural Gas Futures – The U.S. Energy Information Administration (EIA) on Thursday morning reported a massive 107 Bcf withdrawal from natural gas storage for the week ending Dec. 13.The reported draw was far above consensus estimates of a pull in the low 90s Bcf and was even several Bcf above the highest projection in market surveys. However, the 107 Bcf withdrawal was still far below the 132 Bcf withdrawal EIA recorded in the year-ago period and several Bcf below the 112 Bcf five-year average draw.Nevertheless, the triple-digit pull took the natural gas market by surprise, with prices responding immediately to the latest EIA data. About five minutes before the 10:30 a.m. ET report, the January Nymex gas futures contract was trading at $2.257, down 2.9 cents from Wednesday’s settle, as weather models extended the coming span of mild temperatures further into January. As the EIA print crossed trading desks, however, the prompt month strengthened to trade less than penny lower at $2.278. February was also nearly flat at $2.261. By 11 a.m., the January contract was just two-tenths of a cent lower at $2.284. February was up fractionally to $2.266. “A massive draw. Way beyond expectations,” Ahead of the report, a Reuters poll of 16 analysts estimated withdrawals ranging from 68 Bcf to 102 Bcf, with a median draw of 92 Bcf. NGI expected to see a draw of 86 Bcf.Broken down by region, the Midwest reported the largest withdrawal of 40 Bcf, and the East came in second with a 29 Bcf pull, according to EIA. The South Central withdrew 26 Bcf out of storage, including a stout 24 Bcf pull from nonsalt facilities and a 2 Bcf pull from salts.“The South Central is the biggest miss here,” said independent weather forecaster Corey Lefkov. “Don’t mess with Texas.”Total working gas in storage as of Dec. 13 stood at 3,411 Bcf, 618 Bcf higher than the year-ago period and 9 Bcf below the five-year average, according to EIA.Looking ahead, the combination of low cash prices, max power burns and record liquefied natural gas demand could make for some volatile days ahead. However, “if we torch up the first two weeks of January, my view is that weather always wins in wintertime,” Paltrinieri said.NatGasWeather meteorologist Rhett Milne agreed and said although weather models are starting to tease at colder air arriving in early January, it’s “going to be a painful stretch of weather to get through during the next 10-12 days.”

Elizabeth Warren’s Massachusetts Loves Natural Gas – Forbes – Elizabeth Warren has pledged to ban fracking when she becomes president of the United States. This would cause real problems for her home state. The Massachusetts economy depends on imported natural gas. In a single year, methane supplies around 465 trillion Btu of energy, or some 50% more than second place gasoline. Massachusetts, however, produces no natural gas itself, making energy imports as integral to the state’s functioning as anywhere. Since the 1970s, Massachusetts has seen a steady shift to heating with natural gas in households, from a greater reliance on heating oil. Especially in the shale revolution era since 2008, natural gas is cheaper, less volatile, and has lower greenhouse gas emissions. Over 1.5 million homes in Massachusetts use gas as the primary source of heating.Mass.gov reports that over 50% of Massachusetts households use gas for heating, with 15% using electricity, which is becoming more gas-based as well. Oil though still supplies 27% of heating, meaning that there is room for more gas when it is cold outside, via both gas heating and electricity heating. Natural gas is surely a beloved product in The Bay State: on average per capita, Massachusettsans use 64,000 cubic feet of gas each year. Up from 50% a decade ago, natural gas supplies almost 70% of Massachusetts’ electricity, one of the highest gas reliances in the country and nearly double the national average of 38% (heck, gas producing juggernaut Texas is only at 50%!). This extension of gas power’s share in Massachusetts, however, has nicely helped reduce the state’s power sector CO2 emissions by 45% since 2010. Eight of the top 10 generation plants in Massachusetts are gas-based. In contrast, wind supplies less than 1%, with solar at 15%. And officials in Massachusetts have outlined a goal to end the sale of gasoline vehicles in the state by 2040. The goal for more electric cars, for instance, could surge the state’s gas power demand by 40-50%.

Natural Gas And Oil Industry Stalwarts Fueling Biden Campaign – Former Vice President Joe Biden, 77, has a multitude of people tied to the oil and gas industry on his campaign staff, according to a new report by Real Sludge. Heather Zichal, the climate advisor for the Biden campaign, used to be a board member at Cheniere Energy, a natural gas company. Andrew Goldman, a former adviser to Biden and a current fundraiser, is the co-founder of natural gas company Western LNG. And Unite the County, the SuperPac that is supporting him, has a former gas lobbyist on its board, Sludge said. But the most dangerous connection to the gas and oil industry is Biden’s campaign co-chairman Louisiana Democratic Rep. Cedric Richmond. Richmond has been a steady vote in favor of the expansion of the production and exporting of natural gas and oil. He voted in favor of the Keystone XL pipeline and “voted in favor of a bill from Rep. Bill Johnson (R-Ohio) that would undermine the environmental review process for natural gas pipelines by stating that all pipelines that transport 0.14 billion cubic feet per day or less should be immediately approved,” Sludge reported. Richmond also voted for bills to exempt cross-border pipelines from environmental review, reverse the crude oil export ban, expand offshore drilling and block the EPA from regulating the disposal of toxic coal ash. “This is all deeply concerning,” Stephen O’Hanlon, the communications director of Sunrise Movement told Sludge. “No presidential candidate is going to get taken seriously on climate change if they’re funded by and taking advice from current and former fossil fuel executives, and choosing to take cues from members of Congress who’ve put the interests of oil and gas donors above the health and well-being of their constituents.”

Joe Biden’s Campaign Co-Chair is a Big Oil and Gas Booster – Former Vice President Joe Biden has surrounded himself with people tied to the natural gas industry for his 2020 presidential campaign. His climate adviser, Heather Zichal, is a former board member of natural gas company Cheniere Energy, while one of his fundraisers is a cofounder of natural gas company Western LNG. In addition, the super PAC supporting his candidacy has a former gas lobbyist on its board. But there is another Biden campaign figure whose oil and gas industry connections have not been examined: Louisiana Democratic Rep. Cedric Richmond, whom Biden selected in May to serve as his campaign co-chairman. Despite representing a low-lying Louisiana district that could be one of the areas in the U.S. most immediately impacted by climate change, Richmond has voted reliably in favor of expanding production and exports of natural gas and oil. His voting record is one of the most fossil fuel industry-friendly of all Democrats in Congress. In 2015, Richmond was one of 28 House Democrats to vote in favor of approving construction of the Keystone XL pipeline, which will transport crude oil from Alberta, Canada to the Gulf Coast. Last year, he voted in favor of a bill from Rep. Bill Johnson (R-Ohio) that would undermine the environmental review process for natural gas pipelines by stating that all pipelines that transport 0.14 billion cubic feet per day or less should be immediately approved. Richmond, a member of the moderate New Democrat Coalition, has voted in favor of many Republican bills opposed by environmentalists over the years, including Rep. Markwayne Mullin’s (R-Okla.) bill to exempt cross-border pipelines from environmental review, Rep. Joe Barton’s (R-Texas) billto reverse the crude oil export ban, Rep. Doc Hastings’ (R-Wash.) bill to expand offshore drilling, and Rep. David McKinley’s (R-W.V.) bill to block the Environment Protection Agency from regulating the disposal of toxic coal ash.

EQT Head Tells W.Va. Lawmakers Natural Gas Drillers May Need Some ‘Help’ – The head of natural gas driller EQT Corporation told members of the West Virginia Legislature the company intends to ramp up the size of drilling projects to hedge against projected low natural gas prices. To accomplish that, the company may need help from lawmakers when it comes to “fractured mineral interests.” Toby Rice, EQT’s new president and CEO, testified Monday to the Joint Committee on Natural Gas Development and Joint Standing Committee on Energy. “Gas prices are down. It has a big impact, the difference between $2.75 gas and $2.50 gas,” he said. “A lot of this development doesn’t work as well at $2.50 gas.” EQT is one of the largest natural gas producers in the country, with a focus in Pennsylvania, Ohio and West Virginia. Rice told lawmakers the company is moving toward “combo development,” or the practice of drilling multiple wells on multiple well pads adjacent to one another. “This allows us to do economies of scale in terms of low gas prices,” he said. Rice argued larger natural gas developments will ultimately be less disruptive to local communities because multiple wells will be drilled simultaneously. He said EQT sees “room for a lot more development in West Virginia.” But to accomplish that, Rice told the Legislature that EQT and other natural gas drillers may need “help at some point.” Large-scale development may require the company to sign deals with up to 1,000 landowners, instead of a few hundred. In West Virginia, often rights to the surface of a property and minerals below it have been severed and do not belong to the same person. Mineral rights are sometimes owned by multiple people. In 2018, the Legislature passed a co-tenancy bill that lessened the burdens on drillers by allowing companies the ability to enter into leases with co-tenants owning 75 percent of the interest in the minerals. Rice said he expects fractured ownership could be an issue to the company’s larger development strategy in some cases, “and maybe co-tenancy doesn’t get us there.”

Lack of Safety System Led to Fatal West Virginia Blasts, CSB Says

• Safety board’s report points to reactive chemical hazards
• Federal rules don’t require comprehensive safety management system

The U.S. Chemical Safety and Hazard Investigation Board blames the lack of an effective safety management system for a pair of explosions that killed three workers at a Midland Resource Recovery facility in Philippi, W.Va., in 2017. The CSB released its final investigation report Dec. 17 on the two pressure vessel explosions that occurred at the natural gas odorization contractor. Midland’s founder and president was one of the workers killed in the explosions, which also injured a worker employed by another contractor. Midland performs odorant work on client sites, transports odorant and odorant equipment, and decommissions and removes obsolete odorization equipment from client sites.

Dominion still sees U.S. Atlantic Coast natgas pipe online in 2022 despite Morgan Stanley’s doubts – (Reuters) – Dominion Energy Inc said on Monday it was confident it will complete the proposed $7.3-$7.8 billion Atlantic Coast natural gas pipeline from West Virginia to North Carolina by early 2022, in response to a prediction by investment bank Morgan Stanley that a court decision would likely scuttle the project. “We remain committed to completing the project for the good of our economy and the environment,” Dominion spokesman Aaron Ruby said, noting the company expected to complete construction in late 2021 with final in-service in early 2022. Dominion made its comments after Morgan Stanley said in a report that “Atlantic Coast will likely not be completed given the Fourth Circuit’s likely (in the bank’s view) rejection, for the third time, of a newly issued Biological Opinion and Incidental Take Statement that we expect to come by the first quarter of 2020.” In July, the U.S. Fourth Circuit Court of Appeals vacated the Fish and Wildlife Service’s (FWS) second Biological Opinion because the court found the agency’s decisions were arbitrary and would jeopardize the Rusty Patched Bumble Bee and other endangered species. Federal agencies use Biological Opinions when authorizing projects that could adversely affect threatened or endangered species or critical habitats, and issue take statements to limit the number of those species that could be harmed. Ruby said Dominion expects the FWS will issue a new Biological Opinion in the first half of 2020. Dominion suspended construction of the 600-mile (966-kilometer) project in December 2018 after the Fourth Circuit stayed the FWS’ second Biological Opinion. Dominion and its partners, Duke Energy Corp and Southern Co, are also working through a dispute over where the pipeline can cross the Appalachian Trail. The U.S. Supreme Court has agreed to take up the Appalachian Trail case, which is also important for the construction of EQM Midstream Partners LP’s Mountain Valley gas pipe from West Virginia to Virginia. Analysts at Height Capital Markets said they expect the Supreme Court will issue a ruling in May or June 2020. Analysts at Morningstar said they expect the Appalachian Trail dispute will be resolved by a favorable Supreme Court decision or an administrative or legislative solution.

Dominion seeks permits to build new power plant in Chesterfield – Dominion Energy has filed an air permit application with the Virginia Department of Environmental Quality to build a $600 million combustion turbine peaking power plant in Chesterfield County near Dutch Gap. The four proposed natural gas peaking units – also known as peakers – would only produce electricity during periods of high demand. The plant would generate nearly 1,000 megawatts, enough to power 250,000 homes, and would be built in two phases. The first phase would be operational by spring 2023 and the second phase would be operational by spring 2024. According to Dominion officials, the new plant is necessary to supplement energy produced by renewable resources during periods when energy usage is highest, such as the early morning and early evening hours. For example, solar photovoltaic energy is generated while the sun is shining, but drops off as electricity demand peaks in the evenings when people return home from work and use electric appliances. As the utility company moves toward renewable energy and shutters coal-fired units, officials say peaking units are needed to augment the power generated by renewable resources – those that essentially have an endless supply, such as wind, solar and geothermal – when there’s a lack of sunlight or low wind speed. .

Kalamazoo County parks ban oil, mineral and other natural resource extraction – — After Kalamazoo County Park Commission was approached by an oil company with an interest in geotechnical exploration at Scotts Mill County Park last year, the county took a look at what preservation policies were needed to protect the future of the parks. On Tuesday, Dec. 17, the county commissioners unanimously approved an 11-point list of preservation efforts outlined by an oil and gas subcommittee and Parks Director David Rachowicz. “For them [the board] to give us clear direction and then empower us to go out and do it and support us along the way, I think we’re going to end up with something that is really a great thing for Kalamazoo County,” Rachowicz said. The county has never allowed exploration, production, or extraction of natural resources in parks, Rachowicz said. However, being approached by the oil company brought attention to potential future threats to preserving that county land, and prompted action from commissioners like Vice Chairperson Tracy Hall. “Our parks are our crown jewels and we need to protect them as best we can,” Hall said. The county commissioner said she was surprised with how forward-thinking the policy could be, rather than functioning solely as an immediate solution to oil proposals. Hall and Rachowicz agreed that the policy was designed to make sure there were no unintended consequences in the future that would compromise the park system.

What a Line 5 shutdown could mean for Michigan energy – If a state lawsuit succeeds in shutting down Enbridge Energy Co.’s controversial Line 5 oil pipeline, Michigan consumers could experience price hikes for fuel, natural gas and propane while increasing the risk of a spill on land, industry experts said. Fuel industry officials and independent experts estimate closing the dual pipelines beneath the Straits of Mackinac would cut off not only thousands of gallons of propane a day in the Upper Peninsula but also light crude shipments to Detroit, Toledo and Sarnia, Ontario, refineries that convert the oil into gas, diesel and jet fuel. The 66-year-old pipeline has been targeted for shutdown by environmentalists who fear the implications of a spill in the Straits of Mackinac could be similar to the 2010 oil spill near the Kalamazoo River in Marshall. Enbridge ended up paying $1.2 billion for the cleanup and restoration of the southern Michigan area that experienced the largest inland oil spill in U.S. history. Michigan Attorney General Dana Nessel’s lawsuit seeking the shutdown of Line 5 is pending before an Ingham County circuit judge. In the meantime, Enbridge continues pre-engineering work on a planned $500 million tunnel to house the controversial pipeline, saying it would take four years to build and nearly eliminate any environmental impact of a potential rupture. A cutoff of the Straits segment would likely have an unknown impact on regular unleaded gas prices in Michigan depending on market conditions, according to industry experts. But it would be more likely to spike the price of propane, which many residents in the Upper Peninsula and northern Michigan rely on for heat during the six-month-long cold season. Such a shortage would require a flotilla of trucks to replace the 540,000 barrels-a-day capacity of Line 5, a logistical nightmare that would drive up costs and increase the likelihood of an oil spill on Michigan roads, Enbridge and independent energy analysts said. The price increase for Michigan consumers likely would depend on other circumstances in the industry and the timing of a potential shutdown, said Tom Kloza, global head of energy analysis for the Oil Price Information Service, an energy consulting firm based in Rockville, Maryland. Environmental groups have questioned the dire industry predictions, arguing that Line 5 is not critical energy infrastructure and could be replaced easily by a handful of extra trucks or rail cars. The shutdown would have a minimal effect on cost, they contend. “While you don’t want to see any oil and gas spill, if a truckload spills, it’s limited to one truckload,” said Sean McBrearty, state legislative and political director for Clean Water Action. Relative to a pipeline spill in the Straits, he said, “one truck spill is orders of magnitude smaller.”

‘We could get by’ – U.P. considers alternatives to Line 5 propane – Tribal nations, Michigan’s governor and environmental groups are all calling for a shutdown of Line 5: the pipeline that carries oil underneath the Straits of Mackinac. They say the pipeline, which is 60-plus years old, poses too great a risk of rupturing. The pipeline doesn’t just carry oil – its liquid mix includes propane that is delivered to Michigan’s Upper Peninsula. So, what would happen to U.P. households using propane if Line 5 shut down? The majority of households in the Upper Peninsula heat their homes with natural gas, but it’s often not available in rural areas, like where James Ball lives. About 18 percent of U.P. households heat primarily with propane. Some of those are summer cottages or hunting camps, but many are not. It isn’t unheard of for a family to spend $2,000 filling their propane tanks over a winter. Ball says one winter a few years ago, there was a propane shortage in the U.P. Many states in the Midwest declared propane emergencies in the winter of 2013-14. Farmers needed a lot of propane for crop drying during the harvest season of 2013. There were also infrastructure issues, and it was just a really cold winter. “When I called to order propane, they said that there was a possibility that it would not be available by the time that my tank ran out,” says Ball. It concerned him so much that now, he only uses propane as a last resort. He put a wood pellet stove in his basement, and he also has a standard wood stove in his living room. The bags of pellets weigh 40 pounds each, and he has to haul them to the basement. Ball is worried about how that will work for him as he gets older. “There’ll come a time when I’ll no longer be able to cut wood,” he says. “There’s costs. Pellets are fairly expensive. You have to transport those and haul them in.” He might have to rely on propane again, and he’s concerned about anything that might change its price. That includes a possible shutdown of Enbridge’s Line 5, which delivers propane to a facility just a few miles from his house.

Public forum in Duluth on Enbridge Line 3 – Minnesota regulators will hold a forum in Duluth on Thursday for members of the public to comment on additions to the state’s environmental review for Enbridge Energy’s plan to replace its Line 3 crude oil pipeline across northern Minnesota. The update became necessary after the Minnesota Court of Appeals declared in June that the previous version was inadequate because it failed to specifically address the potential impacts of a spill into the Lake Superior watershed. The state Commerce Department then conducted additional modeling, and concluded that there’s no serious threat to Lake Superior if crude oil ever leaks from the pipeline. Line 3 carries Canadian crude from Alberta to Enbridge’s terminal in Superior, Wisconsin. The replacement would double the capacity of the existing line, which was built in the 1960s and is increasingly subject to cracking and corrosion. Environmental and tribal groups that have been fighting the project plan to make their opposition heard at the meeting, The Public Utilities Commission has imposed strict security protocols to try to prevent disruptions.

Pre-filed bill aims to ban offshore drilling for good from S.C. coast – Offshore drilling has become a big topic on the state, local and national levels, and one South Carolina state senator has taken a step to keep offshore drilling far away from our coastline. South Carolina state Sen. Chip Campsen (R) said after working in the Gulf of Mexico for many years, he believes people don’t understand the reality of having offshore drilling along our coast and what this could do to the communities near the beach. “That if you’re going to have offshore drilling, your coast is going to be industrialized. There is a massive amount of onshore infrastructure that is needed to support offshore drilling,” Campsen said. Campsen believes this type of growth would harm the $17 million tourism industry, which is the main source of revenue for the coastal areas of the state. “Refineries and tank farms and oil spills don’t go well with the vacationers on the Grand Strand beaches. Louisiana, Texas, and parts of Alabama decided we’re going to dig for oil. They don’t have the tourism, the coastal tourism, we have, they don’t have the coastal real estate values we have because that oil industry affects all of that,” Campsen said. Earlier this year, a provision was passed by the state Senate, preventing the Department of Health and Environmental Control or local government entities to use funds to approve licenses or permits associated with offshore drilling or for seismic testing. This bill was passed on a year-to-year basis.

Deepwater Gulf enters next phase of growth – For the first time since the Deepwater Horizon tragedy of a decade ago, the British oil major BP will ship a major oil platform to the Gulf of Mexico, where it will operate in some 4,500 feet of water nearly 200 miles south of New Orleans.The Argos platform, which will reach its destination in the fall of 2020, is part of the next wave of oil production in the Gulf of Mexico as companies learn to reduce costs while operating with new technologies in more complex, deeper waters. Even as the onshore shale boom starts to slow and companies cut back onshore, global deepwater spending is back on the rise for oil and gas producers.That has driven a mini-resurgence in the Gulf, where mix of legacy production and the development of new mega projects has offshore platforms pumping out record volumes of oil to the tune of about 2 million barrels a day.“There’s quite a bit of potential in the ultra-deepwater,” said George Laguros, a senior analyst the global research and consulting firm IHS Markit.On HoustonChronicle.com: As energy world focuses on Permian, Gulf makes its own comebackJust this month, Chevron authorized the $5.7 billion first phase of the Anchor project, which is considered the first ultra-high-pressure development in the Gulf. Anchor, located in the ultra-deepwater Lower Tertiary region about 140 miles off the coast of Louisiana, would be the first project to use subsea equipment and technology capable of withstanding pressures of 20,000 pounds per square inch – enough to crush concrete – compared to the previous highs of roughly 15,000 pounds per square inch.Other companies plan to follow with their own projects at similar pressures in the Lower Tertiary area, including the French energy major Total, which is doing engineering work for the North Platte field, and the Louisiana company LLOG Exploration, which is buying equipment for its Shenandoah project – both about 200 miles southwest of New Orleans.

Coast Guard responding to crude oil discharge near New Orleans – The Coast Guard is responding to a crude oil discharge near New Orleans today. Authorities received a report shortly before 7:30 a.m. on Saturday that approximately 1,050 gallons of crude oil discharged into Garden Island Bay from the Whitney Oil and Gas Garden Island Bay Tank Battery 49 facility due to mechanical issues. The source of the spill has been secured after personnel at the facility shut down the pump and isolated the line, according to the Coast Guard. The discharge is all within previously placed containment boom, and caused a 180-foot by 60-foot dark black sheen on the water’s surface in Garden Island Bay. Whitney Oil and Gas hired OMI Environmental Solutions as the oil spill response organization. OMI has two skimmers, two boats, and personnel currently working on active recovery of the product, with 420 gallons of oily water mixture recovered. Sector New Orleans deployed two incident management division personnel to the site with personnel from Whitney Oil and Gas and Louisiana Oil Spill Coordinators Office. The cause of the discharge is under investigation.

Freeport LNG Train 2 ships first commissioning cargo – Freeport LNG has shipped the first commissioning cargo on Train 2 of its liquefaction plant on Quintana Island, Freeport, Tex. McDermott International Inc., along with partners Chiyoda International Corp. and Zachry Group, reported production of LNG from Train 2 on Dec. 6 (OGJ Online, Dec. 6, 2019). First cargo is a precursor to substantial completion of Train 2. The project includes three pretreatment trains, a liquefaction plant with three trains, a second loading berth, and a 165,000-cu m full-containment LNG storage tank. Zachry Group, as the joint-venture lead, engaged McDermott for the pre-front-end engineering and design in 2011, followed by FEED. Chiyoda joined the partnership later and the joint team provided engineering, procurement, and construction, as well as commissioning and initial operations for the project. Freeport LNG anticipates adding a fourth train by 2021, bringing total plant capacity to more than 20 million tpy. Freeport LNG Trains 2 and 3 remain on schedule with Train 3 initial production of LNG scheduled for first-quarter 2020.

US was net energy exporter in November, new API statistics say – The US became a net energy exporter for the first time in 60 years during November and produced a record 12.9 million b/d of crude oil, the American Petroleum Institute said Dec. 19 as it released its 2019 fourth quarter industry outlook and latest monthly statistical report. “Never before has a major energy-consuming nation also become a top global exporter of total energy – usually it’s the other way around,” API Chief Economist Dean Foreman said. “The fact that US production has been able to simultaneously satisfy strong domestic demand and supply continued international demand for US exports while maintaining relatively low and stable prices is remarkable and historic in magnitude.” With solid productivity and expanded pipeline infrastructure, the nation is in a position to continue its oil and gas production growth in 2020 as predicted by the US Energy Information Administration, the quarterly industry outlook said. It found that US energy exports have continued to grow despite trade frictions. “Nationwide, natural gas demand for electricity generation increased 5.65 year-to-year so far in 2019, reflecting its cost competitiveness,” the outlook indicated. Domestic petroleum demand remained near record peaks throughout 2019, it said. The US refining system is well-positioned to meet 2020 International Maritime Organization (IMO) sulfur reduction requirements due to its relatively complex plant, access to attractive crude feedstocks, abundant and inexpensive natural gas, and the best refining workers globally, API’s latest quarterly industry outlook said. “Motor gasoline and diesel fuel prices have generally moved with crude oil, and EIA expects limited impact from IMO 2020,” API’s latest quarterly industry outlook said. “Since 2000, US distillate stocks have remained above 100 million bbl with an increasingly interconnected supply chain and pipeline network.”

Whistler Pipeline moves forward with three public meetings – A pipeline project to move natural gas from the Permian Basin of West Texas to Corpus Christi is moving forward with three public meetings in Odessa, Uvalde and Alice.Developers of the Whistler Pipeline held a public meeting for the project on Tuesday evening at the Odessa Marriott in Odessa. A second public meeting is planned for 5 p.m. Wednesday at the Herby Ham Activity Center in the Hill Country town of Uvalde. The third meeting is planned for Thursday at the Alice Country Club in the South Texas town of Alice, the Texas Condemnation Rights website reported. Spanning some 475 miles, the proposed 42-inch pipeline will move 2 billion cubic feet of natural gas per day from the Waha Hub in the Permian Basin to the Agua Dulce Hub of South Texas. The Whistler Pipeline is being developed as a joint venture between Ohio-based MPLX LP, Austin pipeline operator WhiteWater Midstream, New York private equity firm Stonepeak Infrastructure Partners and Midland pipeline operator West Texas Gas.Developers announced that they had made a final investment decision on the project in June. An open season for booking capacity on the pipeline ended on Monday. If approved by regulators and supported by the market, the pipeline is expected to be in service by the third quarter of 2021.

Hazardous Liquids Training for First Responders Available in Texas — ExxonMobil is teaming up with the Texas A&M Engineering Extension Service (TEEX) to provide a hazardous liquids emergency response training course for firefighters. A $200,000 grant from the oil giant funded development of the course and participation of 150 firefighters at sessions in August and October. A third session is set for January 11-12, and 50 firefighters have already signed up to participate. Nicolas Medina, public and government affairs manager for ExxonMobil Pipeline, is hoping to see firefighters from West Texas participate in the January session or additional sessions in 2020. The company’s support of the course is part of its commitment to the communities where it operates, he said. In addition to the $200,000 grant that funded the development of the program, ExxonMobil will make another $200,000 grant for the program next year. Municipal and volunteer firefighters “do an awesome job at what they do, they are well-trained for what they do, which is primarily house fires, car fires, rescues like that,” said John Burge, director of the industrial firefighting program at TEEX. But training for large plant fires such as at Port Neches recently, or tank battery fires or pipeline fires costs more than their budgets allow he said. The funding from ExxonMobil will allow municipal and volunteer firefighters to receive that training, he said. “They pay for everything – hotel rooms, meals, the training, the fuel used in the training, that’s very expensive, the foam used in the training, that’s very expensive,” Burge said in a phone interview.

Emissions Soar As Permian Flaring Frenzy Breaks New Records – The flaring and venting of natural gas in the U.S. continues to soar, reaching new record highs in recent months. The volume of gas that was burned or simply released into the atmosphere by oil and gas drillers reached 1.28 billion cubic feet per day (Bcf/d) in 2018, according to the EIA, up from 0.772 Bcf/d in 2017. The practice is a disaster on many levels. It is wasteful, it worsens air quality and it exacerbates climate change. Venting gas is much worse than burning it since it releases methane into the atmosphere, a potent greenhouse gas.The New York Times documented several “super emitters” in the Permian, using infrared cameras to visually capture the epidemic. The NYT even recorded an oil worker walking into an invisible plume of leaking methane. But shale drillers continue the practice and regulators have shown little interest in regulating them. Even though venting is off limits in North Dakota and restricted in Texas, flaring has largely gone unchecked while methane leaks at virtually every stage of the extraction process. In the third quarter of 2019, the Permian basin alone vented and flared 752 million cubic feet of natural gas per day, up sharply from 661 mcf/d in the first quarter, according to Rystad Energy. “This represents a new all-time high. Oil production in the Permian Basin is growing at an accelerated pace again, and we observe high, sustained levels of flaring and venting of associated gas in the basin,” Artem Abramov, head of shale research at Rystad, said in November. “It’s a black eye for the Permian basin,” Pioneer Natural Resources Chief Executive Officer Scott Sheffield said earlier this year. “The state, the pipeline companies and the producers — we all need to come together to figure out a way to stop the flaring.” One thing that could be done would be for the Texas Railroad Commission, which regulates the industry in the state, to deny permits to companies that allow them to flare. But the Railroad Commission has not denied a single request from an oil producer for a flaring permit in years, despite the spike in flaring. The number of permits granted has shot up from around 500 in 2010 to 5,500 in 2018, according to the EIA. There is essentially no cop on the beat. The situation reached absurd levels a few months ago when the Texas Railroad Commission approved a company’s request to flare even though the company had pipeline access readily available. One of the main reasons that flaring has reached astronomical levels is because pipeline capacity has not kept up with the surge in gas production. Because the industry is really chasing oil, all of the gas is surplus. And because there is nowhere to put it, they flare it..

Report: As TCEQ Sits Idle, Polluters Double Illegal Air Pollution in 2018 – The oil and gas industry in Texas is largely responsible for doubling the amount of illegal air pollution in the state last year, according to a reportreleased Wednesday. The Texas Petroleum Chemicals (TPC) plant in Port Neches – the same facility that caught fire last month, injuring three and prompting multi-day evacuations – was listed as a major emitter of butadiene, a known human carcinogen. That and other emissions, innocuously referred to as “upset events,” lead to the premature deaths of 42 Texans and $241 million in health care costs each year.Last year, approximately 270 companies, including Chevron, Dow Chemical, and ExxonMobil, reported 4,590 unauthorized emissions incidents in the state, according to the report from advocacy group Environment Texas. Those resulted in 135 million pounds of illegal air pollution, double the amount emitted in 2017. Contaminants spewed into the sky include human carcinogens butadiene and benzene; smog-forming nitrogen oxides; and particulate matter, which can cause heart attacks, strokes, and congestive heart failure.The biggest release occurred on August 29, 2018, when the Beaumont Gas to Gasoline Plant belched 53 million pounds of carbon dioxide over five days. The event made up the lion’s share of the 63.9 million pounds of air pollution in the Beaumont region, the most polluted area in Texas that year. TheMidland region, which is the locus of the state’s fracking boom, saw 39.5 million pounds of air pollution, the second most in the state. “Texans are sick and tired of oil refineries and petrochemical plants catching fire, exploding, and pumping out harmful pollution,” said Catherine Fraser, an air pollution fellow at Environment Texas. “The data show the problem is getting worse, not better. We need our state leaders to crack down on illegal pollution, and stop putting the interests of polluters over the rest of us.” The Texas Commission on Environmental Quality (TCEQ) has a laissez-faire approach to enforcing federal air pollution laws, especially when dealing withmonied rulebreakers. According to the report, the agency fined companies in only 1.2 percent of illegal emission events, a rate Fraser called “shockingly low.” On Wednesday, she and other environmental activists and Beaumont-area residents gathered in front of TCEQ’s offices in North Austin to demand stricter enforcement. They took particular issue with TPC’s massive butadiene release in 2018, for which TCEQ proposed fining the company a paltry $22,000.

Industry, enviros contrasting accounts over flaring – Environmentalists and the natural gas industry have issued contrasting accounts about flaring, the practice of burning off excess natural gas in the Permian Basin and other shale plays across the United States. Over the past week, the Washington, D.C.-based environmental group Earthworks and the industry-funded group Texans For Natural Gas released online statements that offer contrasting viewpoints of the issue. In a public letter, Earthworks criticized the Texas Commission on Environmental Quality, the state’s top environmental agency, as being lax on enforcement and “uncooperative” in response to citizen complaints about the issue. Texans For Natural Gas posted a Tuesday morning report stating that methane emissions intensity, the amount of methane vented or flared for each barrel of oil equivalent produced, has fallen in the United States over the past seven years and remains at rates far below other nations such as Russia.With natural gas viewed as a byproduct of drilling for much more valuable oil, companies that don’t have their wells connected to natural gas pipelines can receive permits to either release it into the atmosphere in practice known as venting or burn it off on site in another practice known as flaring.Oil companies vented or flared a record 1.28 billion cubic of natural gas per day during 2018, a recent report from the Energy Information Administration shows. At the current market prices, that’s roughly $1 billion worth of natural gas burned off or wasted per year.Texas oil wells accounted for 51 percent of the flaring and venting activity while oil wells in North Dakota accounted to 31 percent. Vented and flared natural gas increased to 1.25 percent of overall U.S. production from 0.84 percent reported in 2017. In its public letter, Earthworks criticized TCEQ for failing to follow up on citizen complaints regarding flaring and venting in the Permian Basin and elsewhere across the state. The environmental group vowed to step up its pressure on the agency and that it would be attaching more videos and scientific information with future complaints. Working with two partner organizations, the report released by Texans For Natural Gas went nation by nation comparing the amounts of natural gas vented or flared compared to crude oil production. Smaller nations with considerably smaller crude oil production such as Syria, Yemen and Mozambique had the worst rates.

US oil, gas rig count rises for second straight week: Enverus – The US oil and gas rig count rose for the second straight week, according to energy researchers Enverus’ drilling statistics released Thursday, on what analysts say may be a final push to spend the last bit of 2019 drilling budgets at WTI prices that have cracked the $60/b mark. The domestic rig count totaled 860, up five for the week ended December 18 following an unusually large 15-rig jump the previous week, Enverus said. As a result, the US gained 20 rigs in the past two weeks, a reversal of the past year’s general southward direction. Since mid-November 2018, when the recent US rig count peak totaled 1,237, industry has lost 30% or nearly 400 rigs. This week’s land rig count totaled 831, up by four but down from 1,144 this same week in 2018, Enverus’ data show. Evercore is forecasting the US land rig count to fall 10% in 2020 year on year, which is greater than its US capex spending forecast decline of 7% for next year. The rig count gains are likely traceable to year-end drilling here and there as needed, possibly fueled by higher oil prices that finally mounted the $60/b milestone not seen in months, observers said. This week’s total rig count gains came from oil-directed rigs, which moved up 10 to 695. Conversely, natural gas-oriented rigs moved down six to 160. In addition, a one rig rise came from basins classified as neither oil nor gas. As a result, drilling ticked up in two of the largest domestic oil basins – the Permian in West Texas/New Mexico, and Eagle Ford Shale in South Texas as each added several rigs. The biggest boost came from the Eagle Ford, which rose by four rigs to 77 week on week while the Permian was up three to 404. But the Bakken Shale in North Dakota/Montana fell by three rigs, leaving 50, while the SCOOP-STACK plays of Oklahoma and the Denver-Julesburg Basin remained static week on week at 41 and 23, respectively. In gas basins, the Haynesville Shale in East Texas/northwest Louisiana dropped four to 47 while Appalachia – the Marcellus Shale, mostly found in Pennsylvania and the Utica Shale mostly in Ohio – declined two rigs, leaving 49. That basin comprises the Wet Marcellus which lost one rig for a total of 19; the Utica, which also fell by a rig, leaving 12; and the Dry Marcellus, which was unchanged week on week at 18.

U.S. shale oil output to rise 29,000 bpd to record 9.14 million in January (Reuters) – U.S. oil output from seven major shale formations is expected to rise about 29,000 barrels per day (bpd) in January to a record 9.14 million bpd, the U.S. Energy Information Administration said in a monthly forecast on Monday. Output at the largest formation, the Permian Basin of Texas and New Mexico, is expected to rise 48,000 bpd to a new record 4.74 million bpd, the smallest increase since July. Production from North Dakota and Montana’s Bakken region is expected to rise by about 3,000 bpd to a fresh peak of about 1.53 million bpd. That would be the smallest increase since production from the region declined in September, the data showed. The agency forecast production declines in the Eagle Ford and Anadarko basins. The Permian and Bakken regions have been the biggest drivers of a shale boom that has helped make the United States the biggest oil producer in the world, ahead of Saudi Arabia and Russia. However, the rate of growth has slowed as independent oil producers cut spending on new drilling and completions and focus more on earnings growth. The oil rig count, an early indicator of future output, has already declined for a record 12 months in a row. Separately, U.S. natural gas output in the big shale basins was projected to increase to a record 85.6 billion cubic feet per day (bcfd) in January. That would be up less than 0.1 bcfd over the December forecast, its smallest monthly increase since January 2019 when production in the big shale basins declined. Growth was slowing as the number of rigs in each region has declined since the start of the year.

Permian Drillers Are Struggling To Keep Output Flat – Newer wells in the Permian see their oil and gas production declining much faster than older wells, and operators will need to drill a large number of wells just to keep current production levels, an IHS Markit analysis showed on Thursday. IHS Markit has analyzed what it calls the “base decline” rate, calculating the actual or expected production of all the operating wells at the start of the year and tracking their cumulative decline by the end of the year. Over the past decade, the base decline rate of the more than 150,000 producing oil and gas wells in the Permian has “increased dramatically,” according to the analysis.“Because of the large increases of recent years, the base decline production rate for the Permian Basin has increased dramatically, and we expect those declines to continue to accelerate. As a result, it is going to be challenging, especially for some companies with cash constraints, just to keep production flat,” Raoul LeBlanc, vice president of Unconventional Oil and Gas at IHS Markit, said in a statement.“Now that capital markets have closed for many companies and investors are requiring returns, a critical objective for these companies is to slow production growth, significantly moderating their base declines,” LeBlanc said.Last month, IHS Markit said it expects U.S. production growth to be 440,000 bpd in 2020, “before essentially flattening out in 2021.”“Going from nearly 2 million barrels per day annual growth in 2018, an all-time global record, to essentially no growth by 2021 makes it pretty clear that this is a new era of moderation for shale producers,” LeBlanc said in early November. With capital discipline required by investors and WTI Crude prices expected to average around US$50 in 2020 and 2021, IHS Markit expected in November capital spending for onshore drilling, and completions to have fallen by 10 percent to US$102 billion this year, by a further 12 percent to US$90 billion next year, and by another 8 percent to US$83 billion in 2021.

From Boom To Bust: Permian Shale Towns Face Exodus -Perhaps it’s not evident to anyone who is not an oil-worker living in America’s biggest shale towns, but signs of the shale slowdown predicted by many analysts, and the EIA itself, are already surfacing in the form of vacant hotels, a dip in home prices, a noticeable reduction in overtime hours for oil workers, and a change in standards for hiring. Texas’ Permian basin lost 400 jobs in the first 10 months of this year, according to the Dallas Morning News, and fracking contractor Superior Energy Services Inc. alone announced in late November that it had cut 112 jobs from its Permian Pumpco unit. This is in stark contrast to the first 10 months of 2018, when the Permian added 16,700 jobs. According to the Dallas Federal Reserve’s “Permian Basin Economic Indicators” from November 27 this year, oil production reached a new high in September, though the rig count slipped and drilling has dropped to its lowest level in nearly two years. Not only are frack crews for well completions in the Permian down more than 20% this year, according to the Dallas Morning News, citing Primary Vision Inc., but oilfield services companies are firing people–from National Oilwell Varco to Halliburton and RPC. The Greater Houston Partnership said in a December report that Houston is facing a situation that is “eerily similar to what it faced after the 1980s bust — an oversaturated real estate market, a bleak outlook for oil and gas, and the need for innovation to drive the economy forward”.

U.S. energy chief shrugs off Permian oil slowdown as a ‘pause’ –The golden age of U.S. shale is far from over, with an expected slowdown in the Permian Basin likely to be temporary, according to the new U.S. Energy Secretary. The shale boom helped transform the U.S. into a net exporter of crude and petroleum products in September from a major importer a decade ago. Even as growth is set to slow next year in the Permian and elsewhere as drillers respond to investor demands for capital restraint, Dan Brouillette said the shale boom has further to run. “Maybe there are some folks who — for whatever reason — thought they could make some quick money in this and they are learning that production is not as easy as you might think,” Brouillette said Tuesday in an interview in Washington. “You may see some of them go by the wayside.” Brouillette, who replaced Rick Perry at the beginning of the month, said improvements in drilling technology meant companies are better equipped to respond to price fluctuations than in the past. And prices are less volatile than they used to be, given the new status of the U.S. as a major producer. “The recent events in Saudi Arabia, the recent events with OPEC — none of those had any sort of dramatic or extraordinary move of the market associated with them,” he said. “We’re just not subject to the same types of price shocks that we used to be subjected to.” According to Brouillette, one risk to the growth of U.S. production and exports comes from Democratic presidential candidates including Elizabeth Warren and Bernie Sanders who have promised to ban hydraulic fracturing, the process by which shale rock is broken apart to release oil and gas.

House Dems propose halt to drilling on public lands in broad climate bill — House Democrats introduced sweeping climate legislation Tuesday that would halt fossil fuel production on public lands for at least a year as the nation prepares to drastically cut climate-warming pollution from its own land holdings. The bill from the House Natural Resources Committee requires the Department of the Interior to reach net-zero greenhouse gas emissions on public lands by 2040. “The Trump administration is handing out drilling and coal mining leases like candy, and no thought is ever given by this administration to the climate change impacts,” said Rep. Raul Grijalva (D-Ariz.) a sponsor of the bill as well as chair of the committee. “Our bill is about what’s right for the whole country and not just polluting industries,” he added. Grijalva said the yearlong moratorium on fossil fuel production would be meant to give Interior time to assess how to meet the 2040 goal of net-zero emissions, though the bill also sets targets in five year increments that the department must meet. The department would be barred from issuing new leases until they came into compliance with the targets. The plan would ratchet up the royalties paid by fossil fuel companies that drill and mine on the nation’s more than 600 million acres of public land, raising fees from roughly 12 percent to 18 percent. That increased cost of doing business would be used to create a transition fund to help communities that are largely dependent on the fossil fuel industry.

Residents pack Boulder County forum in search of tips to implement fracking ban – The Denver Post – Three grassroots groups in Boulder County cohosted a public forum Thursday night to discuss what could be done to extend the county’s moratorium on fracking, which is set to expire in the spring.During “The Fracking Threat to Boulder County: What We Can Do About It,” speakers from 350 Colorado, The Lookout Alliance and Colorado Rising discussed the sunset date of a countywide fracking moratorium on March 28, and the signing of Senate Bill 181, which allows local governments more authority to regulate oil and gas. Speakers cited the 6-month-old law as a tool for implementing a ban on fracking and they urged the more than 100 people who packed a room at Unity of Boulder Church to help them on that mission. In the wake of recent fracking site fire in Weld County that hospitalized seven, and many seeing the operations crop up near schools and neighborhoods, those in the audience seemed largely in favor of an outright ban. Gabrielle Katz, a member of Lookout Alliance, walked forum participants through some background and fracking numbers, citing Weld County as the site of 88% of the state’s oil production and 35% of gas production. Since 2000, she said gas production has doubled in the state. With 55,000 wells across the state and 6,000 permits pending before the Colorado Oil and Gas Conservation Commission that trend is likely to continue, she said. With it, comes increased health risks, threats to the environment and accelerating climate change with the mass release of carbon dioxide and methane, Katz said.“This unconventional oil and gas development is now colliding with neighborhoods like my own, Broomfield, Erie, all around us, where we have people living on top of these oil an gas reserves,” Katz also addressed two projects proposed for eastern Boulder County, including Crestone Peak Resources’ seeking to drill 140 wells north of Erie. A company called 8 North also is seeking to set up a fracking operation in Erie. Boulder County Commissioners filed lawsuits against both oil and gas operations. While claims for both were shot down in Boulder County District Court, the county plans to appeal the rulings in an effort to the prevent large-scale operations.

South Dakota governor plans revision of riot-boosting laws (AP) – South Dakota Gov. Kristi Noem is planning to have another try at so-called riot-boosting laws next year, despite previously drawing criticism for supporting such laws ahead of protests related to the Keystone XL pipeline. The Republican governor has written to lawmakers with proposed changes to laws passed earlier this year that were later blocked by a federal judge. The state eventually settled a lawsuit brought by the American Civil Liberties Union by agreeing not to enforce parts of the laws. Noem is proposing changes in the law to repeal parts that the judge deemed unconstitutional and change the definition of “incitement to riot” to meet constitutional protections of free speech, according to her memo. It would charge people with “incitement to riot” if they “urge” three or more people to force or violence. The proposed law defines “urging” as “instigating, inciting, directing, threatening, or other similar conduct,” but excludes oral and written advocacy that does not urge force or violence. Noem drew criticism from Native American tribes in the state for pushing the laws last year ahead of expected protests on Keystone XL pipeline construction. The Oglala Sioux Tribe banned her from tribal lands after Noem signed the legislation.

Tribes: Oil companies should pay for pipeline spills (AP) – South Dakota lawmakers are proposing legislation that would require oil companies to pay for cleaning up any pipeline spills or leaks as plans are being made to construct the Keystone XL pipeline in the state. The State-Tribal Relations Committee on Wednesday agreed to sponsor the bill in the 2020 legislative session at the request of South Dakota Native American tribes. Crow Creek Tribal Chairman Lester Thompson Jr. said the bill would hold pipeline companies accountable. “As a citizen of South Dakota, I really hate to see our local farmers, ranchers, tribal members, just the common citizen who doesn’t make that big dollar like that company does, be hung with a bill for clean up that isn’t their fault,” Thompson said. The bill would require companies to contribute to a state fund based on the pipeline’s length with a cap of $100 million, the Argus Leader reported. Opponents of the Keystone XL pipeline point to a recent spill in northeastern North Dakota in raising concerns about management of the pipeline. Crude began flowing through the $5.2 billion pipeline in 2011. It’s designed to carry crude oil across Saskatchewan and Manitoba, Canada and through North Dakota, South Dakota, Nebraska, Kansas and Missouri on the way to refineries in Patoka, Illinois and Cushing, Oklahoma.

North Dakota oil output growth to improve moderately on OPEC+ cuts: state regulator – The OPEC+ decision to deepen output cuts will cause “slow to moderate” growth in Bakken production, North Dakota’s top oil and gas regulator said Friday. Without a deeper cut, North Dakota production, which set a record of 1.52 million b/d in October, would likely have “flat lined” throughout 2020, Lynn Helms, director of North Dakota’s Department of Mineral Resources, told reporters Friday. Helms said that the decision will likely lead to an increase in capital available to producers. “It was going to be a struggle just to match this 1.5 million b/d,” Helms said. The OPEC+ decision “should result in small increments of production growth through the year 2020.” Last week, OPEC, Russia and nine other allies announced last week that they will deepen collective output cuts by 503,000 b/d to 1.7 million b/d from January through March. In its Short-Term Energy Outlook Tuesday, the US Energy Information Administration said, assuming the cuts stay in place through 2020, global liquids fuel supply from non-OPEC sources will increase by 1.5 million b/d, offsetting OPEC’s decline in production. North Dakota’s oil output in October was up more than 74,500 b/d from September and more than 37,300 b/d from August, when the previous monthly record was set. Roughly 72% of oil produced in October was shipped out of the state by pipeline, 16% was shipped out by rail, 6% was trucked or railed to Canada, and 6% was refined in state, the North Dakota Pipeline Authority said Friday. The state reported that there were 126 well permits issued in October, up from 92 in September and 885 wells are waiting on completion, down from 916 in September. Helms said that statewide, breakeven prices averaged $12/b in Q3 2019, unchanged from Q2, averaging $12/b in McKenzie, Dunn and Mountrail counties and $16/b in Williams County. Nearly all of North Dakota’s active rigs are in those four counties. Statewide breakeven prices have fallen by $10/b, a roughly 45% decline, since Q2 2017, according to the agency. Helms has called the state’s breakeven estimates a “pure breakeven,” which only accounted for recovering drilling and completion costs and did not consider return on investment.

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