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

Written by rjs, MarketWatch 666

Here are some selected news articles from the week ended 22 September 2019.

This article is a feature every Monday evening on GEI.

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Oil jumps on record volume after Saudi attack; horizontal drilling at a 28 month low; DUCs drop most in 3 years

Oil prices were much higher in volatile trading this past week in the wake of the drone & missile attack on Saudi oil infrastructure last Saturday, with the biggest move coming in the opening hour of trading on Monday…after falling 3% to $54.85 a barrel last week, ironically on the hope that war with Iran was less likely after the firing of national security advisor John Bolton, prices of US crude for October delivery opened 12% higher on Monday with the news that 5.7 million barrels, or more than 5.7% of global daily crude production had been knocked out by the drone strikes, with many traders figuring that Saudi production would take months to recover…prices remained volatile throughout the session as the Saudis were silent and speculation swirled, slipping back to as low as $58.77 a barrel by midday, but later rallying to close $8.05, or 14.7% higher at $62.90 a barrel on record trading volume of 1.4 million contracts, the equivalent of 112 times more oil than the US produces in a day….however, oil prices opened lower and slid backwards on Tuesday, as traders reassessed the long term fallout from the attack, with US October oil closing $3.54, or 5.7% lower at $59.34 a barrel after the Saudi oil minister said Saudi oil production would be fully back online by the end of September…oil extended its pullback on Wednesday, first on the prior night’s surprise API report of a crude oil inventory increase, and then after the EIA confirmed the crude build, with the October WTI ending $1.23 lower at $58.11 per barrel following reports that 50% of Saudi production was already back online…but oil prices rose again early Thursday, carried by an equity market rally following the Fed’s rate cut, reaching as high as $59.54 a barrel as risks to Saudi output came into focus, but pulled back near the close to end with a gain of just two cents at $58.13 a barrel…prices eased lower on Friday on renewed concern over the U.S.-China trade war, ending down 4 cents at $58.09 a barrel, but still posted a 6% gain for the week, the biggest weekly gain in 3 months…

With a record volume of trading in oil on Monday, i went looking for some more details on that, which seems to be fairly well captured in the graph and table below:

The graph above and table of crude oil trading volume for Monday September 16 came from the CME group website, as the CME (Chicago Mercantile Exchange) is the owner of the NYMEX (New York Mercantile Exchange) where US oil contracts are traded….directly above, we have the first part of the table showing the volume of trading in each of the first five current oil futures contracts, monthly from October 2019 thru February 2020…on the October line, we’ve circled in blue the Monday trading volume of the October contract, which is the contract quoted by the media as “the price of oil”, which was over 1.4 million contracts…since each contract is for a thousand barrels, Monday’s trading in the October contract represents more than 1.4 billion barrels of US light sweet crude changing hands, or roughly 112 times the amount of oil produced in the entire country on an average day…in addition, on the interactive bar chart above the table, we’ve moused over the bar for the total trading in all oil futures contracts on Monday, to expose that total trading volume for the day was over 3.68 million contracts, or 3.68 billion barrels of crude…on the same bar in red indicates that another 517 million options to buy or sell crude contracts were also traded on Monday, bringing our total volume of oil contract trading on Monday to a figure that represents nearly 4.2 billion barrels of crude…that’s 344 times the amount of oil actually produced in the US during the same period, which just goes to show that it’s the speculators in New York and London who control the price of oil, just based on the shear volume of it they trade electronically…

Meanwhile, natural gas prices finished lower for the first time in four weeks, mostly on a larger than expected injection of gas into storage…after rising 4.7% to $2.614 per mmBTU on short covering following warmer forecasts last week, the natural gas contract for October delivery jumped 6.7 cents higher Monday on notably hotter forecasts for the eastern & southern US during the second half of September, suggesting a continuation of summerlike cooling demand….even so, natural gas prices still slipped 1.3 cents on Tuesday and 3.1 cents on Wednesday in advance of the Thursday storage report, which indicated more surplus gas was added to storage than was expected, driving prices 9.9 cents lower by the end of trading on Thursday…prices then slipped another four-tenths of a cent on Friday to end the week down more than 3% at $2.534 mmBTU..

The natural gas storage report for the week ending September 13th from the EIA indicated that the quantity of natural gas held in storage in the US increased by 84 billion cubic feet to 3,103 billion cubic feet by the end of the week, which meant our gas supplies were 393 billion cubic feet, or 14.5% more than the 2,710 billion cubic feet that were in storage on September 13th of last year, while still 75 billion cubic feet, or 2.4% below the five-year average of 3,187 billion cubic feet of natural gas that have been in storage as of the 13th of September in recent years….this week’s 84 billion cubic feet injection into US natural gas storage was somewhat more than the forecast for an 76 billion cubic feet injection by analysts surveyed by S&P Global Platts, and it was also a bit above the average 82 billion cubic feet of natural gas that have been added to gas storage during the second week of September over the past 5 years, the 25th such average or above average storage build in the last 27 weeks… as a result, the weekly storage injections so far this season are averaging 29% above the five-year average…the 1,925 billion cubic feet of natural gas that have been added to storage over the 25 weeks of this year’s injection season is the second most for the same period in the modern record, eclipsed only by the record 1995 billion cubic feet of natural gas that were injected into storage over the same 24 weeks of the 2014 natural gas injection season, a cool summer when there were no injections below 76 billion cubic feet….

The Latest US Oil Supply and Disposition Data from the EIA

US oil data from the US Energy Information Administration for the week ending September 13th showed that because of a big drop in our refinery throughput while our oil imports were rising, we were left with surplus oil to add to storage for the first time in 4 weeks…our imports of crude oil rose by an average of 326,000 barrels per day to an average of 7,050,000 barrels per day, after falling by an average of 180,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 120,000 barrels per day to an average of 3,175,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 3,875,000 barrels of per day during the week ending September 13th, 446,000 more barrels per day than the net of our imports minus exports during the prior week…over the same period, the production of crude oil from US wells was reported to be unchanged from the prior week at 12,400,000 barrels per day, so our daily supply of oil from the net of our trade in oil and from well production totaled an average of 16,275,000 barrels per day during this reporting week..

US oil refineries were reportedly processing 16,707,000 barrels of crude per day during the week ending September 13th, 788,000 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 151,000 barrels of oil per day were being added to 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 and from oilfield production was 583,000 barrels per day less than what was reportedly added to storage and 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 (+583,000) 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”….with that great a quantity of oil unaccounted for again this week, it calls into question the other oil totals that the EIA has reported and that we have just transcribed (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 fell to an average of 6,652,000 barrels per day last week, now 12.7% less than the 7,704,000 barrel per day average that we were importing over the same four-week period last year…the 151,000 barrel per day increase in our total crude inventories was all added to our commercially available stocks of crude oil, while the amount of oil stored in our Strategic Petroleum Reserve remained unchanged……this week’s crude oil production was reported to be unchanged at 12,400,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was unchanged at 12,000,000 barrels per day, while a 25,000 barrels per day increase to 423,000 barrels per day in Alaska’s oil production had no impact on the final rounded national production total…last year’s US crude oil production for the week ending September 7th was rounded to 11,00,000 barrels per day, so this reporting week’s rounded oil production figure was 12.7% above that of a year ago, and 47.1% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016…

Meanwhile, US oil refineries were operating at 91.2% of their capacity in using 16,707,000 barrels of crude per day during the week ending September 13th, down from 95.1% of capacity the prior week, & somewhat below the normal refinery utilization rate for mid-September…as a result, the 16,707,000 barrels per day of oil that were refined this week were 4.1% below the 17,415,000 barrels of crude per day that were being processed during the week ending September 14th, 2018, when US refineries were operating at 95.4% of capacity….

With the big drop in the amount of oil being refined, gasoline output from our refineries was quite a bit lower, decreasing by 909,000 barrels per day to a nine-month low of 9,451,000 barrels per day during the week ending September 13th, after our refineries’ gasoline output had increased by 88,000 barrels per day over the prior week…with that big decrease in gasoline output, this week’s gasoline production was 8.0% lower than the 10,270,000 barrels of gasoline that were being produced daily over the same week of last year….at the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) fell by 232,000 barrels per day to 5,109,000 barrels per day, after our distillates output had increased by 187,000 barrels per day the prior week….with that decrease, our distillates production was 6.4% less than the 5,457,000 barrels of distillates per day that were being produced during the week ending September 14th, 2018….

However, even with the big drop in our gasoline production, our supply of gasoline in storage at the end of the week managed to increase for the 5th time in 14 weeks and for just the 6th time in twenty-nine weeks, increasing by 781,000 barrels to 229,685,000 barrels during the week to September 13th, after our gasoline supplies had fallen by 682,000 barrels over the prior week….our gasoline supplies increased this week because the amount of gasoline supplied to US markets decreased by 868,000 barrels per day to 8,939,000 barrels per day, while our exports of gasoline rose by 55,000 barrels per day to 692,000 barrels per day, and while our imports of gasoline fell by 296,000 barrels per day to 501,000 barrels per day…but even after this week’s increase, our gasoline supplies were still 1.9% lower than last September 14th’s inventory level of 234,150,000 barrels, while increasing to roughly 4% above the five year average of our gasoline supplies for this time of the year…

Likewise, even with the big decrease in our distillates production, our supplies of distillate fuels rose for the 12th time in the past 27 weeks, increasing by 437,000 barrels to 136,663,000 barrels during the week ending September 13th, after our distillates supplies had increased by 2,704,000 barrels over the prior week…our distillates supplies increased this week even as the amount of distillates supplied to US markets, a proxy for our domestic demand, increased by 55,000 barrels per day to 3,859,000 barrels per day, and while our exports of distillates rose by 136,000 barrels per day to 1,330,000 barrels per day, as our imports of distillates rose by 98,000 barrels per day to 142,000 barrels per day….but even after this week’s inventory increase, our distillate supplies were still 2.5% less than the 140,122,000 barrels of distillates that we had stored on September 14th, 2018, and remained around 6% below the five year average of distillates stocks for this time of the year…

Finally, as our imports rose while our refineries processed much less oil, our commercial supplies of crude oil in storage rose for the third time in fourteen weeks and for the eighteenth time in 35 weeks, increasing by 1,058,000 barrels, from 416,068,000 barrels on September 6th to 417,126,000 barrels on September 13th…that modest increase still left our crude oil inventories 2% below the five-year average of crude oil supplies for this time of year, but more than 24% higher than the prior 5 year (2009 – 2013) average of crude oil stocks after the second week of September, 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 the past year up until the most recent fourteen weeks, after generally falling until then through most of the prior year and a half, our oil supplies as of September 13th were still 5.8% above the 394,137,000 barrels of oil we had stored on September 14th of 2018, but at the same time were 8.8% below the 472,832,000 barrels of oil that we had in storage on September 15th of 2017, and also 8.8% below the 473,966,000 barrels of oil we had in commercial storage on September 16th of 2016…

This Week’s Rig Count

The US rig count fell for the 27th time in 31 weeks over the week ending September 20th, and is now down by 20% since the end of last year….Baker Hughes reported that the total count of rotary rigs running in the US fell by 18 rigs to a 29 month low of 868 rigs this past week, which was also down by 185 rigs from the 1053 rigs that were in use as of the September 21st report of 2018, and well less than half of the shale era high of 1929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC announced an attempt to flood the global oil market…

The count of rigs drilling for oil decreased by 14 rigs to 719 rigs this week, which was a 28 month low for oil rigs and 147 fewer oil rigs than were running a year ago, and quite a bit below the recent high of 1609 rigs that were drilling for oil on October 10th, 2014…at the same time, the number of drilling rigs targeting natural gas bearing formations fell by 5 rigs to 148 natural gas rigs, a 30 month low for gas rig drilling activity and down by 38 rigs from the 186 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…however, a vertical rig classified as miscellaneous began drilling on the island of Hawaii this week, targeting a formation between 5000 and 10,000 feet below the surface, matching the miscellaneous rig count of a year ago, when the miscellaneous rig was drilling in Richland county Ohio..

Gulf of Mexico offshore drilling activity was down by 2 to 23 rigs running this week, as two platforms offshore from Louisiana were shut down…the 23 rigs still left drilling offshore from Louisiana were up by 5 from the 18 Gulf of Mexico rigs deployed a year ago, when there was 17 rigs drilling in Louisiana waters and one drilling offshore from Texas…in addition to the Gulf, a directional rig began drilling offshore from the Kenai Peninsula in Alaska, where there are now two rigs, one targeting oil and the other targeting natural gas at a greater depth of more than 15,000 feet…that offshore Alaska count matches the offshore Alaska count of a year ago, so the national total of 25 offshore rigs is up by 5 rigs from the 20 rigs that were deployed offshore a year ago…

The count of active horizontal drilling rigs was down by 20 rigs to 756 horizontal rigs this week, which was the least horizontal rigs deployed since May 12th, 2017 and hence is a 28 month low for horizontal drilling…that was also 163 fewer horizontal rigs than the 921 horizontal rigs that were in use in the US on September 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 down by 2 to 51 vertical rigs this week, and those were also down by 14 from the 65 vertical rigs that were operating during the same week of last year…on the other hand, the directional rig count was up by 4 to 61 directional rigs this week, but those were still down by 8 from the 69 directional rigs that were in use on September 21st of 2018…

The details on this week’s changes in drilling activity by state and by major shale basin are included in our screenshot below of that part of the rig count summary pdf from Baker Hughes that shows 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 September 20th, the second column shows the change in the number of working rigs between last week’s count (September 13th) and this week’s (September 20th) count, the third column shows last week’s September 13th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running before the equivalent 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 September, 2018…

A significant number of the rigs that were shut down this week had been drilling in basins not tracked separately by Baker Hughes, so the basin table above comes up short on identifying the rigs shut down in the various states…for instance, the 10 rigs idled in Oklahoma include single oil rigs in the Arkoma Woodford and Ardmore Woodford, two oil rigs and one natural gas rig in the Cana Woodford, and 5 rigs in those “other basins” that Baker Hughes does not track…in Texas, we saw a rig added in Texas Oil District 8, or the core Permian Delaware, and 2 rigs added in Texas Oil District 8A, encompassing the northern part of the Permian Midland, while 6 rigs were shut down in Texas Oil District 7C, or the southern part of the Permian Midland, for a net loss of 3 Permian oil rigs in Texas, which thus means that the New Mexico start-up was in the far western Permian Delaware basin…the 2 oil rigs and single natural gas rig shut down in the south Texas Eagle Ford account for 3 more Texas losses, leaving just one Texas retirement in a basin not tracked separately by Baker Hughes…elsewhere, the two rigs shut down in the Williston basin match the North Dakota count, but the rig added in the Denver-Julesburg NIobrara of the Rockies front range means that 2 rigs in either Wyoming or Colorado were shut down in those “other” basins that Baker Hughes doesn’t track…those “other” basins also account for the remaining 3 natural gas rig closures. as the rig count in all the major natural gas basins was unchanged this week…also note that other than the changes in activity in the major producing states shown above, Mississippi had two rigs start up this week and now has three rigs drilling, still down from 5 rigs a year ago, while Montana also saw a rig start up in the first drilling in that state since January…the aforementioned miscellaneous rig that started drilling in Hawaii, by the way, is the first drilling in that state since July 2016…

DUC well report for August

Monday of this past week saw the release of the EIA’s Drilling Productivity Report for September, which includes the EIA’s August data for drilled but uncompleted oil and gas wells in the 7 most productive shale regions…for the sixth month in a row, this report showed a decrease in uncompleted wells nationally in July, as both drilling of new wells and completions of drilled wells decreased….moreover, the Permian basin of western Texas and New Mexico, which had been seeing an increase of newly drilled but uncompleted wells (DUCs) every month of late, also saw a decrease in DUCs in August for the first time since August 2016…for the 7 sedimentary regions covered by this report, the total count of DUC wells decreased by 142 wells, the largest decrease in 36 months, falling from a revised 8,092 DUC wells in July to 7,950 DUC wells in August, which still represents a 10.7% increase from the 7,181 wells that had been drilled but remained uncompleted as of the end of August a year ago…that DUC decrease occurred as 1,247 wells were drilled in the 7 regions that this report covers (representing 87% of all U.S. onshore drilling operations) during August, down by 62 from the 1,311 wells drilled in July and the lowest in 17 months, while 1,389 wells were completed and brought into production by fracking, a decrease of 6 well completions from the 1,395 completions seen in July….at the August completion rate, the 7,950 drilled but uncompleted wells left at the end of the month still represent a 5.7 month backlog of wells that have been drilled but are not yet fracked, the same backlog as a month ago…

Both oil producing regions and natural gas producing regions saw DUC well decreases in August, with only the natural gas producing Haynesville shale showing a small increase…the number of DUC wells left in the Oklahoma Anadarko decreased by 46, from 906 at the end of July to 860 DUC wells at the end of August, as 102 wells were drilled into the Anadarko basin during August while 148 Anadarko wells were being fracked….in addition, the Permian basin of west Texas and New Mexico saw its total count of uncompleted wells fall by 25, from 3,864 DUC wells at the end of July to 3,839 DUCs at the end of August, as 525 new wells were drilled into the Permian, while 550 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 23 to 438, as 178 Niobrara wells were drilled in August while 201 Niobrara wells were completed….meanwhile, DUC wells in the Bakken of North Dakota fell by 22, from 674 DUC wells at the end of July to 652 DUCs at the end of August, as 97 wells were drilled into the Bakken in August, while 119 of the drilled wells in that basin were being fracked…in addition, DUC wells in the Eagle Ford of south Texas decreased by 16, from 1,474 DUC wells at the end of July to 1,458 DUCs at the end of August, as 184 wells were drilled in the Eagle Ford during August, while 200 already drilled Eagle Ford wells were completed..

Among the natural gas producing regions, the drilled but uncompleted well count in the Appalachian region, which includes the Utica shale, fell by 12 wells, from 529 DUCs at the end of July to 517 DUCs at the end of August, as 116 wells were drilled into the Marcellus and Utica shales during the month, while 128 of the already drilled wells in the region were fracked…on the other hand, the natural gas producing Haynesville shale of the northern Louisiana-Texas border region saw their uncompleted well inventory increase by 2 wells to 188, as 45 wells were drilled into the Haynesville during August, while 43 Haynesville wells were fracked during the same period….thus, for the month of August, DUCs in the five oil basins tracked by in this report (ie., the Anadarko, Bakken, Niobrara, Permian, and Eagle Ford) decreased by a net of 132 wells to 7,247 wells, while the uncompleted well count in the natural gas basins (the Marcellus, Utica, and the Haynesville) decreased by 10 wells to 703 wells, although as the report notes, once into production, more than half the wells drilled nationally will produce both oil and gas…

5 Permits Awarded for Utica-Point Pleasant Drilling – Five permits for drilling in the Utica-Point Pleasant shale were issued by the Ohio Department of Natural Resources in the week ended Sept. 14, the agency reports. Four were granted to Ascent Resources Utica: two each in Belmont and Harrison counties. The other permit was awarded to Utica Resource Operating for a well in Guernsey County. No permits were awarded in Mahoning, Trumbull or Columbiana county, nor were any granted by the Pennsylvania Department of Environmental Protection in Lawrence or Mercer counties. Through the end of last week, the ODNR reported 14 active rigs in the Utica-Point Pleasant shale play. For horizontal drilling, 3,162 permits have been issued to date with 2,694 wells drilled.

DC Circuit Rejects Requests to Vacate FERC Authorization for Nexus Pipeline, Remands for Explanation on Use of Foreign Precedent Agreements in Project Need Determination . On September 6, 2019, the U.S. Court of Appeals for the D.C. Circuit (“D.C. Circuit”) dismissed the City of Oberlin, Ohio’s and the Coalition to Reroute Nexus’s (collectively, “Petitioners”) request to vacate FERC’s authorization of Nexus Gas Transmission, LLC’s (“Nexus”) to (1) construct and operate an interstate natural gas pipeline through parts of Ohio and Michigan; and (2) use eminent domain to acquire any necessary rights of way to complete the project (see December 18, 2018 edition of the WER). The D.C. Circuit agreed with Petitioners, however, that the Commission failed to adequately substantiate its finding that it lawfully credited Nexus’s precedent agreements – under which shippers agree to enter into service agreements once the pipeline is built – with foreign shippers serving foreign customers as evidence of market demand for the interstate pipeline. As a result, the D.C. Circuit remanded this issue to the Commission, without vacatur, for further explanation of the decision. In determining that Nexus’ project was in the public convenience and necessity, the Commission (1) found that Nexus’s precedent agreements were “the best evidence” that the pipeline served unmet market demand; (2) approved Nexus’s proposed 14% return on equity (“ROE”), subject to the condition that Nexus design its initial customer rate based on a hypothetical capital structure of 50% equity and 50% debt; and (3) found that the pipeline does not “represent a significant safety risk to the public.” Following the Commission’s authorization, the U.S. District Court for the Northern District of Ohio found that Nexus had the right to exercise eminent domain to condemn certain easements over Petitioners’ properties, and Nexus subsequently exercised that right. In response, Petitioners asked the D.C. Circuit to vacate the Commission’s order granting Nexus an NGA section 7 certificate, along with its orders on rehearing.

Court questions pipeline land grab – Why was building a pipeline that exported some of its natural gas to Canada enough to justify taking property away from land owners using eminent domain? The decision to construct the NEXUS natural gas pipeline is still being challenged, even though the pipeline has been operating in Erie County and across much of Ohio since 2018. Earlier this month, the District of Columbia Court of Appeals ruled in favor of the landowners who opposed the pipeline. On Sept. 6, the court ordered the Federal Energy Regulatory Commission to answer why the pipeline was needed that it required the use of eminent domain, a government power to seize land for public use. Robert Wheeler of Milan, one of the local landowners who battled the pipeline, said he hopes the ruling will help other landowners defending their rights. “Obviously, the pipeline’s there to stay,” he said. “It’s not going to go away.” Property rights are a guarantee of the U.S. Constitution, but using eminent domain to take property is one way around that. David A. Mucklow, an Akron attorney who represented landowners opposing NEXUS, said technically the court still could vacate the FERC’s order, shutting down the gas pipeline. But that appears to be unlikely. Probably the best case scenario is that landowners will get further compensation, he said.

Fracking to Begin in Oil Reservoir Found Beneath Brukner Nature Preserve – Oil and Gas Development Company Limited Inc. (OGDCLI) has recently filed for permits to lease the entirety of Brukner Nature Preserve to begin fracking on a massive, newly discovered oil and gas reservoir. According to OGDCLI’s statement, the oil and gas reservoir is one of the largest deposits in the entire world. The deposit makes the Miami County one of the top 25 leading natural gas producing sites on earth, replacing Uzbekistan as the number 15. A joint venture comprising of OGDCLI and Troy’s Walnut Society plans to begin fracking operations in fall of 2019. Fracking, or hydraulic fracturing, is the controversial process of forcing a cocktail of water and chemicals into rock to widen fissures, enabling natural gas to be extracted. For years, environmental groups, tribes and other opponents have raised flags about frackingencroaching on Bruckner Nature Preserve, a major center of historic Miami County culture and heritage.“People complain about gas prices all of the time. Maybe they should be careful what they wish for,” stated OGDCLI CEO Tyson McGreenahan. “Fracking happens everywhere. Now that it’s happening in Miami County’s backyard, of course everyone is up in arms.” Bruckner Nature Preserve sits in the central basin of the Miami Valley, an area that’s booming with shale gas extraction. Roughly 90 percent of the Brukner Nature Preserve is already leased for oil and gas development, but more fossil fuels lie beneath those lands. OGDCLI wants to sell parcels of land that are along the park’s 10-mile, no drilling buffer zone. “You can’t monetize nature,” said Shelly Smythe of Miami Conservational. “Actually, you can, but it’s wrong. We need to protect Bruker Nature Preserve.” Miami Conservational will open a protest period in the Brukner Nature Center’s parking lot beginning September 2nd, with intent to “stay put until OGDCLI ceases plans for fracking.”

Report: Secret Fracking Chemicals a Concern for Ohio – – Troubling information has been uncovered about the use of so-called classified chemicals in fracking operations in Ohio. Using mapping and data analysis by FracTracker Alliance, new research from the Partnership for Policy Integrity shows the oil and gas industry injected potentially toxic chemicals more than 11,000 times into roughly 1,400 fracking wells between 2013 and 2018.Report author Dusty Horwitt, senior council at the Partnership, said there’s cause for concern.”EPA regulators have found that many secret chemicals have health risks,” Horwitt said. “And there are multiple potential pathways of exposure, including leaks and spills, underground migration, also road-spreading of these chemicals.” Ohio law allows well owners to conceal chemical formulas as trade secrets, which Silverio Caggiano, battalion chief at the Youngstown Fire Department, said ties the hands of first responders who need to act fast in a spill or explosion. “We depend upon being able to quantify and qualify the product that we’re dealing with so we know how to mitigate it,” Caggiano said. “If I don’t know what it is, I can’t identify its physical properties and how I’m going to take care of it, or how to protect people.” The industry has claimed trade-secret provisions prevent competitors from stealing their formulas. Horwitt countered there is a way for companies to protect their chemical information without keeping the public in the dark. “Drilling companies can make their chemical identities available to the public in a random list, so that their competitors would not be able to reverse-engineer that list of chemicals into the products that they’re putting into their wells,” Horwitt said. Caggiano said he isn’t opposed to fracking, but feels the industry is being given a free pass.

What’s in fracking chemicals? Energy nonprofit demands answers – Ohioans could be exposed to dangerous chemicals that state laws don’t require drilling and fracking companies using them to disclose, according to a report issued by a nonprofit organization.“Ohio and 28 other states have enacted rules that require some public disclosure of fracking chemicals. However, most if not all of these rules have exceptions that allow well owners to withhold chemical identities as trade secrets,” according to a report by the Partnership for Policy Integrity, a group based in Pelham, Massachusetts, that specializes in energy policy. “We looked at Ohio’s records and found trade-secret chemicals being used extensively in eastern Ohio in oil and natural gas wells, which could be some of the same trade-secret chemicals that the (U.S. Environmental Protection Agency) has health concerns about. We can’t say that definitively because the identities are secret,” said senior counsel Dusty Horwitt, who wrote the report.“But it’s entirely possible that some of these chemicals could have effects that EPA identified like neurotoxicity, developmental toxicity, lung toxicity, kidney toxicity and liver toxicity,” Horwitt said. “People need to know. People have a right to know, and first responders have a right to know if they might be exposed to those types of chemicals.”Well drillers sometimes use a process known as hydraulic fracturing, or “fracking,” in which they inject sand, water and chemicals to fracture rock layers deep below the surface to release oil and gas trapped within them. They injected secret chemicals 10,992 times into 1,432 wells in Ohio between 2013 and 2018, according to the report. The Ohio Oil and Gas Association characterized the recommendations in the report as “recycled.” The concerns broached in the report “were addressed way back in 2012 before shale development began, with support from the Ohio Oil and Gas Association,” through Senate Bill 315.

Trade Secret: Oil And Gas Companies Won’t Say What’s In Their Fracking Chemicals – WOSU –A new analysis by the nonprofit Partnership for Policy Integrity finds that “trade secret” chemicals were injected into gas and oil wells nearly 11,000 times in Ohio during a five-year period. Some first responders like Silverio Caggiano, fire battalion chief with the Youngstown Fire Department, are concerned that this is leaving the public at risk in emergencies. Caggiano has been a hazardous materials technician for more than 28 years and was an original member of the Ohio Hazardous Materials and Weapons of Mass Destruction Technical Advisory Committee. He says his hazmat team usually gets a warm welcome from local industries that use potentially dangerous chemicals. Most want to coordinate emergency planning. “When we get to a facility, we’re used to, ‘Here’s everything we got. You guys are the rock stars, help us out,’” Caggiano said. Emergency planning ensures that if there’s an explosion or a fire, the hazmat team knows what chemicals are used at a facility, and how to respond. But according to Caggiano, oil and gas companies aren’t interested in sharing information about all their chemicals with the local hazmat team.”Fracking is a whole different deal,” he said. “We’ve made attempts many times to talk to these frack industries and they don’t want to work with you.” Fracking companies use chemicals for everything from limiting the growth of bacteria, to preventing corrosion of well casings. Ohio laws enacted in 2010 and 2012 require drillers to disclose the chemicals they use. But, there’s a loophole: Oil and gas companies don’t have to identify chemicals they consider trade secrets.”Partnership for Policy Integrity analyzed state data and found that between 2013-2018, well owners injected undisclosed chemicals nearly 11,000 times at more than 1,400 wells in Ohio. The report was funded in part by the Park Foundation, which also funds The Allegheny Front. Adam Schroeder, a spokesperson for the Ohio Department of Natural Resources, Division of Oil and Gas Resources Management, said in a recorded audio statement, “Owners are required to disclose product by supplier trade name, chemical name and maximum concentration. An owner may designate certain information as trade secret and withhold it from reporting.” “The state can access information from well owners if there’s a spill or other emergency,” he said. “Critical safety information is always available and any additional information can be requested and accessed if necessary.”But Caggiano calls this a “pseudo disclosure.” That’s because in an emergency, Caggiano says he doesn’t have time to send an email to ODNR and wait for a response. His hazmat team needs to know immediately whether to use water to put out a fire, or something else. Caggiano gives the example of a gas well fire in Monroe County in 2014. It took days for the state to provide chemical information.

Marcellus and Utica Shales in the US, 2019-Gas Shales Market Analysis and Outlook to 2023 – The US Appalachian Basin located in Pennsylvania, Ohio, West Virginia and New York continues to be the driver in natural gas production within the United States. During May 2019, it produced around 31 billion cubic feet per day (Bcfd) and is forecast to reach a rate of approximately 35 Bcfd by the end of 2019. The basin comprises the two main formations – the Marcellus, and the Utica. The majority of the activity in the Marcellus continues to take place in north east and south west Pennsylvania while the hotspot for the Utica is in eastern Ohio. Fracking activity in the Marcellus and Utica formations is driven by the large demand for natural gas from the nearby populated areas and although natural gas prices have experienced some volatility during recent years, Appalachian producers are generally able to sell their natural gas at a premium in trading hubs located in the North East. The competitive landscape of the Marcellus play is largely dominated by EQT Corp., the largest natural gas producer in the US, whereas, Ascent Resources LLC and Gulfport Energy Corp. lead the natural gas production in the Utica play. Browse more detail information about this report here: The report analyzes the natural gas appraisal and production activities in the Marcellus and Utica shale plays. The scope of the report includes –

– Comprehensive analysis of natural gas production across major counties in Pennsylvania, West Virginia, Ohio, and New York during 2013-2018, as well as production outlook from 2019 to 2023

– In-depth information of well permits issued in the Pennsylvania region of the Marcellus and Utica shale, by county and by company from January 2018 to March 2019

– Detailed understanding of IP rates and type well profiles in Marcellus and Utica formations

– Exhaustive analysis of competitive landscape in the Marcellus and Utica shale in terms of net acreage, gross production, cost trends and planned investments.

– Comparison of type well economic metrics of major players were also analyzed

Environmental groups continue push to investigate link to fracking and childhood cancer – – TV news video- Three environmental groups point to published research that link the fracking industry with chronic illnesses and they continue to suspect a deeper concern related to childhood cancer rates. FracTracker, Southwest Pennsylvania Environmental Health and Center for Coalfield Justice held their most recent community information meeting to create awareness. “We know that fracking poses a health risk and we don’t know what that health risk is,” says Heaven Sensky, of Center for Coalfield Justice. Several dozen residents attended the most recent information session at Cannonsburg Middle School. It covered everything, from the basics of fracking, to the various ways air and water are adversely affected by malfunctions and oversight. This was the most recent in a series of meetings in southwestern Pennsylvania, with more scheduled for the immediate future, says Sensky, “We’re not getting answers from our industry leaders or our elected officials. We started there. We started with asking questions.”

PUC says no leak or damage to line after latest sinkhole along Mariner East 2 in Delaware County – A five foot by eight foot hole in the ground opened up in a park in Middletown Township in Delaware County on Friday, exposing part of the Mariner East pipeline that transports natural gas liquids. Eric Friedman lives in the area and saw what happened. “The particular sinkhole that I saw was near the intersection of Valley Road and Forge Road, in Sleighton Park, just a few feet away from nearby residences and a few feet away from soccer fields in places where children play,” Friedman said. The Pennsylvania Department of Environmental Protection said heavy rain caused the hole, and that there was no contamination or environmental impact. The gas company Sunoco filled in the hole Friday afternoon and the Pennsylvania Public Utility Commission started a safety investigation. The PUC said in a news release that the sinkhole occurred in the right of way for a 12-inch steel pipeline that moves “highly volatile liquids (HVLs) and petroleum products” along Sunoco’s Mariner East pipeline system. The sinkhole was near construction work for Mariner East 2, and near “several other pipelines,” the PUC said. The agency added that no leaks or injuries were reported. The PUC said initial indications are that the pipeline was exposed by the sinkhole, but that there were no “integrity issues” with the line. The Mariner East project has resulted in multiple sinkholes in the densely populated Philadelphia suburbs, including Chester and Delaware counties.

Exclusive: Antero to idle pioneering wastewater treatment plant that opened two years ago – – The Antero Clearwater Facility near Greenwood has been idled and has stopped receiving water while it undergoes a cost-effectiveness evaluation. The plant cleans water that has been used in fracking so it can safely be reused. Antero Resources Chief Administrative Officer and Regional Senior Vice President Al Schopp said the evaluation will help determine if it is the best, most cost-effective way to of dealing with the water. “(It’s) to determine what is the best thing going forward. The plant is not being shut down by any stretch of imagination. …The price of oil is low right row, and we need to be looking at every aspect of business, and this is one that we are looking at,” he said.Schopp said injecting used water into a disposal well or reusing water in depletion operations are other industry alternatives, and the evaluation will help determine how the plant compares to other options.“We just need to see if there are ways to make the plant more efficient and to make it more competitive with the other methods,” he said.The Doddridge County facility can treat a maximum capacity of up to 40,000 barrels of water a day. For the last year, it has been treating between 20,000 and the maximum each day.Schopp added the plant is safe and free of both safety and environmental issues. The idle will not impact any other operations or programs at Antero.

Pipeline protester found not guilty of assaulting security guard – An assault charge against a Giles County man involved in protesting the Mountain Valley Pipeline was tossed out Monday after a judge watched a video of the man’s encounter with a security guard at a construction site – and ruled there was no attack. The not guilty verdict for Jammie Hale, 47, of Pembroke, came in a Montgomery County General District Court hearing that showed a personal level to the ongoing controversy surrounding the natural gas pipeline, which is being built from West Virginia through six Virginia counties. The pipeline’s backers call it a vital piece of the region’s energy infrastructure, while opponents say it will only contribute to increased pollution, and that its construction damages the environment and infringes on property rights.

Mountain Valley Pipeline sues more Alamance Co. landowners – – The company behind the proposed Mountain Valley Pipeline Southgate has sued five more Alamance County landowners to get access for surveys to test the pipeline’s potential route. In all, MVP has sued eight landowners in Alamance County this year and four more in Rockingham County, according to court records. MVP has already been granted consent judgments allowing it access to three of those properties in cases it filed in the spring. Hearings on four of the five cases filed in August will be held Sept. 30, according to court records. MVP dismissed the suit against the fifth landowner Sept. 12. North Carolina law gives condemnors, which includes pipelines, the right to “enter upon any lands, but not structures, prior to condemnation to make surveys, borings, examinations, and appraisals,” so it is likely that MVP will get access to these properties at the Sept. 30 hearings. The properties in question are on Cherry Lane, Haw River Hopedale, Basin Creek and Jimmie Kerr roads. The proposed Mountain Valley Pipeline Southgate would be a 72-mile, 24-inch-diameter line connecting to the existing MVP in Pittsylvania County, Va., to carry Marcellus shale gas to the PSNC distribution system south of Graham, near Cherry Lane Road and Alamance Community College, according to documents submitted to the county. The earlier stage of the pipeline, still under construction in Virginia, has been controversial and mired in litigation over numerous citations for violating environmental regulations. MVP Southgate would provide natural gas to Dominion Energy customers, according to the MVP website, but opponents, including the Haw River Assembly and Sierra Club, say it will be a health and environmental hazard, and abuse of property rights through eminent domain, and that the company heavily inflates the growing demand for natural gas in the region. The Alamance County Board of Commissioners adopted a resolution in September 2018 opposing the pipeline. While the commissioners have no authority to permit or stop the pipeline, the resolution went to the Federal Energy Regulatory Commission. In July, the FERC released a Draft Environmental Impact Statement minimizing the potential long-term damage the pipeline’s construction would cause, which opponents have criticized.

Houston-based energy co. to review strategic alternatives year after exiting bankruptcy – Houston-based Harvest Oil & Gas Corp is undertaking a review of strategic alternatives, during which the company will consider potentially selling some or all of its remaining assets or a potential sale or merger of the company. The move comes a little over a year after the company emerged from Chapter 11 bankruptcy protection as the successor to EV Energy Partners LP, an upstream master limited partnership that Houston-based EnerVest Ltd. formed in 2006. Harvest now describes itself as “an independent oil and gas company engaged in the acquisition, efficient operation and development of onshore oil and gas properties in the continental United States.” Harvest also will review options to reduce its overall cost structure now that it has completed other divestitures. The company sold substantially all of its interests in the Barnett Shale for $63.5 million and some of its oil and gas properties in the Anadarko Basin and SCOOP/STACK area for $5.4 million, per the Sept. 16 release. Buyers were not disclosed. Harvest plans to return net proceeds from the deals to shareholders, possibly through dividends, distributions or share repurchases, the company said. UBS Investment Bank acted as Harvest’s financial adviser on the transactions, and Kirkland & Ellis LLP acted as the legal adviser. Earlier this year, Harvest sold all of its interests in the San Juan Basin in New Mexico and Colorado for $42.8 million and all of its 4.2 million shares of Magnolia Oil & Gas Corp. (NYSE: MGY), which it acquired in August 2018. The newly formed Magnolia bought Harvest’s South Texas assets for about $135 million in cash plus 4.2 million newly issued shares valued at approximately $56 million as of Aug. 20, 2018. Also in August 2018, Harvest announced it would sell certain Eagle Ford formation rights and existing production in Lee County, Texas, to a third party for $3.5 million in cash. The company’s assets now consist primarily of producing and non-producing properties in the Appalachian Basin (which includes the Utica Shale), Michigan, the Mid-Continent areas in Oklahoma, Texas, Kansas and Louisiana, the Permian Basin and the Monroe Field in Northern Louisiana.

Court Nixes ‘Eminent Domain’ for Big East Coast Fracked-Gas Pipeline – Federal appellate judges’ reversal of decisions by a lower court and by the Federal Energy Regulatory Agency to allow private developers of the $1-billion, 120-mile PennEast natural gas pipeline to condemn state-owned land in New Jersey appears headed for US Supreme Court review.The Sept. 10 ruling by the three-judge panel of the Third Circuit Court of Appeals in Philadelphia said the previous approvals of eminent domain to seize131 land parcels, including 40 that are state-owned, for the 36-in.-dia line violate the US Constitution’s 11th Amendment. PennEast had argued it was allowed under the federal Natural Gas Act to condemn properties along the line route and said that a ruling like the one it ultimately received could cause that project and other interstate pipelines to halt.Pat Kornick, a spokeswoman for PennEast Pipeline Co., said the firm is still reviewing the appellate decision and did not confirm a high-court appeal in a statement. But she said PennEast “remains committed to moving forward” with the project. The company had stated its intention to limit impacts to waterways by drilling beneath streams where possible, and restoring streambeds after construction is completed. But New Jersey Attorney General Gurbir Grewal said the state-owned properties are open space preserved for recreation, conservation and agriculture and not suited for natural gas shipment. He said the 11th Amendment grants states immunity from eminent domain takings by private entities.Environmental group Delaware Riverkeeper, the project’s leading opponent, said the ruling could have wider implications. “This is a huge blow against the PennEast pipeline project and a huge victory for states and states rights,” said the group’s director Maya Van Rossum.

EDITORIAL: Bills calling for gas pressure monitors left to languish – Effects of the Merrimack Valley’s gas disaster linger, large and small. Some people are still putting their lives back together. For others, the residuals are emotional and psychological. Something else held over – maddeningly so – are plans to make natural gas work safer. On Beacon Hill, Sen. Bruce Tarr filed a bill back in January to require utilities to assign monitors to job sites. These individuals would watch over the work and be able to quickly shut off service – a check against the rapid ratcheting up of gas pressure that unleashed last fall’s swarm of fires and explosions in the Merrimack Valley. On the House side, Rep. Barry Finegold filed a similar bill. But, as Statehouse reporter Christian Wade chronicled this past week, both proposals are stuck in committee. Tarr tried jump-starting his by hooking it to the state’s $43 billion budget. The gambit didn’t work. Finegold told Wade he’s confident his plan will get a hearing. A full year after the gas disaster, and months after these bills were filed, one could be forgiven for being skeptical. A year after the disaster, it’s well past time for action. Beacon Hill isn’t the only muddy place where these plans bogged down. Capitol Hill is another. Sen. Ed Markey and Rep. Lori Trahan filed legislation in Congress to require on-site monitoring of gas work, naming the bill after Leonel Rondon, the 18-year-old killed in South Lawrence last Sept. 13. Their plans haven’t moved either. Their legislation would go a step further, requiring professional engineers to scrutinize plans for gas line work. Massachusetts enacted that rule in response to a preliminary report on the gas disaster by the National Transportation Safety Board. As Wade reported, however, many other states still exempt utilities from that level of oversight. Public safety in those places, one expert told him, is compromised as a result.

As LIPA cuts its natural gas bill, Grid says new pipeline still needed — LIPA, Long Island’s largest natural gas user, has cut its usage by two-thirds in the past decade – to the tune of $400 million – even as supplier National Grid has been making a case that soaring overall demand for gas requires a new pipeline. National Grid downplayed the 65.5 percent decline in the yearly natural gas usage by the Long Island Power Authority over that time, saying its largest customer’s lower bill is unrelated to the need for the Northeast Supply Enhancement project, which, if approved, would increase local capacity by about 14 percent. “Even if LIPA used zero natural gas, NESE is still required to serve the increased customer demand for new and expanded natural gas service and to support economic growth,” National Grid spokeswoman Karen Young said, adding local demand for natural gas is projected to increase by more than 10 percent over the next 10 years.” National Grid has declared a moratorium on new gas hookups across Long Island until New York State regulators, who have twice rejected it, approve the project. Meanwhile, the state is investigating National Grid’s claim of a local shortage, which some environmental critics charge is based on false forecasts to tie the region to a fossil-fuel future. Local developers and even some doing home renovations have been caught in the crossfire, as National Grid refuses to commit to firm service for any new customers.

Baltimore’s natural gas system is increasingly leaky, raising concerns about safety and global warming – More and more natural gas has been leaking out of aged pipes in and around Baltimore in recent years, likely diminishing the fossil fuel’s relative Earth-friendliness and creating hazards that can lead to explosions like one that devastated a Columbia building last month. Leaks are so frequent that nearly two dozen of them are discovered each day, on average, according to data the Baltimore Gas and Electric Co. reports to federal authorities. The number of leaks increased by 75 percent from 2009 to 2016 – amid what officials called a “dramatic” increase in the failure of pipe joints dating to the 1950s and 1960s. Beyond the immediate safety concerns, the leaks contribute to the greenhouse effect that has been warming the planet for decades. And new research suggests more natural gas from Baltimore and other older cities is reaching the atmosphere than previously thought. The leaks won’t be stopped anytime soon. In the Baltimore area, BGE needs to replace thousands of miles of obsolete pipes that already could be leaking. Though hundreds of workers are assigned to the task, at the rate BGE is going, the work will take at least two decades.“This leaking methane has a huge impact in the atmosphere, and it’s not good for consumers,” said Mike Tidwell, director of the Chesapeake Climate Action Network. On top of the contributions to global warming, he said, “it’s a resource lost. It’s inefficient.”

Weather Forecasts Jump Back Hotter As Summer Refuses To Go Quietly — For a couple of days last week, it looked like the abnormally hot pattern in place was finally ready to fade away, but weather models over the weekend jumped notably hotter for the second half of September. Here is today’s GFS ensemble forecast for next week, for example. Back on Friday, this is what the forecast looked like from the same model, valid the same dates. Given that the change included a hotter southern half of the U.S, this was enough to boost natural gas demand compared to forecasts back on Friday, as seen in our forecast Gas-Weighted Degree Day (GWDD) change in our morning update. This September’s projected GWDD total is among the highest in the historical dataset. While of course not the sole reason for the large natural gas rally over the last few weeks, it has definitely been about as supportive as weather can be at this time of the year. Should the run of warmth last a few weeks longer, however, it would transition into a bearish factor. Some models, such as the CFS, indicate such a possibility, which is tough to argue with, as warm-dominated as the pattern has been since late June. CFS October outlook:

US natural gas in underground storage rises by 84 Bcf: EIA – US working natural gas volumes in underground storage rose 84 Bcf last week, more than most of the market expected, as the NYMEX Henry Hub prompt-month contract and winter strip plummeted following the announcement. Storage inventories increased to 3.103 Tcf for the week ended September 13, the US Energy Information Administration reported Thursday morning. The injection was more than an S&P Global Platts’ survey of analysts calling for a 76 Bcf build. It was at the high end of the survey range as responses spanned from 71 Bcf to 85 Bcf. The build was equal to the 84 Bcf injection reported during the corresponding week in 2018, but just above the five-year average of 82 Bcf, according to EIA data. As a result, stocks were 393 Bcf, or 14.5%, above the year-ago level of 2.710 Tcf and 75 Bcf, or 2.4%, above the five-year average of 3.178 Tcf. The NYMEX Henry Hub October contract fell 8.1 cents to $2.556/MMBtu following the announcement. The winter strip dropped 7.34 cents to $2.708/MMBtu. Comparing the weekly EIA ranges for cash prices, cash prices were up across the board week on week outside the West. The biggest mover was the Waha hub, which was up nearly 40% as congestion relief from Gulf Coast Express Pipeline has allowed that market to recover. For the week in progress, total US supply shows virtually no change while demand is down by 1.2 Bcf/d week on week, according to S&P Global Platts Analytics. Reductions in gas-fired power generation burn occurred along the East Coast and Texas, where temperatures fell on average about 1.5 degrees. The Southeast featured the largest weekly losses at 0.8 Bcf/d compared with the Northeast and Texas at 0.6 Bcf/d and 0.2 Bcf/d, respectively. Storage inventories look to rise 79 Bcf and 88 Bcf over the next two weeks, according to a Platts Analytics forecast. These bulky builds would continue to reduce the ever-shrinking deficit to the five-year average. The EIA has only reported two injections less than the five-year average since March. Both occurred in July, as hot weather drove demand. Over the past five years, the final injection of the season, on average, was the week ended November 8. If stocks add the same amount as the five-year average over said time frame, 552 Bcf, peak storage would hit 3.655 Tcf. The five-year end-of-season average is 3.73 Tcf. But weekly storage injections so far this season are averaging 29% above the five-year average. If this continues through season’s end, stocks will peak at 3.8 Tcf. With recent builds coming in closer to average, the final volume will likely be somewhere between 3.6 and 3.8 Tcf.

Weaker Cash And Bearish EIA Report Send Natural Gas Prices Tumbling After testing the 2.70 level in the prompt month October contract a couple of times earlier this week, sellers have taken control the last couple of days, especially in today’s session, which saw prompt month prices decline nearly 10 cents. Ironically, just yesterday in our Seasonal Trader Report, we highlighted to clients the risk of such a move back into the 2.50-2.55 range. In the spirit of fairness, this occurred quicker than we expected, thanks mostly to a bearish EIA report released this morning. Prices were already lower on weaker daily cash, but the 84 bcf injection reported for last week accelerated the decline. This was higher than our estimate, and while the EIA reports have been erratic lately, seemingly alternating bearish / bullish each week, anything close to an 84 is reflective of very loose supply / demand balances, as seen when looking at the last 10 weeks. The larger injection came despite a hot, higher demand weather pattern in place, with a lot of heat last week in key areas of the nation. Above normal temperatures are forecast to remain quite strong over the next couple of weeks. Time of year tells us, however, that we are getting closer to the point where above normal temperature regimes switch from bullish to bearish, as “normal” levels of HDDs begin to overtake “normal” CDD levels. That would not bode well for natural gas price support if that occurs in conjunction with weaker supply / demand balances. That said, the one thing we know in the natural gas world is that things can change, especially when it comes to the weather.

Gas Prices Could Return to Disco-Era Levels – A vestige of the era of disco, bell-bottoms and stagflation could be making a comeback next year: very cheap natural gas. So says IHS Markit, which on Thursday predicted that oversupply will push the average U.S. natural gas price for 2020 below $2 per million British thermal units (MMBtu). The information services firm observes that sub-$2 per MMBtu amounts to the lowest average gas prices in real terms since the 1970s. In nominal terms, natural gas did fall below $2 in 1995, IHS added. “It is simply too much too fast,” Sam Andrus, IHS Markit executive director who covers North American gas markets, said in a written statement emailed to Rigzone. “Drillers are now able to increase supply faster than domestic or global markets can consume it. Before market forces can correct the imbalance, here comes a fresh surge of supply from somewhere else.” According to IHS Markit, robust domestic gas demand and rising export levels will fail to keep prices from falling. Since January 2018, U.S. gas production has increased by more than 14 billion cubic feet per day (Bcfd), the company stated, adding that domestic output should average more than 90 Bcfd this year and next. Also, it anticipates a 3-Bcfd increase in liquefied natural gas (LNG) exports in 2020. IHS Markit also noted the next surge of U.S. gas production likely will come from the Permian Basin in West Texas. It stated that growth from the Permian will “more than compensate” for declines in other regions, sustaining the oversupply condition and requisite downward pressure on prices. “Nearly all the growth in U.S. natural gas demand over the next few years will come from LNG exported to other countries,” Andrus said. Factors driving the Permian output growth forecast include associated gas and 6 Bcfd of new pipeline takeaway capacity slated to go online through 2022, IHS Markit stated. Michael Stoppard, the firm’s chief strategies for global gas, pointed out the associated gas will get produced out of the oil well in any event. “The real change here is the transportation capacity,” said Stoppard. “You go from a situation where producers, in many cases, were paying someone to take their gas to having an economic means of getting it to market.”

Trump-Modi may unveil Indian investment in US LNG – President Donald Trump and Indian Prime Minister Narendra Modi may unveil new economic partnerships between the two countries at a joint appearance in Houston this weekend, including potential Indian investment in a US Gulf coast LNG project. Trump said in Washington, DC, yesterday that there “could be” an announcement on 22 September during an event at Houston’s NRG Stadium expected to be attended by more than 50,000 people.In February, India’s Petronet LNG signed a preliminary agreement with Houston-based LNG developer Tellurian to invest in the company in exchange for long-term LNG supplies from Tellurian’s planned Driftwood LNG export terminal near Carlyss, Louisiana.When asked if that deal could be advanced or finalized this weekend, Tellurian told Argus, “We will certainly confirm any deal when we have it.”Petronet is India’s largest LNG importer but it does not have any long-term deals for US LNG. It has a long term deal for 8.5mn t/yr with Qatar’s state-controlled Qatargas and a 1.44mn t/yr long-term deal with Australia’s Gorgon LNG. Both those deals are indexed to oil prices, so Petronet may be seeking to diversify its procurement strategy with Henry Hub-indexed LNG. Prices of spot LNG delivered to India were around $4.50/mn Btu in August, down considerably from August last year, although cargoes from Qatar and Australia delivered under long-term contracts cost more than $8/mn Btu. Indian LNG imports climbed last month from a year earlier as domestic gas demand increased while gas output slowed. Imports were at 2.1mn t, equivalent to 88.3mn m³/d of dry gas. This was up from 80mn m³/d a year earlier and unchanged from July.

EOG to Supply Gas to Cheniere Texas Facility – EOG Resources, Inc. has signed long-term natural gas supply agreements with two subsidiaries of Cheniere Energy, Inc., Cheniere reported Monday afternoon.Under EOG’s gas supply agreements (GSA) with Corpus Christi Liquefaction, LLC and Cheniere Corpus Christi Liquefaction Stage III, LLC, the exploration and production company will initially sell Cheniere 140,000 million British thermal units (MMBtu) per day of gas but ramp up volumes to 440,000 MMBtu per day, Cheniere noted in a written statement. The approximately 15-year GSA period begins in 2020. Cheniere stated that it will own and market the roughly 0.85 million tonnes per annum (mtpa) of LNG associated with 140,000 MMBtu per day of the gas supply, adding that EOG will receive a price for this share of gas based on the Platts Japan Korea Marker (JKM). EOG will sell Cheniere the remaining 300,000 MMBtu of gas at a Henry Hub-indexed price, the LNG producer noted. Cheniere also pointed out that a portion of the transaction hinges on a positive final investment decision on the Corpus Christi Stage III project, which would add up to seven midscale liquefaction trains with roughly 9.5 mtpa of capacity. The U.S. Federal Energy Regulatory Commission (FERC) granted the project a positive environmental assessment in March of this year, noted Cheniere, adding that all remaining regulatory approvals are forthcoming by the end of 2019.

NextDecade, Enbridge Team to Build LNG Pipeline – NextDecade Corporation and Enbridge Inc. have entered into a Memorandum of Understanding (MOU) for the development of the Rio Bravo Pipeline as well as other natural gas pipelines in South Texas. This will transport natural gas to NextDecade’s Rio Grande LNG project in Brownsville, Texas. Rio Bravo is built to feed 4.5 billion cubic feet per day of natural gas from the Agua Dulce area to Rio Grande LNG. “With its Texas Eastern Pipeline and recently completed Valley Crossing Pipeline, Enbridge has extensive permitting, construction and operating experience in the State of Texas, especially in South Texas.” Bill Yardley, Enbridge’s president of gas transmission and midstream, shared excitement as well to be working with NextDecade for pipeline solutions to the Rio Grande LNG facility. “Our existing infrastructure fits very well with the Brownsville location,” said Yardley. “This is a continuation of our strategy to bring our major projects execution and permitting capability to the expanding LNG export efforts in North America.” NextDecade and Enbridge expect to finalize the terms of the MOU in the fourth quarter of this year.

EOG Resources lands deal to supply natural gas to Corpus Christi LNG – Houston oil & gas company EOG Resources has landed a natural gas supply deal for Cheniere Energy’s Corpus Christi LNG export terminal. The companies confirmed the 15-year gas supply agreement in a joint statement released on Monday afternoon. Under the deal, EOG Resources will supply 140,000 million British Thermal Units of natural gas per day to the South Texas facility starting in 2020. The delivery amount will be gradually increased to 440,000 MMBTU of natural gas per day. Financial terms were not disclosed, but the companies confirmed that EOG Resources will receive a price based on the Platts Japan Korea Marker for the 140,000 MMBTU of natural gas while the remaining 300,000 MMBTU will be sold to Cheniere at at a price indexed to the Henry Hub in Louisiana.

Expanding NGL Markets Likely To Affect Producer Decisions – – Expanding markets for natural gas liquids produced in the Appalachian Basin should provide an extra financial incentive for natural gas producers in the region to maintain robust production in the long term, although concerns over low gas and NGL prices continue to dominate short-term planning, writes S&P Global Platts. Demand for NGLs produced in association with natural gas production in the Appalachian Basin is expected to increase dramatically in the next several years. In the short term, the demand growth will come from NGL pipeline projects being built or expanded to take products such as ethane, propane, and butane to markets far removed from Appalachia. In the longer term, in-basin NGL demand is expected to be generated by the construction of large-scale manufacturing projects, such as the ethane cracker being built by Shell in Monaca, Pa. Enterprise Products (Houston) has begun soliciting shipper interest in a proposed expansion of its ATEX pipeline that would move more supplies from the Appalachian Basin to its NGL complex in Mont Belvieu. The 1200-mile ATEX, or Appalachia-to-Texas, line transports ethane from the Marcellus and Utica shale plays in Pennsylvania, West Virginia, and Ohio to Enterprise’s Mont Belvieu NGL complex. Depending on demand, Enterprise would add up to 50,000 bbld of incremental capacity by 2022 through a combination of pipeline looping, hydraulic improvements, and modifications to existing infrastructure. Another pipeline option to transport NGLs out of the Appalachian Basin is Energy Transfer Partners’ (Dallas) 350-mile Mariner East 2 pipeline. The line, which went into service late last year, has 345,000 bbld of capacity to carry a mixture of ethane, butane, pentane, and propane from the tristate gas-producing region to the Marcus Hook Industrial Complex and export facility in eastern Pennsylvania. A second source of NGL demand, this time within the basin, is being created by the development of a petrochemical manufacturing industry in the region, identified by industry advocates as the Shale Crescent, the area surrounding the northern stretch of the Ohio River and comprising parts of Pennsylvania, West Virginia, and Ohio. The most advanced of these projects is the 1.5-million-metric-ton/year steam cracker Shell is building near Monaca. The plant, which will use ethane to manufacture polyethylene used in plastics manufacturing, is expected to cost up to $6 billion. In addition, a joint venture led by Thai-owned PTTGC America and South Korea’s Daelim is planning to construct a petrochemical complex in southeastern Ohio, though that project has yet to pass the final investment decision phase.

Capital Dries Up As New Crude, Gas And NGL Infrastructure Comes Online – U.S. energy markets are coming to the end of their latest infrastructure cycle just as the reality of tight capital markets is sinking in. Permian crude oil and natural gas takeaway constraints are being relieved by new pipeline capacity. Long-delayed LNG terminals and NGL-consuming petrochemical plants are coming online. Essentially all growth in crude, gas and NGL production volumes is being exported to global markets that – so far, at least – have been absorbing the incremental supply. But there is a chill in the air. Besides the recent bump-up in crude prices tied to last weekend’s attack on Saudi oil facilities, commodity prices have remained stubbornly low. Easy access to capital is a thing of the past. No longer can private equity count on the build-it-and-flip asset investment model. Yup, it’s another inflection point in the Shale Revolution that we’ll start exploring today. All this has huge implications for energy flows, infrastructure utilization and price relationships across all of the energy commodities. As is well-documented in the RBN blogosphere (for example, see Don’t Stop Believin’) and pretty much every other energy-related information source on the planet, equity markets have soured on energy investments. With public investors demanding return of capital in the form of dividends and share buybacks, and private equity spooked by a dearth of M&A deals, the result has been a steady decline in energy investment. Consider one indicator: the rig count. Crude rigs are down about 150 this year, or 17%, while gas rigs are down 45, or 23% (see left and center graphs in Figure 2 below). Another relevant indicator is the value of E&P stocks, with the S&P Oil & Gas E&P Index crashing from the 6,500 range a year ago to a paltry 3,500 level in recent weeks (right graph in Figure 2), though the index jumped nearly 400 points on Monday morning after the weekend’s Saudi news (then lost half of that one-day gain on Tuesday).

Damaged barge removed after spilling 117K gallons of oil — Crews have removed a damaged barge that spilled oil from Tennessee-Tombigbee Waterway in northeast Mississippi. U.S. Coast Guard Lt. David Schneider tells WTVA-TV that the Jamie Whitten Lock remains closed as cleanup continues and the barge’s cargo is removed. The barge spilled more than 117,000 gallons (443,000) liters of oil on Sept. 8, prompting an extensive cleanup effort. Crews worked to contain the oil spill inside the lock, although 4 miles (6.5 kilometers) of the waterway were closed. Schneider says the barge will be transported to New Orleans for repair. The Savage Inland Marine barge was carrying about 321,000 gallons (1.21 million liters) of oil, but nearly two-thirds was safely removed.The Coast Guard is investigating.

Current regulations aren’t enough to keep offshore oil industry in check – With an administration pushing for more oil exploration in the Gulf of Mexico, drilling watchdogs say they don’t trust the infrastructure used to collect the oil nor the government regulations and policies that oversee oil and gas companies. “I think they really want the industry to regulate itself, so they really don’t want to take an active role,” said Ian MacDonald, a Florida State University professor and oceanographer. “They’re trying to roll back environmental regulations because their philosophy is the economy will be better.” MacDonald points to the Taylor Energy leak as one example of the industries’ inability to effectively clean up existing oil leaks. One of about 3,000 platforms in the western and central Gulf of Mexico, the Taylor Energy site is about 19 miles off the coast of Louisiana. It was toppled by Hurricane Ivan in 2004, and oil has been leaking from the site since. Although the Coast Guard has recently capped at least part of the leak, higher estimates suggest about the site has been leaking about 70,000 gallons a day. A recent Coast Guard says the leak is about 30,000 gallons per day. The leak has spanned three presidential administrations, and the Donald Trump version is keen on more drilling. Although the Taylor leak started in 2004, little work was done on the site until 2010, after a group now called Healthy Gulf reported a sheen miles long. “At the end of the day we’ve been relying on industry self-reporting for pollution events for far too long,” said Dustin Renaud, with the non-profit Healthy Gulf. “We don’t have a system in place to verify or fact-check them (because) that’s directly against their self-interests as a corporation.”

Texas Charges Oil Port Protesters Under New Fossil Fuel Protection Law – A group of activists who shut down one of the nation’s largest oil ports by hanging off a bridge over the Houston Ship Channel have been charged under a new Texas law that imposes harsh penalties for disrupting the operations of fossil fuel infrastructure. The charges could present the first test for a wave of similar state lawsthat have been enacted around the country over the past three years in response to high-profile protests against pipelines and other energy projects. More than two-dozen Greenpeace activists were arrested in Harris County after a number of them dangled from a bridge on Sept. 12 holding banners with the aim of blocking oil and gas tankers from passing through a busy shipping channel below. The Texas law they were charged under was based on a model billpromoted by the American Legislative Exchange Council, an industry-backed group.Lawmakers in at least 16 states have introduced versions of the bill over the past three years. Seven states have enacted them as law, according to the International Center for Not for Profit Law, and Iowa and South Dakota have enacted different bills with similar aims. The U.S. Department of Transportation earlier this year also proposed that Congress enact similar language into federal law. The bills create harsh criminal penalties for people who trespass on pipelines or other “critical infrastructure” facilities, and several of them allow for steep fines of up to $1 million for organizations that support people who violate the laws. Oil and gas industry groups have lobbied in favor of the bills, part of an effort to ratchet up pressure on protesters.

Greenpeace members face federal, state charges in Houston protest – (Reuters) – Federal and state authorities on Friday criminally charged climate change protesters for shutting down the largest U.S. energy-export port for a day by dangling from a bridge. The protest organized by Greenpeace closed part of the Houston Ship Channel on Thursday. The Harris County District Attorney’s office said its charges were the first under a new law that makes it a felony to disrupt energy pipelines and ports. “This action cost our community many, many millions of dollars in lost commerce,” said Sean Teare, a Harris County prosecutor, citing day-long shipping disruptions. Those charged include 31 people who dangled on ropes off a bridge or who provided logistical support, said Teare. Most of the protesters were expected to appear Friday before a magistrate for a probable cause hearing, he said. All 31 face up to a $10,000 fine and two years in prison if convicted. The district attorney’s office plans to convene a grand jury to consider other criminal charges, he said. Federal prosecutors separately charged 22 members of the same group with misdemeanor obstruction of navigable waters, according to a filing on Friday. They could face up to a year in prison on the federal charges. “This is a bullying tactic that serves the interests of corporations at the expense of people exercising their right to free speech,” said Tom Wetterer, Greenpeace’s general counsel. Texas was one of seven states this year that passed laws seeking to curb protests over energy projects such as the Dakota Access Pipeline and Bayou Bridge pipeline.

Catastrophic Flooding Threatens Heart Of Texas Oil Industry – Flooding from a tropical storm hit the Houston area on Thursday, with some calling the situation worse than Hurricane Harvey. Heavy rainfall inundated the Texas coast, flooding Houston and Beaumont, home to massive oil refining, petrochemical and export facilities. The storm was downgraded to just a tropical depression, but those classifications only measure wind speed. The real threat from Imelda was “major, catastrophic flooding,” according to the National Weather Service. “Extremely persistent thunderstorms” created the potential for 6 to 12 inches of rain, with higher levels in certain areas. “Storm total rainfall could be in excess of two feet for some areas before the weather finally begins to improve!” the NWS said in a notice. The forecast predicted that through Friday, some parts could see rain reach as high as 25 to 35 inches. But the Texas Department of Transportation said on Thursday that 41 inches of rain had already hit the area between Beaumont and the town of Winnie (between Beaumont and Houston). The sudden and rapid flooding of the area caught many by surprise, with thousands of people trapped in their homes and cars. Texas Gov. Greg Abbott said that the floods have “caused widespread and severe property damage and threatens loss of life.” He declared a state of disaster across 13 counties. The slow-moving nature of the storm meant that intense rain continued to pummel the region. “What I’m sitting in right now makes Harvey look like a little thunderstorm,” Chambers County Sheriff Brian Hawthorne told ABC13, a local ABC affiliate. “It’s dire out here. I’m fearful for this community right now.” ExxonMobil said on Thursday that it was shutting down its 370,000-bpd Beaumont, Texas refinery because of flooding. “Exxon Mobil’s Beaumont refinery and chemical complex is conducting a preliminary assessment to determine the impact of the storm,” an Exxon spokesman said. “The Beaumont chemical plant has completed a safe and systematic shutdown of its units.”

Sur de Texas-Tuxpan Pipeline begins commercial operations in Mexico – More natural gas from the Eagle Ford Shale of South Texas and the Permian Basin of West Texas is flowing south of the border in Mexico.Just three weeks after resolving a contract dispute with the Mexican government, Infraestructura Marina del Golfo, a joint venture between the Mexican subsidiaries of Canadian pipeline operator TC Energy and San Diego utility company Sempra Energy, announced Tuesday that a $2.6 billion pipeline designed to move natural gas from deep South Texas to Central Mexico has started commercial operations.The underwater Sur de Texas-Tuxpan Pipeline is designed to move 2.6 billion cubic feet of natural gas per day, the 42-inch and 480-mile pipeline begins in the Gulf of Mexico a few miles east of Brownsville and continues underwater to power plants in the coastal cities of Altamira, Tamaulipas and Tuxpan, Veracruz. It connects with other pipelines to move natural gas to other destinations further inland.“After reaching an agreement with the Federal Electricity Commission and the Mexican government, this important energy infrastructure project will provide a fundamental link between an abundant, low-cost natural gas supply to growing markets in Mexico for decades to come,” TC Energia President Robert Jones said in a statement.AMLO: Mexico reaches deal in natural gas pipelines controversyDeveloped as part of a contract issued by Mexico’s Federal Electricity Commission, the Sur de Texas-Tuxpan Pipeline receives its natural gas from the Valley Crossing Pipeline, a separate project developed by Canadian pipeline operator Enbridge to move natural gas from the Agua Dulce hub near Corpus Christi to the U.S./Mexico border.Tuxpan Economic Development Director Juan Pablo Alcantar told the Houston Chronicle that the Sur de Texas-Tuxpan Pipeline will feed five natural gas-fired power plants in Tuxpan capable of producing more than 4,100 megawatts of electricity. Two of the power plants are owned and operated by Japanese industrial conglomerate Mitsubishi, two are owned by Spanish energy firm Naturgy and a power plant owned by the Federal Electricity Commission that was switched over from fuel oil to natural gas.The pipeline will also feed another two natural gas power plants being built by the Spanish power company Iberdrola to produce an additional 1,200 megawatts of power. Once complete, Alcantar said Tuxpan will produce more electricity than any other city in Mexico.

New Fracking Process Highlights Oil Industry’s Achilles Heel – Reuters published an interesting story on September 12 titled, “Low-cost fracking offers boon to oil producers, headaches for suppliers.” The story details a new hydraulic fracturing technology called “E-Frac” that promises to save producers up to $350,000 per well over the more traditional frac spread. E-Frac bills itself as “electric fracking,” which is really slightly misleading. In fact, these frac spreads, operated by Evolution Well Services, deploy electric turbines powered by the operating company’s own natural gas production in place of the diesel-powered generators deployed in traditional fracking operations. These turbines are quieter, cheaper to operate and produce far less air emissions than their diesel counterparts. Now, there’s a concept: Oil and gas companies finding a use for their unconnected lease natural gas besides flaring it. The big wonder here is why didn’t we read this story in Reuters a decade ago? There is nothing novel about companies using their lease gas to power wellsite equipment. That’s been happening for a century now in one form or another. Nor is there anything new about the portability of these natural gas turbines, which are basically scaled-down versions of the turbines used in electric power generation plants. The only thing really new here is that a service company decided to raise and invest the up-front capital needed to make the concept a cost-saver for producers and thus make the company a going concern. But big service providers like Halliburton and Schlumberger have already signaled that they won’t be rolling out their own “electric fracking” spreads anytime soon. Why? Because the up-front estimated capital cost of $60 million per spread is too expensive, double the cost of a traditional, diesel-fueled spread. “It’s a bad time for service companies to be ramping up very capital-intensive service offerings,” Reuters quotes Josh Young, chief investment officer with energy investor Bison Interests. But again, none of this is “new” technology in any real sense, so when is a good time for making those investments? More to the point, why didn’t the industry invest to adopt this kind of environmentally-friendly, flaring-reducing technology when oil was selling for $100/bbl and times were good? After all, flaring has been a big issue in the Bakken Shale play since 2008, in the Eagle Ford Shale since 2010 and in the Permian Basin since 2012. Instead of being proactive on the issue, the industry has continued to deploy and refine its traditional, diesel-fueled fleets, relying on messaging that the flaring problem would go away once all the new pipelines are built. But that promise hasn’t exactly worked out in the Bakken, where North Dakota regulators recently noted that, despite the build-out of significant new pipeline expansions, the industry there flared 24% of its production in June. That’s a new all-time record for the state, double the 12% target set by the North Dakota Industrial Commission.

Study suggests Texas address oil and gas waste water – Oil and gas producers in Texas are seeking ways to mitigate waste water from oil and gas operations, as state lawmakers in neighboring New Mexico moved to do the same. The two states share the Permian Basin, a vast underground oil and gas shale play credited with leading the U.S. toward energy independence and driving up local economies in the region. The Permian’s rise to prominence was due to hydraulic fracturing, or fracking, and horizontal drilling. Fracking uses billions of barrels – about 42 gallons each – of water each year. New Mexico Gov. Michelle Lujan Grisham announced last week a consortium of the New Mexico Environment Department, the New Mexico Energy Minerals and Natural Resources Department, Office of the State Engineer and New Mexico State University to begin studying how to treat and reuse produced water, potentially providing the resource to other industries. A report released Monday from the Texas Alliance of Energy Producers said 8.5 billion barrels of produced water – or waste water – was created in 2017 across Texas and could increase to more than 15 billion barrels by 2023. The study titled Sustainable Produced Water Policy, Regulatory Framework, and Management in the Texas Oil and Gas Industry: 2019 and Beyond said Texas oil and gas producers will be forced to continue sourcing water for fracking from an area in West Texas where water is scarce and freshwater sources are depleting. “Water demand for fracturing operations will continue to increase due to the growing numbers of wells drilled and completed coupled with the concurrent increase in fracturing fluid proppant intensity, well lateral lengths and well design improvements,” read the report.

Permian ‘Child’ Wells May Cut Oil Recovery By 20%, Bank Says – Oil producers drilling so-called parent-child wells in the Permian Basin are risking the loss of 15% to 20% of the crude that can ultimately be recovered from those wells by spacing them too close together, according to a Houston-based investment bank. The analysis from Houston-based investment bank Tudor, Pickering, Holt & Co. — contained in a 61-page presentation seen by Bloomberg — is the latest salvo in the debate on the spacing of so-called parent-child wells in the Permian, the most prolific oil patch in the U.S. When drilled too close to the initial “parent” well, output from a “child” can be much less prolific. But producers risk leaving oil in the ground if the spacing is excessive. In much of the Permian, a region that stretches across West Texas and New Mexico, the amount of oil that can be recovered from child wells is on average about 20% to 30% lower than that of the parent, the analysis shows. That means overall production from a particular area could be some 15% to 20% lower than projections made by producers. “Child wells get progressively worse relative to their parent well with tighter spacing,” according to the analysis. In a note to clients Friday, Sanford C. Bernstein analyst Bob Brackett said parent-child interference could end up decreasing overall production by a million barrels a day. “But it’s back end loaded,” he said. It’s not all bad news. One solution to the parent-child problem is to drill and frack both wells at the same time, which has been shown to improve recoveries, according to Tudor, Pickering, Holt. Those “co-developed” wells are showing results that are largely in line with company projections, the analysis said. Last year, 60% of wells in the Permian’s Delaware sub-basin were child or co-developed wells, according to the bank. Until 2017, the bulk of the Delaware was made up of parent wells. Tudor, Pickering, Holt declined to comment on the presentation.

Energy Transfer Makes a $5 Billion Bet on Crude Oil – Energy Transfer announced this week that it would acquire SemGroup for $17 per share, an eye-popping 65% premium to its closing price last Friday. The cash-and-stock deal valued themidstream company at $5 billion, including the assumption of debt. While the acquisition of SemGroup will do several things for Energy Transfer, the main driver of this deal is how it will bolster the company’s oil transportation business. Energy Transfer’s acquisition of SemGroup will significantly enhance the company’s scale in several important production basins and market centers. Because of that, it will increase the connectivity of the company’s crude oil and natural gas liquids (NGLs) business. At the heart of the deal is SemGroup’s Houston Fuel Oil Terminal Company (HFOTCO), which is a world-class crude oil terminal on the Houston Ship Channel. That facility can store 18.2 million barrels of oil and has five deepwater ship docks from which it can export oil to global markets. Supporting the terminal are stable take-or-pay contracts that provide predictable cash flow. In addition to HFOTCO, Energy Transfer will pick up crude oil and NGL gathering assets in the DJ Basin of Colorado and Anadarko Basin in Oklahoma and Kansas. The company will also get some crude oil and NGL pipelines that connect those two regions to oil terminals in Cushing, Oklahoma, which is a major oil hub. Finally, Energy Transfer will gain a significant oil gathering and transportation business in western Canada. Although Energy Transfer is paying a substantial premium for SemGroup, it’s getting all these assets at a good value. The company is paying only nine times EBITDA after adjusting for the expected $170 million in annual cost savings. For comparison’s sake, Kinder Morgan recently sold its Canadian subsidiary and a related pipeline for 13 times EBITDA. The low price Energy Transfer is paying despite the significant premium is a result of the slump in SemGroup’s stock over the past few years. The current offer price, for example, is still 28% below where shares traded a year ago and more than 50% below where they were three years ago.

More earthquakes occurring in Kansas, none have broken the record for the most powerful quake – WDAF FOX4 Kansas City – – Earthquakes keep rocking Kansas this year. It might have some people a little on edge about whether the state can expect a large-scale earthquake. The good news: It’s pretty unlikely for Kansas to see a quake like the ones that rattle California. There isn’t an active enough fault-line to produce the more damage-heavy tremors.An investigation is underway to find out why the state has received so many quakes and what can be done to prevent them. At least 50 quakes have shaken up an array of counties in the Sunflower State this year. A series of three quakes rattled portions of south-central Kansas on Sunday and Monday. The Kansas Geological Survey said the strongest quake measured Monday was a 3.8 tremor. It was reported around 2:30 a.m. in Chase County about 75 miles northeast of Wichita. Another quake rattled off around 10 a.m. It was a 3.6 magnitude quake. A quake was also reported in Reno County Sunday at 10:20 a.m. Hutchinson is in Reno County, the area is about 50 miles northwest of Wichita. spike in quakes goes all the way back to 2014. Researchers blame many of the quakes on wastewater injection wells from oil and gas production. After oil prices dropped and more regulations were added, the number of quakes decreased in 2015. This year is a different story. The back-to-back quakes in Reno County have led the Kansas Corporation Commission to look further into injection well activity. The regulatory agency took that action after a cluster of 17 earthquakes hit in Reno County over five days from August 15 to August 20.The strongest quake of the year was a 4.8 magnitude tremor on June 22. “Amid damage reports and a concern for public safety, the KCC is conducting an investigation and will evaluate whether additional action is needed to safeguard Kansans,” KCC spokesperson Linda Berry said in a written statement announcing the investigation.

Judge grants injunction in ‘riot booster’ lawsuit – A judge has put a temporary stop to South Dakota’s new riot booster law aimed at Keystone XL pipeline protesters. U.S. District Judge Lawrence Piersol granted a preliminary injunction on Wednesday in a lawsuit against Gov. Kristi Noem and Attorney General Jason Ravnsborg alleging the state’s riot laws, which allow the state to sue “riot boosters” including on behalf of a third party, were unconstitutional. Piersol also denied the state’s request to certify the question to the South Dakota Supreme Court and he granted Pennington County Sheriff Kevin Thom’s motion to dismiss the case against him, leaving Noem and Ravnsborg as the sole defendants. The state has an interest in criminalizing participation in a riot, but the state’s laws defining a riot “go far beyond that appropriate interest and … do impinge upon protected speech and other expressive activity as well as the right of association,” Piersol wrote in his order. The American Civil Liberties Union of South Dakota filed the lawsuit on behalf of four groups and two individuals. ACLU attorney Stephen Pevar said they’re “thrilled” by Piersol’s injunction. “What it means for everybody is that they can speak their minds about the pipeline without fear of going to prison,” Pevar said. “This has never been about breaking the law. Our clients simply want to engage in peaceful protest, but under these statutes, they can’t do that without fear of punishment. The statutes just go too far.”

Federal agency resists paying North Dakota oil protest cost (AP) – The federal government is contesting North Dakota’s claims that the state should be reimbursed for the $38 million the state spent policing prolonged protests against the Dakota Access oil pipeline. The Army Corps of Engineers filed a motion Tuesday asking a federal judge to dismiss the state’s lawsuit seeking to recoup the costs, arguing it has “limited authority to enforce its rules and regulations” on land it manages. “The federal government acquired the Corps-managed land … without accepting any special criminal jurisdiction over this property,” the agency said in court documents. “Thus, North Dakota has the authority and responsibility to enforce criminal law on the Corps-managed lands…” North Dakota Attorney General Wayne Stenejem called the Corps’ claim that it is “toothless” in enforcing law on its land “preposterous.” Stenehjem filed the claim in Bismarck federal court in July after the agency ignored an administrative claim he filed a year earlier. Thousands of opponents of the $3.8 billion pipeline that’s been moving oil from the Dakotas through Iowa to Illinois for more two years gathered in southern North Dakota in 2016 and early 2017, camping on federal land and often clashing with police, resulting in 761 arrests over six months. The Standing Rock Sioux Tribe opposed the pipeline built by Texas-based Energy Transfer Partners over fears it would harm cultural sites and the tribe’s Missouri River water supply – claims rejected by the company and the state. Stenehjem has said the Corps “allowed and sometimes encouraged” protesters to illegally camp without a federal permit. The Corps has said protesters weren’t evicted due to free speech reasons. The agency said in court papers it used discretion, calling the federal government’s relationship with the Indian tribes “contentious and tragic.” The Corps said its “enforcement decisions” occurred in the “context of this complex and contentious history.”

Oil spill near Santa Maria – Santa Barbara County firefighters responded to an oil spill near ERG Operating Company in Santa Maria on Friday. At 11:45 am the fire department was notified of the spill on Bell Lease at 7320 Palmer Road. Crews responded to scene and confirmed 330 barrels of produced water with 4-5 barrels of oil had leaked. The spill was contained to the pad area and was not affecting any waterways. Oil and gas specialists are on the scene investigating the leak and initiating the cleanup.

US oil and gas rig count posts first weekly gain in nearly two months, up 5 to 954: Enverus – The US oil and gas rig count posted its first weekly gain in nearly two months, rising by 5 to a total 954, during a week of higher domestic oil prices, albeit from a geopolitical event on the other side of the world, Enverus/DrillingInfo data showed on Thursday. The last time the US rig count rose was the week of July 24, when the number of active rigs in domestic fields was up by 10 to 1,049. In the past 10 months, the rig count has dropped by more than 275 rigs from the recent peak of 1,233 in mid-November 2018. Rigs chasing oil increased by 8 to 763, while rigs drilling for natural gas dropped 3 to 186, according to the data for the week ended September 18. Generally, the rig count increase is likely “noise,” “the general trend is down, and I think it ties nicely with [industry’s] capital discipline and conservative drilling story.” “I imagine we will see more of the same the rest of the year,” he added. “I wouldn’t be surprised by further declines, but I think it is more likely to see flat drilling activity.” Basin wise, changes in activity were generally slight or neutral in the eight named large plays. The largest movements were a three-rig loss in the Denver-Julesburg Basin in Colorado, which was down three rigs, leaving 24, and a two-rig gain to 79 in the Eagle Ford Shale of South Texas. Other than that, three basins gained one rig each — the Permian Basin in West Texas/New Mexico, up to 415; the Haynesville Shale in Northwest Louisiana/ East Texas, up to 53; and the Dry Marcellus Shale mostly in Pennsylvania, up to 28. Three other basins remained the same — the Williston Basin, in North Dakota/Montana, at 58; the Wet Marcellus, also in Pennsylvania, at 19; and the Utica Shale mostly in Ohio, steady at 15. And the SCOOP-STACK of Oklahoma lost a rig, leaving 61. Approved US oil and gas permits also were down this week by 72 to a total of 754 permits. The largest change in a named play came from the DJ Basin, up 84 to 110 permits. The Permian gained 25 for a total of 150, the Dry Marcellus was down 25 to two, and the Eagle Ford lost 22, leaving 52. All other basins were up or down fewer than 10 permits from last week. According to Platts data, WTI prices this week averaged $58.06/b, up $1.29, while WTI Midland prices averaged $58.01/b, up $1.31. The Bakken Composite price was $51/b even, up $1.35. Natural gas prices were slightly up too. Henry Hub prices averaged $2.66/MMBtu this past week, up 11 cents, while Dominion South price averaged $2.03/MMBtu, up 9 cents.

U.S. shale oil output to rise to record 8.8 mln bpd in Oct -EIA – (Reuters) – U.S. oil output from seven major shale formations is expected to rise by 74,000 barrels per day (bpd) in October to a record high 8.843 million bpd, the U.S. Energy Information Administration said in its monthly drilling productivity report on Monday. The largest change is expected in the Permian Basin of Texas and New Mexico, where output is seen climbing around 71,000 bpd to a record high 4.485 million bpd in October. That would be the ninth consecutive month of increases in the basin, its longest streak since December 2018. Output in North Dakota and Montana’s Bakken region is expected to edge higher by about 2,000 bpd to a record 1.471 million bpd, the data showed, representing the smallest increase in the basin since May. Even though the number of rigs drilling new wells in both the Permian and Bakken has declined since the start of the year, output has increased in both basins because the productivity of those rigs – the amount of oil new wells produce per rig – has increased to record levels. Production increases in the Permian and Bakken have been at the forefront of a shale boom that helped make the United States the biggest oil producer in the world, ahead of Saudi Arabia and Russia. Separately, U.S. natural gas output was projected to increase to a record 82.4 billion cubic feet per day (bcfd) in October. That would be up almost 0.5 bcfd over the September forecast, putting production from the big shale basins up for a ninth month in a row even though the number of rigs in each region has declined since the start of the year. Again that is because rig productivity – the amount of gas new wells produce per rig – was up in every region since the start of the year. Output in the Appalachia region, the biggest U.S. shale gas formation, was set to rise about 0.2 bcfd to a record 32.8 bcfd. The EIA said producers drilled 1,247 wells and completed 1,389 in the biggest shale basins in August, leaving total drilled but uncompleted (DUC) wells down 142 at 7,950, their lowest since November 2018. That was the biggest monthly decline in DUCs since they fell by a record 144 in August 2016, according to data going back to December 2013.

Short-Term Energy Outlook – U.S. Energy Information Administration (EIA):

• EIA forecasts Brent spot prices will average $60/b in the fourth quarter of 2019 and $62/b in 2020. EIA forecasts that West Texas Intermediate (WTI) prices will average $5.50/b less than Brent prices in 2020.
• EIA forecasts that global liquid fuels consumption will increase by 0.9 million barrels per day (b/d) in 2019, down from year-over-year growth of 1.3 million b/d in 2018. The slowing liquid fuels demand growth reflects EIA’s assumption (based on forecasts from Oxford Economics) of decelerating growth in global oil-weighted gross domestic product (GDP). EIA expects that global liquid fuels demand will increase by 1.4 million b/d in 2020 as a result of an expected increase in global GDP growth.
• EIA forecasts U.S. crude oil production will average 12.2 million b/d in 2019, up by 1.2 million from the 2018 level. Forecast crude oil production then rises by 1.0 million b/d in 2020 to an annual average of 13.2 million b/d. The slowing rate of crude oil production growth reflects relatively flat crude oil price levels and slowing growth in well-level productivity.
• The Henry Hub natural gas spot price averaged $2.22 per million British thermal units (MMBtu) in August, down 15 cents/MMBtu from July. This summer, prices have declined amid rising natural gas production, despite high levels of both natural gas exports and consumption in the electricity generation sector. Based on recent price movements and EIA’s assessment that natural gas production will be sufficient to meet expected demand and export levels at a lower price than previously forecasted, EIA lowered its Henry Hub spot price forecast for 2020 to an average of $2.55/MMBtu, 20 cents/MMBtu lower than the August forecast.
• EIA forecasts that U.S. dry natural gas production will average 91.4 billion cubic feet per day (Bcf/d) in 2019, up 8.0 Bcf/d from 2018. EIA expects monthly average natural gas production to grow in late 2019 and then decline slightly during the first quarter of 2020 as the lagged effect of low prices in the second half of 2019 reduces natural gas-directed drilling. However, EIA forecasts that growth will resume in the second quarter of 2020, and natural gas production in 2020 will average 93.2 Bcf/d.
• Natural gas storage injections have outpaced the five-year (2014 – 18) average so far during the 2019 injection season as a result of rising natural gas production. At the beginning of April, the natural gas inventory injection season started with working inventories 28% lower than the five-year average for the same period. By the week ending August 30, working gas inventories were 82 billion cubic feet (Bcf), or 3%, lower than the five-year average of 3,023 Bcf. EIA forecaststhat natural gas storage levels will be 3,769 Bcf by the end of October, which is slightly higher than the fiveyear average and 16% higher than October 2018 levels.

OIL AND GAS: Is U.S. shale facing an ‘unmitigated disaster’? — The booming shale industry could be headed off a financial cliff, experts say, and environmental groups are asking who will clean up thousands of wells drilled miles beneath the surface if businesses go bust.

Report: Cleanup of abandoned oil, gas wells could cost US (AP) – U.S. taxpayers could face potentially hundreds of millions of dollars in cleanup costs from abandoned oil and gas wells on public lands, a government watchdog agency said Wednesday. The Government Accountability Office said in a report that it identified almost 2,300 wells that have not produced oil and gas since 2008 and have not been reclaimed. The report said bankruptcies by well operators could saddle the government with $46 million to $333 million in reclamation liabilities. The wide range reflects the unknown costs of cleaning up the sites. To avoid such a scenario, GAO recommended officials adjust the amount of bonds companies must post before drilling to better reflect possible cleanup costs. Current rules allow companies to post bonds of $150,000 to cover their wells nationwide. Abandoned wells have been a major issue across much of the West including Wyoming, where companies abandoned almost 6,000 oil and gas wells since 2014 amid low natural gas prices that led to a bust in the coal-bed methane industry. The state has plugged and abandoned over 2,200 wells at a cost of $5,000-$7,000 per well, according to the Wyoming Oil and Gas Conservation Commission. U.S. Rep. Raul Grijalva of Arizona, who had requested that GAO investigate oil and gas bonding practices, said the results underscore the need for an overhaul of federal bonding rules. “Much to the pleasure of the oil and gas industry, bond amounts have been ignored for decades, resulting in levels today that are woefully inadequate,” said Grijalva, who chairs the House Natural Resources Committee.

Trump administration opens huge reserve in Alaska to drilling – The Trump administration on Thursday said it would seek to open up the entire coastal plain of the Arctic National Wildlife Refuge to oil and gas exploration, picking the most aggressive development option for an area long closed to drilling. In filing a final environmental impact statement, the Interior Department’s Bureau of Land Management (BLM) took a key step closer to holding an oil and gas lease sale for the nearly 1.6 million-acre coastal plain, which is part of the 19.3 million-acre ANWR. The administration said its preferred plan would call for the construction of as many as four places for airstrips and well pads, 175 miles of roads, vertical supports for pipelines, a seawater-treatment plant and a barge landing and storage site. The refuge – home to polar bears, wolves, migratory birds and the Porcupine caribou herd – has long been closed off to oil and gas exploration despite long-standing interest among members of the petroleum industry. Climate change has made the area more delicate as melting ice has driven threatened polar bears to spend more time in dens along the refuge’s coastal plain.President Trump is dismissive of climate change, but the BLM conceded that it is having distinct effects on wildlife in the region. Although the report says there might be “positive effects on some species,” such as geese, eiders, loons and swans, it also says there could possibly be “catastrophic consequences” for birds as well as the extinction of 69 of the 157 bird species on the coastal plain over an 85-year period, according to an earlier report by Energy and Environment News. The BLM also said certain species, such as the Beringia bearded seal, which is not considered threatened, would go extinct by 2095 as a result of climate change. Bearded seals depend heavily on sea ice.

McDermott JV Bags Arctic LNG-2 Deal — Natural Gas World US engineering group McDermott International’s joint venture with China Shipbuilding Industry Corp. (CSIC) has secured a contract for three complex modules at the Arctic LNG-2 project in the Russian Arctic.Qingdao McDermott Wuchuan Offshore Engineering (QMW) has been hired to fabricate three pre-assembled units complex process modules, McDermott said in a notice on September 17. The scope of the work includes fabrication engineering, partial procurement, construction and pre-commissioning. Fabrication is slated to start at the end of this year and be completed in mid-2022.McDermott said the contract was “large”, placing its share of the value at somewhere between $50mn and $250mn. The Arctic LNG-2 project will establish a LNG liquefaction terminal on the Gydan Peninsula with an export capacity of 19.8mn mt/yr. Russia’s Novatek, France’s Total, China’s CNPC and Cnooc and Japan’s Mitsui and Jogmec, took a final investment decision(FID) on the project earlier this month. Its three trains are due online in 2023, 2024 and 2026 respectively.

Low Alberta gas storage is not spooking the AECO winter market, yet. – Alberta natural gas storage, one of the largest regional storage hubs in North America, is experiencing one of its slowest cumulative storage injection rates in years and could be headed to a 13-year low for storage levels by the end of the current injection season. That may seem ominous for the chilly Alberta and Canadian winter heating season, not to mention gas exports to the U.S. So far, though, winter gas forward prices for the Western Canadian gas price benchmark of AECO have registered a relatively modest market response, staying in line with last winter’s average spot price. Today, we take a closer look at the market’s apparent lack of concern over low Alberta gas storage. Canadian natural gas storage is not often a topic in the RBN blogosphere, but with Alberta – the province with more gas storage capacity than any other – showing remarkably low storage levels for late summer, and the U.S. still a steady gas taker of Western Canadian gas during the winter, the storage deficit there is likely to factor into how the North American gas market balances this winter. Alberta’s gas storage capacity is estimated at 499 Bcf by the Alberta Energy Regulator (AER) and easily dwarfs that of any other province in Canada. The next-closest competitor would be Ontario at 279 Bcf of storage capacity. Among the U.S. states, Alberta’s storage capacity would rank third, behind only Michigan (686 Bcf) and Texas (549 Bcf), based on capacity data compiled by the U.S. Energy Information Administration (EIA). On that basis, it’s safe to say that Alberta is a major player in the North American gas storage business.

Saudi Disruption Makes Canada’s Largest Refinery Vulnerable — Canada may hold the world’s third-largest crude reserves, but that’s little help to its largest refinery after a weekend attack disrupted production in Saudi Arabia, its biggest oil supplier. Nearly all of the kingdom’s oil shipments to Canada travel to New Brunswick, home to a single refinery, Irving Oil Ltd.’s Saint John plant, which can process about 299,000 barrels a day. The refinery relied on Saudi crude for more than 40 percent of its supplies in July, Statistics Canada data show. A drone attack Saturday on Saudi Arabia’s biggest crude-processing plant knocked out about half the country’s output. Saudi Aramco faces weeks or months before the majority of supply from its Abqaiq plant is restored, according to people familiar with matter. A longer-term outage is especially problematic for Irving’s plant, which relies mostly on imports. The bulk of Canada’s reserves are located in the oil-sands region of Northern Alberta, in the west of the country. Most of that oil is exported to the U.S. and while some can be shipped to eastern Canada on Enbridge Inc.’s Line 9, the pipeline only serves refineries as far east as Montreal. Now, Irving may have to pay up for its crude. “It’s more likely to play out on a price effect, rather than physical shortage” of oil, Kevin Birn, IHS Markit’s director of North American crude oil markets, said by telephone.

Mexico’s Growing Reliance on US Oil Will Continue – Proven oil reserves in Mexico have collapsed from 50 billion barrels 20 years ago to just 8 billion barrels today. It has been a long and winding road for Mexico’s oil industry over the past 15 years. With the peaking of supergiant Cantarell, once the world’s second largest oil field, Mexico’s crude production has been sliced in half to below 2 million b/d. Proven oil reserves have collapsed from 50 billion barrels 20 years ago to just 8 billion barrels today. Mexico’s crude oil exports to primary customer, the U.S., have been plummeting. From 2006-2018, shipments to the U.S. fell 60 percent to 720,000 b/d. After lengthy delays, Mexico in 2013 critically passed its Energy Reform to bring in outside investment and expertise to help production rebound. It remains a bumpy ride, however, and the new Andrés Manuel López Obrador (AMLO) administration has been resistant to deregulation. In turn, Mexico has been increasingly forced to deepen its dependence on the U.S. to meet oil demand at home. Falling production has been exacerbated by a refinery shortage, surging imports of refined products. In 2018, Mexico imported 1.2 million b/d of products from the U.S., or six times more than its intake before peak oil production. The country last year imported 520,000 b/d of gasoline from the U.S., nearly a five-fold boom over the past decade. This does help justify AMLO’s primary goal to not just grow crude output but to also build more refineries. The hope is to finally reverse the very expensive habit of shipping crude to the U.S. only to have to import it as refined product. The problem though is that refineries can cost at least $8 billion. With state-owned Pemex as a seriously indebted energy company, (over $105 billion), its ailing finances are the biggest threat to the Mexican economy. Many in the investment community have advised Mexico to not build the refineries. It remains a chronic problem: Pemex’s profits continually get siphoned off by the government instead of being re-invested. Like those in OPEC, this is a nation that simply depends too much on oil sales. Although down from 45 percent a decade ago, oil still accounts for 20-25 percent of the federal budget. Looking forward, Pemex faces serious obstacles now that AMLO has signaled a return to the resource nationalism that long hampered growth. Blocking an industry rebound, he has claimed no more fracking and no more risk contracts for foreign partners. He could waver because such anti-production policies will have a predictable result: more reliance on the U.S. Mexico should be aware, however, that the U.S. is the fastest growing oil exporter in the world. Many high-paying customers want growing amounts of the light tight oil flowing from America’s shale fields. In fact, the IMO 2020 sulfur rule combined with a trade deal with China could make the U.S. the largest oil exporter within the next five years.

StateImpact Pennsylvania’s Reid Frazier: Why I’m following Pa.’s Marcellus shale gas to Scotland – Zoe Shipton is a geologist and head of civil and environmental engineering at the University of Strathclyde. She’s been around the world to study rocks of varying shapes and sizes. When I showed up one late afternoon, she pulled out her favorite, a granite-based hunk from California’s Sierra Nevada. It was a pseudotachylite – a rock with a white base pocked with dark clumps. She said it was, essentially, a “fossilized earthquake” – the dark parts are the remnants of rocks that were melted during a seismic episode 15 kilometers below the earth’s surface. Shipton has paid close attention to the issue of oil and gas in the British isles. In 2011, she was on a panel of the British Geological Survey to study the question of fracking in the UK. She said one reason why shale gas from Pennsylvania is being shipped to Scotland has to do with what is going on with fracking in Great Britain.For decades, the United Kingdom has relied on oil and gas from the North Sea. Those fields, first developed in the 1960s and 70s, are declining. Grangemouth, the largest refinery in Scotland, is fed by a pipeline from those fields. Shipton says INEOS has been looking for a closer domestic supply, and it’s pushed for fracking in Great Britain. But some of the first exploratory wells in the North of England caused earthquakes, and the fracking effort slowed.The Scottish parliament has put in place a moratorium on fracking, and public sentiment in the UK is generally lukewarm to the process.If fracking were to ever advance in the UK, Shipton said it’s an open question as to how much gas there is in British shale. That’s partially because there are many faults in Britain’s geology, making geological prediction harder. Some of those faults are related to the pulling apart of the European and American continents. Millions of years ago, they were stuck together, but have been moving apart ever since. “So we’ve got a bit of Maine stuck on to Scotland,” she said. “Basically anything north of Glasgow kind of is American. But we nicked it off you millions of years ago.”

Global Gas Flaring Value Surpasses $16B – — The value of natural gas flaring across the world has seen a substantial increase to hit a global peak of $16.4 billion this year, according to Scottish data analytics firm Brainnwave. The firm said this is due to the rising price of natural gas and the increased volume of gas flared. Brainnwave’s analysis saw the value of natural gas flared by 80 different nations increased by 11 percent. Further, the volume of natural gas lost due to flaring increased by just over three percent, from 140.5 billion cubic meters in 2017 to 145 billion cubic meters in 2018.“Gas flaring is a major environmental issue, but it is also a commercial one,” said Brainnwave CEO Steve Coates. “Oil producers often lack the infrastructure to export natural gas from their wells and face few alternatives but to flare it in order to reach oil.”The most wasteful nations in 2018, Brainnwave contends, are Russia, Iraq, Iran and the U.S. – altogether flaring more than 70 billion cubic meters of natural gas. The firm said this is enough to heat 38 million homes for one year and is also more gas flared than the next 30 most wasteful nations combined.Recent analysis from Rystad showed that natural gas flaring in the Permian dropped in the first quarter of 2019 – its first drop since 2017.“Some of our customers are now using our data intelligence platform to find opportunities to provide commercial solutions, including those that convert otherwise-flared gas into power without it even leaving the site,” said Coates. “There are commercially viable solutions to gas flaring – but they rely on the technology being available and the financial incentives to make sense.” Brainnwave said it pinpointed gas flaring events around the globe using nighttime satellite imagery from visible infrared radiometer data that was used to measure the volume of gas flared. The firm then used the mean Henry Hub spot price for natural gas in U.S. dollars to estimate its value.

India Poised to Become a Huge Market for US Gas-— Indian Prime Minister Narendra Modi’s imminent visit to the U.S. energy capital is fueling speculation the second most-populous nation will further tap America’s shale gas bonanza. Modi is scheduled to address upwards of 50,000 people at a sold-out event at Houston’s NRG Stadium on Sept. 22 that’s billed by organizers as the largest-ever turnout for a foreign elected leader on U.S. soil. Energy investors, however, are keenly focused on what happens behind the scenes. A long-running trade war between Washington and Beijing has meant China hasn’t imported any American supply since February. The dispute has also put plans for new export terminals at risk. By contrast, India is open to making purchases, and the nation is already the sixth-largest buyer of U.S. liquefied natural gas. India “has the potential to become an enormous market” for U.S. gas, said Charlie Riedl, executive director of the Center for Liquefied Natural Gas. “Based on the broader aspiration to move people out of energy poverty and to enhance manufacturing, this all points to emerging opportunities.” The three-hour gathering — branded as “Howdy Modi!” — at the home of the National Football League’s Houston Texans is scheduled to include a “cultural program” that will be followed by an address by the Indian leader, according to event organizers. The event comes just weeks after Modi sat with Russia’s Vladimir Putin to explore shipping Arctic natural gas to the subcontinent. Heightening expectations is the timing of Modi’s Texas pilgrimage: it will come only a few days after Gastech, one of the world’s premier methane-industry confabs. Still, India has been slower than some other economies to divorce itself from coal, and that may be a hindrance to gas-import arrangements, said Madeline Jowdy, an analyst at S&P Global Platts. “I am so skeptical of India,” Jowdy said. “’I’m not saying that Indian companies can’t and won’t invest” in gas imports, but coal is entrenched and supports a lot of jobs.

Oil spilling into the Java Sea – In mid-July, one of three oil wells owned by the Indonesian state-owned oil and gas company, PT Pertamina, under an offshore platform in the North West Java (ONWJ) Offshore Block began leaking into the sea north of Karawang City, West Java. By mid-August, the company had deployed 44 vessels to work at containing the spill as oil slicked to the surface along with bubbles of gas. Nevertheless, at least seven beaches in West Java and several villages were affected by the spill lapping ashore. Crude oil reached as far as the seven islands at Pulau Seribu in Jakarta, about 60 km west of the facility. Beaches popular with tourists closed and the hauls of fishermen declined in the polluted area. Every day for weeks after the spill, hundreds of people were mobilized to clean up the beaches. Wearing protective clothing, including masks and gloves, their work started early to beat the heat of the rising sun. PT Pertamina promised to handle the leak off the Karawang coast, hiring a U.S.-based well control company – Boots & Coots – to assist. Boots & Coots handled the infamous 2010 Deepwater Horizon oil spill in the Gulf of Mexico. PT Pertamina aims to fix the well by late September.

Oil spill spanning 800 metre detected along Mersing waters – An oil spill has been detected along an area spanning 800 metres in the Mersing waters, affecting nearby areas such as Pulau Rawa and Pulau Besar, here. Johor Local Government, Urban Wellbeing and Environment Committee chairman Tan Chen Choon said the case was reported by local residents on September 15. “The cause of the spill is still being investigated as the Marine Department reported that there has been no report on vessel accidents or detention. “Initial investigation found that vessels passing through the international waters could potentially be the source of the oil spill,” he said in a statement today. Related agencies have been mobilised to contain the spill, with the marine department and the Malaysian Maritime Enforcement Agency (MMEA) increasing monitoring activities and the Mersing district office activating its beach cleaning action plan. “Monitoring was also done together with the Johor Marine Park Department yesterday but no further spill was detected, possibly due to other elements such as strong waves, high wind and the haze,” he said. Tan also expressed his gratitude to the local residents for reporting the incident to the Department of Environment and for coming forward to help with cleaning activities at the beach.

ExxonMobil Hits More Oil Pay Offshore Guyana – Exxon Mobil Corp. reported Monday that it has made another oil discovery on the Stabroek Block offshore Guyana at the Tripletail-1 well in the Turbot area, adding to Stabroek’s previously announced estimated recoverable resource exceeding 6 billion oil-equivalent barrels. “This discovery helps to further inform the development of the Turbot area,” Mike Cousins, ExxonMobil’s senior vice president of exploration and new ventures, said in a written statement emailed to Rigzone. According to ExxonMobil, Tripletail-1 – drilled in 6,572 feet (2,003 meters) of water by the Noble Tom Madden drillship – encountered approximately 108 feet (33 meters) of a high-quality oil-bearing sandstone reservoir. After the drillship completes operations at Tripletail, which is located roughly three miles (five kilometers) northeast of the Longtail discovery, it will drill the Uaru-1 well roughly six miles (10 kilometers) east of the Liza field, the supermajor added. ExxonMobil affiliate Esso Exploration and Production Guyana Limited operates Stabroek and owns a 45-percent stake in the block. Hess Guyana Exploration Ltd. and CNOOC Petroleum Guyana Limited own 30-percent and 25-percent interests, respectively. “Tripletail is the 14th discovery on the Stabroek Block and further underpins the Turbot area as a major development hub,” Hess CEO John Hess said in a separate written statement. “The discovery adds to the previously announced gross discovered recoverable resource estimate of more than 6 billion barrels of oil equivalent on the Stabroek Block, with multibillion future barrels of future exploration potential remaining.”

Exxon Again Looks to Sell Australia Assets— Exxon Mobil Corp. is again trying to sell its oil and gas operations in southeast Australia as part of a move to shed assets and boost shareholder returns. The U.S. supermajor “will be testing market interest” for global assets, including what it operates in Australia, the company said in an emailed statement. No buyers have been identified and no agreements have been reached, it added. “Exxon Mobil continually reviews its assets for their contribution toward meeting the company’s operating needs, financial objectives and their potential value to others,” it said in the statement. It’s the second effort in about three years to sell Australian operations, which include the long-producing Gippsland Basin project offshore Victoria state. Exxon and its joint venture partner BHP Group abandoned a 20-month sale process for the assets in February 2018. The world’s biggest oil company by market value is pursuing a $15 billion divestment plan, offloading older assets to fund higher-growth projects from Papua New Guinea to Texas and Brazil. It confirmed earlier this month it’s in exclusive talks to sell Norwegian oil and gas operations, a deal reported to be worth as much as $4.5 billion. The company is also negotiating with Spain’s Repsol SA to sell deepwater assets in the Gulf of Mexico, where it said last year it was “testing market interest.” Big IssuePotential buyers “will have to get comfortable with the age of the assets, declining production and significant decommissioning liabilities,” said Angus Rodger, a research director at Wood Mackenzie Ltd. “The fact that a previous effort to offload the Gippsland oil assets failed due to uncertainty over abandonment costs highlights how big an issue it will be.” The Australian newspaper reported in June that Exxon’s 50% stake in the assets, which include the Longford Gas Plant, could be worth about $3 billion.

U.S. And Russia Battle It Out Over This Huge Iraqi Gas Field – With the U.S, Russia, and China all jostling for position in Iraq’s oil and gas industry both north and south, Iraq’s oil ministry last week reiterated its desire to have one or more foreign partners in the Mansuriya gas field. Situated in Diyala province, close to the Iran border, Mansuriya is estimated to hold around 4.6 trillion cubic feet of natural gas, with plateau production projected at about 325 million standard cubic feet per day. For the U.S., encouraging Iraq to optimise its gas flows so that it reduces its dependency for power from Iran is the key consideration. For Russia, Rosneft essentially bought control of the semi-autonomous region of Kurdistan in northern Iraq in November 2017, so power in southern Iraq figuratively will complete the set. Securing oil and gas contracts across all of Iraq will allow Russia to establish an unassailable political sway across the entire Shia crescent of power in the Middle East, stretching from Syria through Lebanon (by dint of Iran), Jordan, Iraq (also helped by Iran), Iran itself, and Yemen (via Iran). From this base, it can effectively challenge the U.S.’s vital oil, gas, and political ally in the region – Saudi Arabia. China, in the meantime, is operating to its own agenda in South Pars Phase 11 and its West Karoun holdings. Iraq, like Turkey, is still – nominally at least – not committing to either the Russia or the U.S., preferring to play each off against the other for whatever they can get, and the same applies in microcosm to the field of Mansuriya. Turkey itself was a key player in this gas field through its national oil company Turkiye Petrolleri Anonim Ortakligi (TPAO) until the middle of last year – holding a 37.5 per cent stake – along with the Oil Exploration Company (25 per cent), Kuwait Energy (22.5 per cent), and South Korea’s KOGAS (15 per cent). TPAO had signed the original development deal for Mansuriya back in 2011, promising Iraq’s oil ministry that it could be trusted to reach plateau production within 10 years at most, a senior figure in the ministry told OilPrice.com last week. This was not an unreasonable schedule, for which TPAO would be remunerated US$7.00-7.50 per barrel of oil equivalent, a relatively generous amount compared to many of the previous awards from the ministry. TPAO agreed that the first phase would mean production of at least 100 million cubic feet a day within 12 months from the signing date. As it stands, Iraq’s oil ministry has made it clear that it needs Mansuriya to be properly up and running and gradually increasing production towards the 325 million standard cubic feet per day figure so that it can be used as a feedstock for the country’s calamitous power sector. Peak summer power demand every year exceeds domestic generation capacity, frequently leading to up to 20 hours per day of blackouts in many areas. Without Mansuriya and similar gas fields coming online, this will get worse, as Iraq’s population is growing at a rate of over one million per year, with electricity demand set to double by 2030, according to the International Energy Agency.

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