Oil, Gas, And Fracking News Reads: 04November, 2018 – Part 1

Written by rjs, MarketWatch 666

Here are some selected new articles from the week ended 04 November 2018.

This article is a feature every Monday evening on GEI.

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Oil prices see largest drop in 9 months on demand concerns, glut fears; US oil production at a record high

Oil prices were down every day the past week in the largest weekly price drop since early February, and ended more than 17% below the 4 year high they set just one month ago…after falling 2.4% to $67.59 a barrel in a global market selloff last week, prices for US oil contracts for December delivery fell 55 cents to $67.04 a barrel on Monday, as Russia signaled its oil output would remain high and concerns over the global trade slowdown deepened…oil prices then fell more than 1% on Tuesday, on rising global oil output and on concern that global economic growth and demand for fuel would fall due to the U.S.-China trade war, closing down 86 cents at $66.18 a barrel…Wednesday saw another 87 cent drop to $65.31 a barrel, as further signs of rising global supply emerged with US and Russian output hitting records, as oil prices finished October with their largest monthly drop in more than 2 years…US crude prices then tumbled $1.62, or 2.5%, to a 7-month low of $63.69 a barrel, as surging output from the US, Russia, and OPEC was met by slowing demand from emerging market economies hit by the US-China trade war…oil prices fell almost another percent again on Friday, closing at $63.14 a barrel, after the US said it would temporarily allow eight allies to buy crude from Iran, alleviating fears of a sanction-related supply crunch… the December US oil contract thus registered a weekly drop of 6.6%, as US oil prices suffered their fourth straight weekly loss, while the contract for January Brent, the international benchmark, settled at $72.83 a barrel with a loss of 6.2% for the week..

On the other hand, natural gas prices for December rose 5.9 cents to $3.284 per mmBTU this week, whipsawed midweek by changing 8 to 14 day forecasts from the Climate Prediction Center, and boosted on Friday by the report of a smaller than expected injection of natural gas into storage…this week’s natural gas storage report from the EIA for the week ending October 26th indicated that natural gas in storage in the US rose by 48 billion cubic feet to 3,143 billion cubic feet during that week, which left our gas supplies 623 billion cubic feet, or 16.5% below the 3,766 billion cubic feet that were in storage on October 27th of last year, and 638 billion cubic feet, or 16.9% below the five-year average of 3,781 billion cubic feet of natural gas that are typically in storage after the fourth week of October….this week’s 48 billion cubic feet increase in natural gas supplies was below expectations of an inventory increase in the 51 to 53 billion cubic foot range, and was also below the average of 62 billion cubic feet of natural gas that have been added to storage during the fourth week of October in recent years, the 13th average or below average inventory increase over the past seventeen weeks…natural gas storage facilities in the Midwest saw a 22 billion cubic feet increase over the week, which reduced their supply deficit to 11.6% below normal, but natural gas supplies in the East only increased by 1 billion cubic feet and saw their supplies deficit rise to 9.5% below normal for this time of year…on the other hand, the South Central region saw a 26 billion cubic feet increase in their supplies, as their natural gas storage deficit decreased to 24.9% below their five-year average for the 4th week in October…meanwhile, while the natural gas pipeline rupture in Canada has been repaired, flows south had not resumed as of this report; as a result, only 3 billion cubic feet were added to supplies in the Mountain region, where their deficit from normal fell to 17.4%, while there no change of gas in storage in the Pacific region, where the natural gas supply deficit rose to 24.9% below normal for this time of year….

The primary reason for this week’s much smaller than average addition to storage was the outbreak of cold weather in the populated eastern half of the country that we saw during the period; natural gas production continued at near record levels…this can be clearly seen in the map of weekly average temperature abnormalities below taken from the EIA’s natural gas storage dashboard:

Again, this map came from the EIA’s natural gas storage dashboard, an EIA website with dozens of interactive graphics tracking various facets and factors influencing US natural gas supplies, which is updated with the most recent data on Thursday of each week…the above map shows how much the temperatures in each geographical area of the 48 states varied from normal during the week ending October 25th, with those areas that were cooler than normal in a shade of blue, while those areas that were warmer than normal are shown in a shade of tan or brown….from the legend underneath this map, we can see that most of the eastern US saw temperatures below normal during the cited week, with a broad swath running from Texas northeast through Maine showing temperatures 5 to 9 degrees below normal…for the fourth week in October, below normal would mean that most of that area, probably with the exception of southern Texas, saw heating demand closer to what one would expect in early to mid November, and hence less natural gas than normal was left to be added to winter supplies…

However, temperatures have since moderated during the week through November 1st, which you can see if you go to the natural gas storage dashboard and run the daily animation that goes with that map…all three of those regions saw a mix of days both above and below normal, with average temperatures thus a few degrees warmer than they were during this reporting week…thus we’d expect that this coming week’s natural gas storage report will show additions of gas to storage much closer to the norm, likely in a range from 55 to 60 billion cubic feet…after that, the forecast is for temperatures to turn colder, so further additions will be minimal if at all..

The Latest US Oil Data from the EIA

This week’s US oil data from the US Energy Information Administration for the week ending October 26th indicated yet another addition to our commercial crude supplies for a sixth week in a row, despite a decrease in our oil imports, an increase in our oil exports, and a modest pickup in refining…our imports of crude oil fell by an average of 334,000 barrels per day to an average of 7,344,000 barrels per day, after rising an average of 63,000 barrels per day the prior week, while our exports of crude oil rose by an average of 352,000 barrels per day to an average of 2,485,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 4,859,000 barrels of per day during the week ending October 26th, 639,000 fewer barrels per day than the net of our imports minus exports during the prior week…over the same period, field production of crude oil from US wells was reportedly 300,000 barrels per day higher at 11,200,000 barrels per day, which means that our daily supply of oil from the net of our trade in oil and from wells totaled an average of 16,059,000 barrels per day during this reporting week…

Meanwhile, US oil refineries were using 16,417,000 barrels of crude per day during the week ending October 26th, 149,000 barrels per day more than the amount of oil they used during the prior week, while over the same period a net of 239,000 barrels of oil per day were reportedly being added to the oil that’s in storage in the US….hence, this week’s crude oil figures from the EIA would seem to indicate that our total working supply of oil from net imports and from oilfield production was 597,000 fewer barrels per day than what refineries reported they used during the week plus what oil was added to storage….to account for that disparity between the supply of oil and the consumption or new storage of it, the EIA inserted a (+597,000) 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 is labeled in their footnotes as “unaccounted for crude oil”…once again, with an “unaccounted for crude” figure that large, one or more of this week’s oil metrics must be off by a statistically significant amount (for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….

Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports slipped to an average of 7,509,000 barrels per day, now 2.5% less than the 7,699,000 barrel per day average that we were importing over the same four-week period last year….the net 239,000 barrel per day increase in our total crude inventories included a 460,000 barrel per day increase in our commercially available stocks of crude oil, which was partially offset by a 220,000 barrel per day decrease in the amount of oil in our Strategic Petroleum Reserve, likely because of a sale of 11 million barrels from those reserves to Exxon et al that closed eight weeks ago….this week’s crude oil production was reported up by 300,000 barrels per day to 11,200,000 barrels per day due to a rounded 300,000 barrels per day rebound to 10,700,000 barrels per day output from wells in the lower 48 states after Hurricane Michael, while a 15,000 barrels per day increase to 488,000 barrels per day in oil output from Alaska was not enough to impact the reported national total, which is now being rounded to the nearest 100,000 barrels per day….last year’s US crude oil production for the week ending October 27th was at 9,553,000 barrels per day, so this week’s rounded oil production figure was 17.2% above that of a year ago, and 32.9% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016…

While we report the preliminary US oil production estimates that are released weekly, the EIA also releases confirmed monthly oil production figures a few months later, after they have collected the accurate production reports that aren’t available on a weekly basis….since this week’s release of that monthly report shows a significant divergence from the weekly figures we’ve been reporting, we’ll include a graphic showing both, so we can see what that divergence looks like…

The above graph, from this week’s OilPrice Intelligence Report, shows the history of confirmed oil production data monthly from January 2016 to August 2018 in blue, and then the weekly estimates of US oil production up until the current week in yellow after that period, with both metrics in thousands of barrels per day….as we’ve pointed out on several previous occasions, the weekly oil data from the EIA that we cover each week is preliminary, and it is typically more than 2 months before the final confirmed figures, published monthly, are released…we follow the weekly data because it’s what the oil traders follow, and hence it moves oil prices and ultimately the decisions on the part of exploitation companies to start drilling for oil…however, the confirmed oil production figures for August were released this week and showed our crude production at a much higher than expected 11,346,000 barrels per day average during that month, up from 10,964,000 barrels per day in July…the weekly production estimates for August, on the other hand, had ranged from 10,800,000 barrels per day to 11,000,000 barrels per day, and thus averaged more than 400,000 barrels per day lower than the confirmed figures…if the reason for the inaccuracies in the weekly report persisted to the current week, and we have no reason to believe they haven’t, the 400,000 barrels per day error in the weekly oil production figures would go a long way toward explaining the large “unaccounted for crude” figures we’ve been seeing in recent weeks…

Meanwhile, this week’s report indicates that US oil refineries were operating at 89.4% of their capacity in using 16,417,000 barrels of crude per day during the week ending October 26th, up from 89.2% of capacity the prior week, a fairly normal utilization rate for during the fall refinery maintenance season….the 16,417,000 barrels per day of oil that were refined this week were once again at a seasonal high, for the 20th out of the past 22 weeks, 2.5% higher than the 16,015,000 barrels of crude per day that were processed during the week ending October 27th, 2017, when US refineries were operating at 88.1% of capacity…

With the increase in the amount of oil being refined this week, gasoline output from our refineries was also higher, increasing by 336,000 barrels per day to 10,364,000 barrels per day during the week ending October 26th, after our refineries’ gasoline output had decreased by 402,000 barrels per day during the week ending October 19th…with that rebound in our gasoline output, our gasoline production during the week was 1.7% higher than the 10,187,000 barrels of gasoline that were being produced daily during the same week last year…meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 23,000 barrels per day to 4,983,000 barrels per day, after that output had increased by 145,000 barrels per day the prior week….however, this week’s distillates production was still 1.1% lower than the 5,036,000 barrels of distillates per day that were being produced during the week ending October 27th 2017….

Even with the increase in our gasoline production, our supply of gasoline in storage at the end of the week fell by 3,161,000 barrels to 226,169,000 barrels by October 26th, the 21st decrease in the past 36 weeks, after our gasoline supplies had dropped by 4,826,000 barrels the prior week….our supplies fell even as the amount of gasoline supplied to US markets fell by 62,000 barrels per day to 9,262,000 barrels per day, and as our imports of gasoline rose by 32,000 barrels per day to 363,000 barrels per day, while our exports of gasoline rose by 43,000 barrels per day to 1,012,000 barrels per day…but even after two big decreases, our gasoline inventories are still at a seasonal high, 6.3% higher than last October 27th’s level of 212,849,000 barrels, and roughly 7.1% above the 10 year average of our gasoline supplies for this time of the year…

Meanwhile, even with our distillates production a bit higher higher, our supplies of distillate fuels also fell again, decreasing by 4,052,000 barrels to 126,322,000 barrels during the week ending October 26th, their sixth straight decrease after 8 straight weeks of increases, and the largest drop since March 9th…our distillates supplies fell by much more than last week’s decrease because the amount of distillates supplied to US markets, a proxy for our domestic demand, increased by 420,000 barrels per day to 4,426,000 barrels per day, while our exports of distillates fell by 163,000 barrels per day to 1,277,000 barrels per day, and while our imports of distillates fell by 22,000 barrels per day to 141,000 barrels per day….after this week’s decrease, our distillate supplies ended the week 2.0% below the 128,921,000 barrels that we had stored on October 27th, 2017, and remained roughly 6.7% below the 10 year average of distillates stocks for this time of the year…

Finally, despite higher oil exports, lower oil imports, and an increase in oil being refined, our commercial supplies of crude oil increased for the 6th week in a row and for the 22nd time in 2018, rising by 3,217,000 barrels during the week, from 422,787,000 barrels on October 19th to 426,004,000 barrels on October 26th to …that increase means that our crude oil inventories continue to be more than 2% above the five-year average of crude oil supplies for this time of year, and roughly 22.4% above the 10 year average of crude oil stocks for the last weekend in October, with the disparity between those figures arising because it wasn’t until early 2015 that our oil inventories first rose above 400 million barrels…however, since our crude oil inventories had been falling through most of the past year and a half until just recently, our oil supplies as of October 26th were still 6.4% below the 454,906,000 barrels of oil we had stored on October 27th of 2017, 11.7% below the 482,578,000 barrels of oil that we had in storage on October 28th of 2016, and 5.5% below the 450,841,000 barrels of oil we had in storage on October 30th of 2015…

This Week’s Rig Count

US drilling rig activity slowed for the second time in 6 weeks during the week ending November 2nd, but just by a bit….Baker Hughes reported that the total count of rotary rigs running in the US decreased by 1 rig to 1067 rigs over the week ending on Friday, which was still 169 more rigs than the 898 rigs that were in use as of the November 3rd report of 2017, but down from the shale era high of 1929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began their attempt to flood the global oil market…

The count of rigs drilling for oil decreased by 1 rig to 874 rigs this week, which was still 145 more oil rigs than were running a year ago, while it was well below the recent high of 1609 rigs that were drilling for oil on October 10, 2014…at the same time, the number of drilling rigs targeting natural gas formations remained unchanged at 193 rigs, which was still 24 more than the 169 natural gas rigs that were drilling a year ago, but way down from the modern high of 1,606 natural gas rigs that were deployed on August 29th, 2008…in addition, a year ago we had a rig categorized as “miscellaneous” deployed, while there are no such “miscellaneous” rigs drilling at this time this year…

Offshore drilling in the Gulf of Mexico was unchanged at 18 rigs this week, which was also unchanged from the 18 Gulf of Mexico rigs active a year ago…meanwhile, the only rig that had been drilling offshore from Alaska was shut down this week, so the total national offshore count is now down to 18 rigs, also the same as a year ago…

The count of active horizontal drilling rigs was up by 2 rigs to 929 horizontal rigs this week, which was also 165 more horizontal rigs than the 764 horizontal rigs that were in use in the US on November 3rd of last year, but down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014…meanwhile, the directional rig count was unchanged at 73 directional rigs this week, which is the same number of directional rigs that were in use during the same week of last year….on the other hand, the vertical rig count was down by 3 rigs to 65 vertical rigs this week, which was still up from the 61 vertical rigs that were operating on November 3rd of 2017…

The details on this week’s changes in drilling activity by state and by 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 producing states, and the second table 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 November 2nd, the second column shows the change in the number of working rigs between last week’s count (October 26th) and this week’s (November 2nd) count, the third column shows last week’s October 26th active rig count, the 4th column shows the change between the number of rigs running on Friday and those running on 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 on Friday the 3rd of November, 2017…

This week’s modest 2 rig decrease in the Permian masks significant other changes within its component basins; while just a single rig was shut down in Texas Oil District 8, which would correspond to the core Delaware basin, there were 4 rigs shut down in Texas Oil District 8A, which would correspond to the central platform and Midland Basins; at the same time, 2 rigs were added in Texas Oil District 7C, which could be Midland rigs or southern shelf, and another rig was added in Texas Oil District 7B, which could also be a Midland rig, or outside the basin altogether (Texas oil districts are political boundaries and hence don’t correspond directly with the geological basins underlying them)…based on that, our best guess, without digging through the individual well logs in the Rig Count Pivot Table (xls), is that Texas shed a net of 3 Permian rigs, while New Mexico picked one up….natural gas rigs, meanwhile, remained unchanged despite the loss of two in the Marcellus (one each in PA and WV) and the natural gas rig that was shut down in Oklahoma’s Arkoma Woodford because a natural gas rig was added to those working Ohio’s Utica, and two others were set up in basins not tracked separately by Baker Hughes…

DOE comments show little support for FirstEnergy bailout request – Most stakeholders weighing in on FirstEnergy Solutions Corp.’s plea in March for federal intervention to support its financially struggling coal-fired and nuclear power plants in the PJM Interconnection were opposed to the request, according to documents obtained from the U.S. Department of Energy.Out of 152 responses on the request the DOE received through May 24, the vast majority urged the department not to grant FirstEnergy Solutions’, or FES’s, application, according to documents S&P Global Market Intelligence received through a Freedom of Information Act request. The DOE has yet to announce a decision on the company’s petition or other agency efforts to prop up vulnerable coal and nuclear units.The DOE did not open a formal comment period on the request but said in April that it would accept stakeholder input on the agency’s ability to declare an emergency under FPA 202(c), including in response to the FES application. The DOE has invoked its 202(c) authority sparingly in the past, mostly in response to temporary energy shortfalls following hurricanes and other emergency events.As a result, several gas and power industry groups said the statute should not be used to provide the market relief FES sought in its 202(c) application. More fundamentally, most stakeholders backed PJM’s assertion that no grid emergency existed in the region to justify subsidizing FES’s at-risk plants. “The proposed actions would tilt the table and not only undermine, but potentially destroy, new private competitive investment, and perhaps more importantly, substantially add to the cost of power to consumers in the region,” independent power producer Calpine Corp. said in comments to the DOE.

U.S. OKs wider startup of Enbridge Ohio-Michigan NEXUS natgas pipe (Reuters) – U.S. energy regulators on Friday approved part of Canadian energy company Enbridge Inc’s request to put more of its $2.6 billion NEXUS natural gas pipeline from Ohio to Michigan into service. In a filing, the U.S. Federal Energy Regulatory Commission (FERC) said it approved the company’s request to put the Clyde compressor station in Sandusky County, Ohio, into service, but not the Wadsworth compressor in Medina County, Ohio. FERC said once NEXUS demonstrates restoration progress at Wadsworth, it would reconsider the company’s request to put that facility in service. Enbridge sought FERC permission to put both compressors into service on Oct. 19. NEXUS is one of several gas pipelines designed to connect growing output in the Marcellus and Utica shale basins in Pennsylvania, West Virginia and Ohio with customers in other parts of the United States and Canada. Earlier in October, FERC allowed Enbridge to put facilities into service that would enable NEXUS to transport about 0.97 billion cubic feet per day (bcfd). One billion cubic feet of gas is enough to fuel about 5 million homes for a day. Once the 255-mile (410-km) NEXUS project is fully in service, it will be able to carry up to 1.5 bcfd of gas from the Marcellus and Utica shale fields to the U.S. Midwest and Gulf Coast and Ontario in Canada. NEXUS is a partnership between Enbridge and Michigan energy company DTE Energy Inc. Separately, Enbridge said it put part of its $200 million Texas Eastern Appalachian Lease (TEAL) gas pipeline project into service earlier in October. TEAL is an expansion of Enbridge’s Texas Eastern system designed to deliver 0.95 bcfd to NEXUS. When it started construction of NEXUS in late 2017, Enbridge estimated it would be able to complete TEAL and NEXUS in the third quarter of 2018. Enbridge said it completed NEXUS in September when it asked FERC for permission to put part of the pipeline into service. New pipelines built to remove gas from Appalachia have enabled shale drillers there to boost output to an estimated record high of around 29.8 bcfd in November from 26.1 bcfd during the same month a year ago. That represents about 36 percent of the nation’s total dry gas output of 81.1 bcfd expected on average in 2018. The Appalachia region produced just 1.6 bcfd, or 3 percent of the country’s total production, in 2008.

Chesapeake completes $2B Utica asset sale; closes quarter with profit – The company that pioneered Utica Shale drilling in Ohio has completed the sale of its holdings in the state. Chesapeake Energy announced Tuesday morning during a conference call with investors it closed its $2 billion sale to Encino Acquisition Partners on Monday. EAP is a partnership between the Canada Pension Plan Investment Board and Encino Energy, a private oil and gas company based in Houston. When announcing the sale in July, the companies said the deal included 900,000 acres and approximately 900 wells, with related equipment and property. On Tuesday, Chesapeake said it was running two rigs in the Utica and placed 11 wells into production during the third quarter. The Oklahoma City-based company’s Utica wells averaged daily production of 10,000 barrels of oil, 488 million cubic feet of natural gas and 28,000 barrels of natural gas liquids during the quarter. Chesapeake’s earnings were originally scheduled for release Wednesday, but the company moved up the date to announce its nearly $4 billion deal to buy Houston-based WildHorse Resource Development, a company with operations in the Eagle Ford Shale and Austin Chalk formations in Texas. Chesapeake closed the quarter with a profit of $60 million or 7 cents per diluted share for common stockholders.

Eclipse Resources Encouraged By First Pennsylvania Utica Well – Eclipse Resources Corp. said Thursday that its first Utica Shale well in north-central Pennsylvania came online at 32 MMcf/d and has continued to perform at that rate for more than 30 days, exceeding the company’s expectations in an underdeveloped part of the play. “After initial cleanup, the well’s production quickly achieved our target rate of approximately 32 MMcf/d, which was expected to continue for an initial flat period of 30 days,” said CEO Benjamin Hulburt. “The well’s production continued at this level after reaching the 30-day period, which is encouraging to us and we will be continuing to monitor this well’s performance closely.”The Painter 2H is the latest Utica well to come online in Tioga County, hundreds of miles east of the Utica core in southeast Ohio. Eclipse brought the well online during the third quarter, nearly a year after it announced the 44,500 net acre acquisition of its Flat Castle area in Tioga and Potter counties. The well was completed with a lateral length of 13,800 feet.Hulburt also said the company’s all-stock merger with Blue Ridge Mountain Resources Inc. (BRMR) remains on track to close by the end of this year. BRMR would become an Eclipse subsidiary under the deal.Earlier this week, BRMR, which operates in southeast Ohio and northern West Virginia, updated full-year guidance and is now calling for 187-212 MMcfe/d of production. As a result, Eclipse said the combined company is forecast to produce 560-600 MMcfe/d of production in the fourth quarter instead of the previously forecast range of 500-560 MMcfe/d.During the third quarter, Eclipse produced 346.4 MMcfe/d, a decline from 353 MMcfe/d in the year-ago period, but up from 305.5 MMcfe/d in 2Q2018. The company cut spendingearlier this year and lowered its annual guidance as a result.The company reported record revenue of $130.1 million in the third quarter, a 42% increase from the year-ago quarter, as prices increased on more takeaway in the Appalachian Basin. Including cash settled derivatives and firm transportation, Eclipse earned $3.34/Mcfe during the period, compared to $2.59/Mcfe a year ago.Eclipse reported net income of $4 million (1 cent/share) for the third quarter, versus a net loss of $16.7 million (minus 6 cents) in 3Q2017.

Energy Transfer completes last segments of Rover natgas pipe in W Virginia – (Reuters) – U.S. pipeline company Energy Transfer LP said on Friday that federal energy regulators approved the company’s request to put the last two segments of its $4.2 billion Rover natural gas pipeline into service:

• * The U.S. Federal Energy Regulatory Commission (FERC) allowed Energy Transfer to put its Sherwood and CGT laterals in West Virginia into service.
• * Energy Transfer originally planned to complete Rover in November 2017, but since starting construction in March 2017, has been delayed by numerous notices of violation in Ohio and other states, some of which led to temporary stop work orders from state and federal regulators.
• * The 713-mile (1,148-kilometer) Rover is designed to carry up to 3.25 billion cubic feet per day (bcfd) of gas from Pennsylvania, West Virginia and Ohio to Michigan.
• * One billion cubic feet is enough gas to supply about five million U.S. homes for a day.
• * Rover has been entering service in phases since August 2017 as Energy Transfer completed each section.
• * Major producers signed up to use Rover include units of privately held Ascent Resources, Antero Resources Corp, Range Resources Corp, Southwestern Energy Co, Eclipse Resources Corp and EQT Corp.
• * Rover is one of several pipelines under construction this year to connect growing output from the Marcellus and Utica shale basins in Pennsylvania, West Virginia and Ohio to customers in other parts of the United States and Canada.
• * New pipelines built to remove gas from the Appalachia region will enable shale drillers there to boost output in to a projected record high of around 29.8 bcfd in November from 26.1 bcfd during the same month a year ago, according to federal energy data.
• * That represents about 36 percent of the nation’s total dry gas output of 81.1 bcfd expected on average in 2018. The Appalachia region produced just 1.6 bcfd, or 3 percent of the country’s total production, in 2008.

Appalachian producers boost natural gas output in Q3 – – Increased takeaway capacity combined with higher prices for natural gas liquids continues to drive gas production increases in the Northeastern US. “This quarter’s cash flow was more than 40% higher than the same period last year,” said Southwestern Energy CEO Bill Way during an earning’s call Friday morning. “Results benefited from our returns-focused growth of liquids as prices improved, from our leading low cost gas transportation portfolio as regional basis tightened and from operational achievements made by our leading operational team.” Northeast producers have been readying themselves to take advantage of incremental production takeaway capacity from pipeline projects that are now being placed in-service at long last. In tandem with Energy Transfer Partners’ Rover Pipeline and Williams’ Transco Atlantic Sunrise expansion placing facilities in-service over the past two months, large drawdowns in well inventory materialized in Ohio and Western Pennsylvania, while rig releases in Northeast Pennsylvania have also strengthened. Southwestern, which was the fourth-largest gas producer in the US during the second quarter, according to the Natural Gas Supple Association, increased its Appalachian production during the third quarter by 22%. Fellow Northeast producer Cabot Oil and Gas, which was the fifth-largest US gas producer during the second quarter, increased its average daily production during the third quarter by 10% to 2.02 Bcf/d on average, according to the company’s latest earning’s report released Friday. As a result of incremental pipeline takeaway capacity becoming available, forward basis pricing at the Dominion South supply hub has strengthened and could encourage continued production growth. Operators in the Northeast have long-awaited the full in-service of ETP’s Rover Pipeline, which is designed to transport 3.25 Bcf/d of Appalachian gas in Ohio, West Virginia and Pennsylvania to the US Midwest and the Dawn Hub in Ontario, Canada. While roughly 1.5 Bcf/d of capacity has been available since September 2017 from Phase I of the project, the lion’s share of capacity, coming from Phase II, was delayed into August 2018 due to unforeseen regulatory and construction delays. As most Phase II facilities have received FERC approval and been placed in-service, flows on Rover have reached as high as 3 Bcf/d in recent days, according to S&P Global Platts Analytics. Thus far, a majority of the volumes hitting the pipeline likely were the result of rerouted volumes from other regional pipelines, including Texas Eastern and Columbia Gas, rather than incremental Northeast production.

CNX Expecting Appalachian Output to Rebound By Year’s End – CNX Resources Corp. expects production to peak in the fourth quarter now that the operational issues it faced earlier in the year have been resolved. The company has reported sequential production declines since early this year on asset sales and issues at well pads, such as retrieving downhole equipment and production casing problems, that have forced it to adjust its turn-in-line (TIL) schedule. The company still remains on track to bring 68 wells online by the end of the year, COO Tim Dugan said this week during a call to discuss third quarter results, and expects production to peak after a number of wells were placed to sales late in the third quarter. CNX produced 119 Bcfe during the period, up from 101 Bcfe at the same time last year. Third quarter volumes declined slightly from 122.6 Bcfe in 2Q2018, but the company had guided for the decline on the cadence of its TIL schedule following the operational issues earlier in the year. The company also completed the sale of its Utica Shale joint venture assets to Ascent Resources LLC in August and lost some production. While the midpoint of its guidance remains unchanged, CNX lowered it slightly at the high end. Full-year production now is forecast at 497.5-507.5 Bcfe, compared to the previous range of 490-515 Bcfe. While the Marcellus Shale accounted for the bulk of the company’s third quarter production at 70.6 Bcfe, Utica Shale volumes from Monroe County, OH, and Pennsylvania continued climbing. CNX said it produced 33.6 Bcfe in the play during the third quarter, up 67% from a year ago. As most other Appalachian operators have, CNX said its average quarterly realized prices increased. The company said it earned $2.92/Mcfe during the third quarter, up from $2.50/Mcfe a year ago. Revenue also increased to $397 million from $287 million over the same time. CNX reported third quarter net income of $125 million (59 cents/share), compared with a net loss of $26 million (minus 11 cents) in 3Q2017.

Why Plans to Turn America’s Rust Belt into a New Plastics Belt Are Bad News for the Climate – DeSmog (blog) –The petrochemical industry anticipates spending a total of over $200 billion on factories, pipelines, and other infrastructure in the U.S. that will rely on shale gas, the American Chemistry Council announced in September. Construction is already underway at many sites. This building spree would dramatically expand the Gulf Coast’s petrochemical corridor (known locally as“Cancer Alley”) – and establish a new plastics and petrochemical belt across states like Ohio, Pennsylvania, and West Virginia. If those projects are completed, analysts predict the U.S. would flip from one of the world’s highest-cost producers of plastics and chemicals to one of the cheapest, using raw materials and energy from fracked gas wells in states like Texas, West Virginia, and Pennsylvania.Those petrochemical plans could have profound consequences for a planet already showing signs of dangerous warming and a cascade of other impacts from climate change. Some of the largest and most expensive petrochemical projects in the U.S. are planned in the Rust Belt states of Ohio, West Virginia, Pennsylvania, and New York, a region that has suffered for decades from the collapse of the domestic steel industry but that has relatively little experience with the kind of petrochemical complexes that are now primarily found on the Gulf Coast.In November 2017, the China Energy Investment Corp., signed a Memorandum of Understanding with West Virginia that would result in the construction of $83.7 billion in plastics and petrochemicals projects over the next 20 years in that state alone – a huge slice of the $202.4 billion U.S. total. Those plans have run into snags due to trade disputes between the U.S. and China and a corruption probe, though Chinese officials said in late August that investment was moving forward. The petrochemical industry’s interest is spurred by the fact that the region’s Marcellus and Utica shales contain significant supplies of so-called “wet gas.” This wet gas often is treated as a footnote in discussions of fracking, which tend to focus on the methane gas, called “dry gas” by industry – and not the ethane, propane, butane, and other hydrocarbons that also come from those same wells.

Work stopped on pipeline that exploded in Beaver County, after Pa. regulators find environmental violations – Energy Transfer LP, the operator of the Revolution Pipeline that exploded near Monaca last month, has been ordered by state regulators to stop all work on that pipeline because of subsequent environmental violations. The Pennsylvania Department of Environmental Protection issued an order to the Texas-based pipeline company on Monday alleging that its construction practices are failing to control erosion and soil movement and have impacted several streams in the area.The company must stop all earth moving activities, temporarily stabilize its work sites and submit a series of plans before it can continue with its work to get the pipeline back up and running again.Soil movement, specifically a landslide, is believed to be the cause of the early morning rupture on Sept. 10 which burned down a house at the end of a suburban street in Beaver County. The Revolution pipeline, a 45-mile natural gas line that runs through Washington, Allegheny, Beaver and Butler counties, was activated just a week prior to the burst, which burned down a house at the end of a suburban street in Beaver County.According to the Beaver County Conservation District, the construction of the Revolution pipeline was marked by land slips – in part because of the unusually wet conditions in the region, including at the site of the explosion.Jim Shaner, executive director of the Beaver County agency, told the Post-Gazette last month that the company had installed the erosion controls as designed “but they were not working.”The Pennsylvania Public Utility Commission is leading the ongoing investigation into the failure. “The line will remain out of service until (Energy Transfer) can provide documentation that demonstrates that they are compliant with the federal and state codes and can operate the pipeline safely,” PUC spokesman Nils Hagen-Frederiksen said. The DEP, meanwhile, inspected the pipeline work over the course of four days last week and found that poor erosion control practices persisted, causing sediment pollution to flow into Raccoon Creek, Service Creek, Elk Horn Run, and tributaries to Raccoon Creek, Brush Run and Moon Run. Energy Transfer also hasn’t provided the DEP with its inspection reports and failed to report instances of non-compliance, the agency charged.It ordered the company to produce a plan to come into compliance with its permits by Nov. 9. By Dec. 3, Energy Transfer is to outline how it will manage storm water along the pipeline corridor once construction is complete.

A Pipeline, a Protest, and the Battle for Pennsylvania’s Political Soul – Mariner East isn’t a typical suburban line, carrying gas to heat people’s homes. When completed, the pipeline will carry highly explosive natural-gas liquids – compressed ethane, butane, and propane – three hundred and fifty miles from the Marcellus shale gas fields in western Pennsylvania to a port in Philadelphia. From there, the chemicals will be transported to Scotland, formed into pellets called nurdles, and made into plastic. The project is owned by Energy Transfer Partners – the parent company of Sunoco, which also owns the Dakota Access Pipeline – and it is part of an ongoing multibillion-dollar effort to monetize the state’s natural-gas resources. The company claims that the pipeline will create nine thousand jobs, and will have an economic impact in the state of more than nine billion dollars. The company also has a dismal safety record: its pipelines experience a leak or accident every eleven days, on average. In Pennsylvania, there is no state agency tasked with deciding where pipelines carrying hazardous liquids can be placed. As a result, E.T.P. can lay the line wherever it wants, without constraints, including through people’s property. If there’s a leak, the company instructs residents to “leave the area by foot immediately and attempt to stay upwind,” but there’s no guidance for people to determine whether they are in a safe area. Within the blast zone, ringing a doorbell, making a phone call, opening a garage door, turning lights on, or running an engine could ignite a fatal explosion. “It makes it hard to imagine how the forty-one schools that sit within the blast zone would manage with small children,” Friel Otten told me. The company did not respond to requests for comment, but it claims that it has recently reduced its rate of accidents per thousand miles by thirty per cent, bringing it into alignment with the rest of the industry.

Mariner East & Atlantic Sunrise Pipeline Contractor Now in Bankruptcy – The main contractor on the Atlantic Sunrise and Mariner East 2 gas pipelines that run through Lancaster County has declared bankruptcy. Ohio-based Welded Construction LP was sued in Oklahoma by Atlantic Sunrise owner Williams Partners. Williams alleges Welded overcharged the company and had accounting failures and other contract breaches.Williams has withheld $23 million from the company. The nearly 300-mile, $3 billion Atlantic Sunrise natural gas project – which goes through 37 miles of Lancaster County – began moving gas on October 6th. Sunoco, owner of the 300-mile Mariner East 2 natural gas liquids pipeline, terminated its contract with Welded, alleging the company failed to comply with environmental requirements.The pipeline, which goes through 8 miles of northeastern Lancaster County, has been beset with spills and fines that have delayed the project. After the legal actions by the two pipeline builders, Welded filed for Chapter 11 bankruptcy.

Residents Speak Out Against Mountaineer Gas Pipeline and Rockwool at Public Hearing in Shepherdstown – The West Virginia Public Service Commission traveled to Shepherdstown this week for a public hearing to address concerns about a pipeline expansion project in the Eastern Panhandle. About a hundred people showed up to rally before the event. Dozens went on to speak during the hearing – and many took the opportunity to mention the controversial Rockwool manufacturing company.Martinsburg resident Stewart Acuff was one of several people who spoke against the pipeline and Rockwool at the PSC’s hearing Wednesday night.“The people of the Eastern Panhandle of West Virginia have said over and over and over again in huge numbers, we don’t want this damn pipeline, and we don’t want Rockwool,” Acuff said. Many attendees asked the PSC commissioners not to approve Mountaineer Gas’ expansion pipeline into the Eastern Panhandle. That pipeline is being built between Berkeley Springs and Martinsburg, and construction began in March. It will be more than 22 miles long.Project developers Mountaineer Gas and TransCanada say the pipeline will bring natural gas to Jefferson and Morgan Counties. Mountaineer Gas has proposed to invest nearly $120 million for infrastructure replacements and system upgrades from 2019 through 2023, including roughly $16.5 million for ongoing investments to expand and enhance service in Morgan, Berkeley and Jefferson counties. But several residents at the hearing shared concerns about the pipeline’s impact on the Panhandle’s karst geology of sinkholes, springs and caves. Speakers also mentioned a controversial insulation manufacturing plant being built in Ranson just a few miles from public schools and homes. The plant, Denmark-based Rockwool, will make stone wool insulation. The Ranson facility would feature two, 21-story smokestacks releasing chemicals like formaldehyde. Rockwool has said the gas pipeline would be crucial for its operation.

Dominion Energy 3Q18: Atlantic Coast Pipeline Delayed to 2020 – Dominion Energy shared two bits of big news yesterday during their third quarter 2018 update. The first is that they’ve agreed to sell their 50% stake in Blue Racer Midstream (see Dominion Sells Its 50% Share in Blue Racer Midstream for $1.5B). The second bit of news, big news (for us), is that Atlantic Coast Pipeline (ACP) is now officially delayed – from late 2019 to “mid-2020″ for a full startup. The price tag for ACP is going up too: $7 billion (up from $6.5 billion). But it’s not all bad news for ACP. Some pieces of the project will still go online in 2019, just not all of it. Dominion is taking a “phased in-service approach” to bringing the project online. The delays are due to the “FERC stop work order and delays obtaining permits necessary for construction.” We put it this way: The delays due to a myriad of frivolous lawsuits from Big Green groups means everyone will now pay more. Thanks Big Green. Details from the official 3Q18 update about ACP and the related Supply Header Project: The FERC stop work order and delays obtaining permits necessary for construction have impacted the cost and schedule for the project. As a result, project cost estimates have increased from a range of $6.0 to $6.5 billion to a range of $6.5 to $7.0 billion, excluding financing costs.Atlantic Coast Pipeline is pursuing a phased in-service approach with its customers, whereby we maintain a late 2019 in-service for key segments of the project to meet peak winter demand in critically constrained regions served by the project. ACP will be pursuing a mid-2020 in-service date for the remaining segments of the project. Abnormal weather and/or work delays (including delays due to judicial or regulatory action) may result in cost or schedule modifications in the future.The Supply Header project target in-service remains late 2019. “We have been constructing ACP in West Virginia and North Carolina and on October 19 we received the final Virginia permit required to petition FERC to be underway with full mainline construction in all three states,” Farrell said. “Following approval from FERC of our Notice to Proceed filing, we will begin mainline construction in Virginia.”“We continue to achieve key milestones toward the successful completion of this critical energy infrastructure project and look forward to delivering safe, reliable, and affordable energy to our customers in time to meet peak demand for the 2019/20 winter season,” Farrell added. (1) Below are excerpts from CEO Tom Farrell’s prepared remarks on the quarterly analyst conference call. Of note:

• The $1.3 billion Greensville Power Station (Greensville County, VA), Virginia’s largest natgas-fired power station, is 98% done now and will be online producing electricity “in early December.”
• ACP is currently under construction in both West Virginia and North Carolina, and with the recent permits from Virginia, will soon be under construction there too.
• They remain committed to buying South Carolina’s SCANA Corporation and aim to complete it by the end of this year.

Why a Democratic candidate opposing offshore drilling is getting Republican support in Trump country – In his third ad of this year’s midterm elections, a wetsuit-clad Joe Cunningham bobs off the South Carolina coast. Treading water, the ocean engineer-turned Democratic candidate for Congress explains that he’s always opposed offshore drilling and that if elected, he’ll “make sure we never do” drill along South Carolina’s coast.The ad reflects what’s among the biggest issues facing South Carolina’s First District, which is home to the majority of the state’s 2,876 miles of serpentine coastline and barrier islands. Tourists flock to the shores for the sandy beaches and unobstructed views of gently curling waves, driving the region’s economy. But a sweeping offshore drilling plan unveiled earlier this year by the Trump administration threatens to upend all that. And local opposition might just be enough to flip the district blue for the first time in nearly 40 years. When the Trump administration first announced its plan to open 90 percent of U.S. waters in the outer continental shelf to oil and gas extraction, Mark Sanford, the Republican representative for the district, announced that he was against it. But Sanford lost his primary to Katie Arrington, a local state representative who campaigned on supporting Trump’s offshore drilling plan. Though she has since flipped on the issue, her stance presented a contrast for Cunningham who is now challenging her in a tight race for the general election.

Oil industry woos SC African-Americans to support offshore drilling – The oil interest lobbying organization American Petroleum Institute has launched a campaign targeting minority communities, including African-Americans, to promote offshore exploration and drilling for natural gas and oil. The pitch is it’s a job creator.The effort is gauged to counter massive opposition to the offshore alternative that numbers in the millions of individuals and groups.That opposition is largely people who are white – one of its acknowledged weak points.But the institute’s Explore Offshore campaign has sparked some outrage. “I’m not surprised in this political climate,” said Marquetta Goodwine, a Beaufort County resident who goes by Queen Quet. She has been dubbed chieftess of the Gullah/Geechee Nation.She is among the more prominent drilling opponents who are African-American. “Those things make me highly irate,” she said.But the campaign has won some support.“Quite frankly, what I was concerned about was there were a whole lot of white people (at a public meeting on the issue) and not a whole lot of black people,” said Stephen Gilchrist, chairman of the South Carolina African American Chamber of Commerce and the Explore Offshore effort in South Carolina.“African-Americans are economically disenfranchised on the coast,” he said.The campaign has been taken up by the African-American chamber as well as at least 68 other businesses, pro-business groups and anti-tax groups in the Southeast, from Virginia to Florida. In South Carolina, they include thePalmetto Promise Institute and S.C. Association of Taxpayers.Industry analyst Offshore Technology reported the campaign specifically focuses on minority communities and that its support reflects the focus. “These groups include a large representation from black, Hispanic and minority communities, which historically have shown less support for offshore oil and gas exploration than others – something the API is keen to change,” the report said.

Listen: Speculation continues as US Strategic Petroleum Reserve faces uncertain future – Podcast – On this week’s Platts Capitol Crude, Ken Vincent, the chief of staff with the DOE’s Office of Fossil Energy, talks exclusively about the Strategic Petroleum Reserve as speculation ramps up that the Trump administration may be considering a release from government oil stocks. Listen now…

Entergy investigators: Company knew or should have known about paid actors at council meetings – Executives at Entergy New Orleans “knew or should have known” that actors were hired to appear at City Council meetings and voice support for the company’s proposed eastern New Orleans power plant, a City Council-commissioned investigation concluded.The results of the investigation were released Monday night, and the council will hold a special meeting on Wednesday at 1 p.m. to formally receive it and hear a presentation from the investigators. The council, which regulates Entergy New Orleans, is considering levying a fine of up to $5 million against the company.The council called for the investigation of the so-called “astroturfing” campaign after The Lens reported that dozens of people, including professional actors, were paid between $60 and $200 to come to City Council meetings in October 2017 and February 2018 in support of a proposed power plant in eastern New Orleans. The council hired a team of lawyers from the firm of Sher, Garner, Cahill, Richter, Klein & Hilbert, led by former federal prosecutor Matt Coman. Retired Judge Calvin Johnson was also part of the team. In May, Entergy released the results of an internal investigation, denying that its employees knew anything about the scheme and blaming its public relations contractor, The Hawthorn Group, for hiring a third company, Crowds on Demand, which ultimately recruited the actors. “Even after the revelation that came as a result of the investigative report by The Lens and there was no question that people were paid by Hawthorn or Crowds on Demand, ENO continued to deny it had any knowledge of the payments and maintained it did nothing wrong,” investigators wrote. But the evidence indicates otherwise, the report says.

$10B LNG Facility Starts Commissioning Phase – Cameron LNG has begun the commissioning process for the support facilities and first liquefaction train of Phase 1 of its liquefaction-export project in Hackberry, La., Sempra Energy reported Friday.“All major construction activities have been completed to begin the commissioning and start-up process to produce LNG from the first liquefaction train,” Joseph A. Householder, Sempra’s president and chief operating officer, said in a written statement. “This is a significant milestone for this landmark U.S. energy infrastructure facility – an important step forward in advancing our strategic vision to become North America’s premier energy infrastructure company.” Sempra, which indirectly owns a 50.2-percent stake in Cameron LNG, noted that the commissioning process includes:

• Testing all support systems, combustion turbines and compressors
• Delivery of feed gas from the transmission pipeline
• Production of the first LNG

Once the Federal Energy Regulatory Commission (FERC) approves all of the commissioning steps and all steps are successfully completed for the first train, LNG production will begin and ramp up to fully production for delivery to global markets, Sempra stated. Other Cameron LNG owners include Total, Mitsui & Co., Ltd. and Japan LNG Investment, LLC, which is owned by Mitsubishi Corp. and Nippon Yusen Kabushiki Kaisha (NYK). Phase 1 of the $10 billion Cameron LNG project comprises the facility’s first three liquefaction trains. Sempra stated that all three trains should be producing LNG next year. The company that the facility is projected to export 12 million tonnes per annum (mtpa) – or approximately 1.7 billion cubic feet per day (Bcfd) – of LNG. According to the Cameron LNG website, the second-phase expansion would add two liquefaction trains with an LNG production capacity of 9.97 mtpa (1.41 Bcfd) as well as up to two additional full-containment LNG storage tanks. The full five-train facility would be capable of exporting up to 24.92 mtpa (3.53 Bcfd) of LNG, the website also states.

Brownsville LNG Project Advances – The U.S. Federal Energy Regulatory Commission (FERC) has issued the draft environmental impact statement (DEIS) for Texas LNG’s proposed LNG export facility in the Port of Brownsville, Texas LNG reported Sunday.“Texas LNG is committed to show how our project protects the environment and generates significant benefits for the local community and the Port of Brownsville,” Langtry Meyer, Texas LNG’s founder and chief operating officer, said in a written statement emailed to Rigzone. “This project will bring jobs and investment to Cameron County and deliver clean, safe, abundant Texas natural gas energy to the world.”According to Texas LNG, receiving the DEIS represents a key milestone toward its final investment decision (FID) for the first 2-million-tonne-per-annum (MTA) phase of the proposed two-train, 4-MTA project. “The DEIS further de-risks the project and adds confidence to the dates of remaining milestones in the permitting process,” the company said in its written statement. The company noted that remaining anticipated milestones include:

• Receipt of the final environmental impact statement by March 15, 2019
• A federal authorization decision deadline of June 13,2019
• A FID in late 2019
• Phase 1 production of 2 MTA of LNG to start in early 2023

According to Houston-based Texas LNG, the LNG export facility will be built on a 625-acre site on the Port of Brownsville’s deepwater ship channel near natural gas supplies and pipelines. The project fact sheet on the company’s website notes that the Port of Brownsville is one of the closest U.S. ports to the Panama Canal, which facilitates access to LNG customers in Asia. The facility would receive natural gas from the Agua Dulce trading hub in South Texas, and the company has stated that the Permian Basin associated gas it would liquefy is cheaper than the Henry Hub-indexed gas that would be fed into other Gulf Coast terminals. Samsung Engineering Co., Ltd. owns a minority equity stake in Texas LNG and will oversee engineering, construction and procurement.Texas LNG is the second Gulf Coast LNG project to receive a DEIS from FERC this month. On October 12, NextDecade Corp. reported that FERC had granted the document for its Rio Grande LNG project and associated Rio Bravo Pipeline. Additionally, Venture Global LNG announced last week that FERC had issued the final environmental impact statement for its Calcasieu Pass LNG export facility in Louisiana.

Next-wave LNG race hits hurdles in U.S.-China trade war (Reuters) – The delay of a U.S. Gulf Coast liquefied natural gas (LNG) export project has crystallized fears that the U.S. trade battle with China is hampering efforts to line up buyers needed to move ahead with multi-billion-dollar builds. The United States is positioning itself as the dominant provider of the supercooled fuel as Asian nations shift away from dirtier power sources like coal, and this month’s approval of a giant Canadian project led by Royal Dutch Shell bolstered enthusiasm for the sector overall in North America. That optimism took a hit on Monday, when Australia’s LNG Ltd delayed until next year a planned decision on whether to build its Louisiana-based Magnolia LNG plant due to problems lining up Chinese customers. And it comes when bankers and analysts in the sector had already questioned whether the next wave of projects in the pipeline would pass muster with investors. “Chinese LNG demand growth is the largest piece of demand growth out there, and Chinese buyers have got to feel reluctant to commit to U.S. capacity when the U.S. government sees trade as a means of exerting political leverage,” said Bob Ineson, managing director of North American natural gas at IHS Markit. China set a 10 percent tariff on U.S. LNG imports last month, extending a trade scuffle in which U.S. President Donald Trump imposed tariffs on $250 billion worth of imported Chinese goods and China retaliated with duties on $110 billion worth of U.S. goods. China’s LNG demand has skyrocketed in recent years on Beijing’s pollution crackdown, with imports nearly tripling since 2015. Last year it overtook South Korea as the world’s No. 2 importer of LNG. That boom, along with rising demand from other Asian nations, has helped gobble up an anticipated LNG glut and boosted spot prices to near four-year highs, breaking a multi-year freeze on new project investment. By the mid-2020s, global LNG demand is forecast to range from 360 million to 450 million tonnes, up from about 290 million tonnes in 2017. With China leading that growth, signing deals with its companies is viewed as imperative to get larger projects done. But the tariffs are having a chilling effect, according to two U.S. industry sources. China is not signing any long-term deals with U.S. projects until the spat is resolved, they said.

Rising U.S. crude output sparks race to build export terminals (Reuters) – A high-stakes competition is emerging among energy exporters proposing multi-million-dollar crude terminals along the U.S. Gulf Coast to handle a gusher of shale oil coming from West Texas oilfields. On Monday, private equity firm Carlyle Group became the latest to place a bet, proposing with the Port of Corpus Christi what it said would be the first onshore U.S. export facility able to load the world’s largest crude tankers. The winners of the export terminal race likely will be those best able to navigate a regulatory process that includes multiple government approvals and overcome labor and supply shortages that have already frustrating some early projects to expand export infrastructure. The contest comes as the shale revolution is expected to send the nation’s oil production to 11.8 million barrels per day by the end of 2019, from 9.35 million bpd in 2017, according to the U.S. Energy Information Administration. Existing coastal terminals could be overwhelmed by late next year as a flurry of new pipelines come into operation and move 2 million barrels of oil landlocked in West Texas to the Gulf Coast, say oil companies and analysts. Carlyle’s facility, which aims to begin operations by late 2020, will compete with other Texas and Louisiana projects proposed by Swiss-trader Trafigura AG and pipeline operators’ Enterprise Products Partners LP and Tallgrass Energy LP. Enterprise and Trafigura have not provided timelines, noting permits must be secured first. Each aims to fully load very large crude carriers (VLCCs)tankers able to carry up to 2 million barrels of oil to markets in Asia, Latin America and Europe. Most would require running pipelines away from ports and into the deeper parts of the ocean to allow loading of the larger ships. All of these proposals face significant licensing and other hurdles. Like others, the Carlyle-Port of Corpus Christi project, must pass lengthy state and federal approvals. It also must await completion of an Army Corps of Engineers project that has been delayed about a year, said Sean Strawbridge, chief executive officer of the Port of Corpus Christi Authority. Although shale production is expected to rise substantially, it will not fill all the proposed projects, said John Coleman, an oil market analyst at research firm Wood Mackenzie. “Everyone is racing to throw their hat in the ring and get their project done before everyone else,” he said. Only one or two of the five proposed offshore ports likely will be needed. “There’s simply not enough oil volumes to go around.”

$10B LNG Facility Starts Commissioning Phase – Cameron LNG has begun the commissioning process for the support facilities and first liquefaction train of Phase 1 of its liquefaction-export project in Hackberry, La., Sempra Energy reported Friday. “All major construction activities have been completed to begin the commissioning and start-up process to produce LNG from the first liquefaction train,” Joseph A. Householder, Sempra’s president and chief operating officer, said in a written statement. “This is a significant milestone for this landmark U.S. energy infrastructure facility – an important step forward in advancing our strategic vision to become North America’s premier energy infrastructure company.” Sempra, which indirectly owns a 50.2-percent stake in Cameron LNG, noted that the commissioning process includes:

• Testing all support systems, combustion turbines and compressors
• Delivery of feed gas from the transmission pipeline
• Production of the first LNG

Once the Federal Energy Regulatory Commission (FERC) approves all of the commissioning steps and all steps are successfully completed for the first train, LNG production will begin and ramp up to fully production for delivery to global markets, Sempra stated. Other Cameron LNG owners include Total, Mitsui & Co., Ltd. and Japan LNG Investment, LLC, which is owned by Mitsubishi Corp. and Nippon Yusen Kabushiki Kaisha (NYK). Phase 1 of the $10 billion Cameron LNG project comprises the facility’s first three liquefaction trains. Sempra stated that all three trains should be producing LNG next year. The company that the facility is projected to export 12 million tonnes per annum (mtpa) – or approximately 1.7 billion cubic feet per day (Bcfd) – of LNG. According to the Cameron LNG website, the second-phase expansion would add two liquefaction trains with an LNG production capacity of 9.97 mtpa (1.41 Bcfd) as well as up to two additional full-containment LNG storage tanks. The full five-train facility would be capable of exporting up to 24.92 mtpa (3.53 Bcfd) of LNG, the website also states.

China’s tariff on US natural gas delays Louisiana LNG project – An LNG (liquified natural gas) container of CNPC (China National Petroleum Corporation) is under construction next to others at the Yangkou Port in Rudong county, Nantong city, east China’s Jiangsu province.A company behind a multibillion-dollar project to export liquefied natural gas from Louisiana is delaying its investment decision due to problems lining up Chinese buyers amid the ongoing U.S.-China trade dispute.The announcement shows the trade tensions are beginning to have a negative impact on an industry that President Donald Trump has championed. Trump has pitched U.S. LNG – natural gas chilled to liquid form – to trade partners from China to Poland.Australia’s LNG Limited on Monday said it will not make a final investment decision this year on its Magnolia LNG terminal near Lake Charles, Louisiana. The company previously told investors it expected to announce a decision by year-end.”We made that statement prior to the trade tensions that have manifested over the past months, which have caused headwinds for LNG transactions,” LNG Limited CEO Greg Vesey said in a letter to shareholders. “We remain hopeful in our ability to bring a final investment decision for Magnolia LNG to the Board of Directors in the first part of 2019.” China slapped a 10 percent tariff on American LNG exports in September after the Trump administration imposed an equal levy on $200 billion in Chinese goods. The White House is reportedly preparing to place tariffs on all remaining Chinese imports – about $257 billion in products – if trade talks between Trump and Chinese President Xi Jinping fail to deliver a breakthrough. Vesey, a former natural gas and power executive at Chevron, held out hope that the world’s two biggest economies would settle their dispute before Magnolia finds buyers beyond China for its supplies.

Trade War Could Be ‘Pivotal’ For U.S. LNG – Donald Trump’s trade war with China is starting to scare away oil and gas investments, as new trade barriers clouds the long-term outlook on exports. Australia LNG announced that it would delay a final investment decision on its Magnolia LNG plant in Louisiana until next year, citing trouble securing enough buyers in China. “We remain confident in our ability to reach (final investment decision) on Magnolia whether or not China participates,” CEO Greg Vesey said in a tweet, before arguing that “multiple opportunities with customers in Europe and Asia exist, and our discussions with them are proceeding well.”His company might still move forward, but will need to find buyers elsewhere because the U.S.-China trade war shows no signs of abating, at least as of now. The Trump administration has implemented two rounds of tariffs on China. The first round consisted of about $50 billion in tariffs on Chinese goods, which was followed by a much more dramatic 10 percent tariff on $200 billion in imports from China. That 10 percent tariff is set to jump to 25 percent at the end of the year.A possible third and even more dramatic round is still in the cards, which would hit an additional $257 billion in Chinese goods. That would be even more significant because it would amount to just about the entirety of U.S. imports from China and would hit a broader set of consumer goods, and its effects would be felt across U.S. society as everyday items would likely see price increases. However, as it relates to the oil and gas market, the effects of the trade war are already evident. China retaliated to U.S. tariffs a few months ago by slapping a tariff on U.S. LNG. Without a clear path towards resolution, LNG developers cannot move forward with investment in new export terminals.

Cheniere to commission 1st Corpus Christi LNG cargo on Nov 15 – port (Reuters) – Cheniere Energy will commission the first liquefied natural gas (LNG) cargo from its new Corpus Christi export terminal on Nov. 15, the Texas port’s chief executive said on Tuesday. The commissioning of the cargo, months ahead of schedule, will mark the start of operations at Cheniere’s second LNG export facility and only the third major export facility in the United States. The Corpus Christi terminal had been undergoing commissioning work since the summer and while it was scheduled to come onstream in the first half of next year, Cheniere had said previously first LNG would come before the end of the year. Sean Strawbridge, CEO of the Port of Corpus Christi, where the terminal is located, told a London LNG conference that an event to mark the commissioning of the cargo would take place at the port on Nov. 15. LNG supplies from the United States are expected to soar in the coming years, turning the country into the third largest global exporter by 2020 according to some forecasts, as new facilities are built opening the tap for LNG exports. Around 50 million tonnes’ worth of export capacity is currently under construction in the United States, mostly on the Gulf Coast, adding to the 20 million tonnes in operation. Some 290 million tonnes of LNG was traded globally last year. Commissioning cargoes tend to be sold on the small, murky spot market so the timing of their arrivals is anticipated by traders. Analysts estimate between 1.0 and 2.5 million tonnes of LNG will hit the spot market in the first quarter of next year due to start-ups at new U.S. facilities, a significant amount in an industry still dominated by rigid multi-year supply contracts.

First USGC onshore VLCC terminal to be developed on Harbor Island by end-2020 — The Port of Corpus Christi and global alternative asset manager Carlyle Group have agreed to develop the first onshore VLCC loading terminal at Harbor Island, Texas, by the end of 2020, the companies announced Monday. The terminal project includes the development of at least two loading docks at Harbor Island as well as inland crude oil tank storage across Redfish Bay on land secured by Carlyle. Dredging of the 36-mile main access channel from the Gulf of Mexico to Harbor Island to at least 75 feet from the current depth of 47 feet will be funded privately, the companies said. “Major construction begins in 2019, but civil work and engineering and design have started,” Carlyle spokeswoman Christa Zipf told S&P Global Platts. Cost of the project is about $1 billion, she said, adding Carlyle expects about 20 VLCC loads per month. Construction and dredging will require no capital outlay from taxpayers, as Carlyle agreed to arrange for a private funding solution through its global infrastructure fund in addition to the port’s realization of regular rental payments, volume-based tariff income and land grants, the companies said. The Harbor Island onshore terminal could come online close to the same time as Trafigura’s offshore VLCC crude export terminal, located 12.7 miles off of the coast of North Padre Island and 15 miles from of Corpus Christi in 93 feet of water. Trafigura’s Texas Gulf Terminals VLCC loading facility will have the capacity to handle an average 500,000 b/d of crude and fully load one VLCC in 48 hours, or eight VLCCs per month, according to the permit application to the US Maritime Administration and the US Army Corps of Engineers. The company has not set a startup date for the offshore facility.

BP closes $10.5bn BHP US onshore assets acquisition – BP has concluded the acquisition of Australian company BHP’s unconventional onshore assets in the US for $10.5bn to boost its US onshore oil and gas portfolio, as well as pursue long-term growth.BP signed the agreement for the acquisition of BHP’s assets in July in a deal that is set to give the company a significant position in the liquids-rich regions of the Permian and Eagle Ford basins in Texas, in addition to the Haynesville natural gas basin in East Texas and Louisiana.The acquisition comprises oil and gas production of 190,000 barrels of oil equivalent per day (boe/d) and 4.6 billion barrels of oil equivalent of discovered resources.UK-based BP expects the transaction to deliver more than $350m of annual pre-tax synergies and boost upstream pre-tax free cash flow by $1bn, increasing it to $14bn-15bn in 2021. BP Upstream chief executive Bernard Looney said: “By every measure, this is a transformational deal for our Lower 48 business. It is an important step in our strategy of growing value in upstream and a world-class addition to BP’s global portfolio. The company’s existing onshore oil and gas business in the US currently produces around 315,000boe/d with resources of 8.1 billion barrels of oil equivalent.

Chevron shares jump 2% as quarterly profit doubles, oil and gas output hits record – Chevron reported quarterly earnings that beat analysts’ expectations on Friday, as record-setting oil and gas production boosted the company’s bottom line. Shares of the oil major were rose more than 2 percent on Friday. Chevron posted a profit of $4.05 billion for the quarter, more than double its earnings from a year ago. That came out to a profit of $2.11 per share, slightly beating Wall Street’s expectations for $2.06 per share, according to Refinitiv.. The company pumped nearly 3 million barrels per day of oil equivalent, the most it’s ever produced in a single quarter. The gains came as Chevron ramped up production from its Wheatstone liquefied natural gas project in Australia and as output continued to surge from its wells in the Permian Basin underlying Texas and New Mexico. That helped drive a nearly seven-fold jump from third-quarter 2017 earnings in Chevron’s oil and gas exploration and production business, where profits hit $3.38 billion this quarter. Chevron’s other major business line, refining and marketing fuels like gasoline and diesel, saw profits drop 24 percent. The decline was largely due to Chevron’s international refining business, where profit margins were lower and the company sold fewer assets compared with a year ago.

Houston driller WildHorse acquired by shale pioneer Chesapeake – Houston Chronicle -The shale drilling pioneer Chesapeake Energy said Tuesday it is acquiring Houston’s WildHorse Resource Development for $3 billion in cash and stock in a consolidation of players in South Texas’ Eagle Ford shale. Chesapeake, of Oklahomas City, is scooping up WildHorse, which exclusively focused on exploration and production in the emerging northeastern corner of the Eagle Ford west of College Station. In addition to its 420,000 acres in the region, WildHorse is about to open a sand mine in the area to service its hydraulic fracturing, or fracking, of wells.The deal combines two top Eagle Ford production companies, diversifying the holdings of Chesapeake, which is primarily focused in the southwestern portion of the shale play south of San Antonio. Chesapeake also is growing in Wyoming’s Power River Basin along with its lrgacy Marcellus shale position in Pennsylvania.Historically a natural gas company, Chesapeake has aimed to expand into higher-value crude oil assets that are ripe for development, and WildHorse proved a prime acquisition target as a pure-play Eagle Ford company with a large block of mostly contiguous acreage. The northeastern Eagle Ford, which is underdeveloped, holds more oil as opposed to natural gas, said David Heikkinen, chief executive and analyst with Heikkinen Energy Advisors in Houston.“I’d call it an emerging region,” Heikkinen said. “WildHorse has gone out and pioneered this region.”Eagle Ford oil arguably sells at the highest prices in the country because of its proximity to refining and port hubs in Houston and Corpus Christi, while the booming Permian Basin in West Texas is facing pricing discounts because of pipeline shortages.Chesapeake Executive Vice President Frank Patterson said the WildHorse acreage is more than 80 percent undeveloped, providing lots of room for growth. Chesapeake will use larger rigs than those deployed by WildHorse to drill longer horizontal wells and to do so more quickly. “It’s a very quick transition to a full field development plan,” Patterson said. “We’ll hit the ground running.”

Having Gone ‘Through Hell,’ Chesapeake Energy CEO Has ‘No Doubt’ It’s Time To Grow Again – Chesapeake Energy surprised investors Tuesday with the unexpected acquisition of WildHorse Resource Development for $4 billion. The prize here is 420,000 net acres of unconventional oil and gas fields, already producing 47,000 barrels a day, most of it from the oil zone of the Eagle Ford shale of southeast Texas, with an additional gas play in the Terryville field of North Louisiana. It works out to about $7,000 per undeveloped acre and $900,000 per undrilled location. Chesapeake is buying WildHorse, which has a thin public float, mostly from a cadre of private equity backers led by Natural Gas Partners and Carlyle Group, with KKR holding a small piece. Capital owns about 70%, Carlyle Group 24% and KKR about 5%, according to SEC filings. No surprise Chesapeake shares were down 15% on the day. When the deal closes, Wildhorse investors will own a whopping 45% of Chesapeake’s equity. The WildHorse Eagle Ford position is largely contiguous, only 20% developed, and it is in the oil zone of the Eagle Ford, with 80% of its revenues from oil. This asset will enable Chesapeake to more than double its oil production by 2020 to 165,000 bbls/d. “It is absolutely a turning point,” Lawler says. Because he’s buying Wildhorse mostly with stock, the deal will help further deleverage Chesapeake’s balance sheet, while being immediately accretive to cash flow. The geology of the acquired acreage is very similar to that of Chesapeake’s existing position in the Eagle Ford, where it has drilled 2,400 wells, commonly engineering horizontal completions 10,000 feet long. “It’s similar to what we have done, a close fit,” he said. And in a neat twist, WildHorse bought a chunk of its Eagle Ford position from Lawler’s previous employer, Anadarko Petroleum, in 2017 for $600 million. One of his top lieutenants at Chesapeake, Jason Pigott, used to run Anadarko’s Eagle Ford division.

Keystone XL pipeline fight heads to Nebraska Supreme Court – Attorneys for opponents of the Keystone XL pipeline and TransCanada will square off Thursday morning before the Nebraska Supreme Court in a lawsuit that could erect a new roadblock to construction of the $8 billion project.Landowners who oppose the pipeline, as well as environmental groups and Indian tribes, are seeking to nullify the Nebraska Public Service Commission’s 3-2 approval a year ago of a pipeline route across Nebraska.The lawsuit claims, among other things, that TransCanada didn’t formally seek approval of the “mainline alternative” route that was approved, and didn’t prove that the pipeline is in the public interest of the state. The lawsuit maintains that the company should reapply for a pipeline route, which would delay the much-delayed project for several more months.Attorneys for the Canadian pipeline developer have argued that even though the PSC didn’t OK the “preferred route” suggested by the corporation, it followed all state laws in approving the alternative. That route, TransCanada attorneys have said, is a superior route because it affects fewer water wells and passes through 84.6 fewer miles of the migratory path of the endangered whooping crane.It could take the State Supreme Court several weeks to rule after hearing oral arguments.Nebraska has become ground zero in the national environmental debate over the Keystone XL pipeline. The 36-inch pipeline would carry up to 830,000 barrels a day of thick tar sands crude oil from Canada to refineries on the U.S. Gulf Coast that are specially set up to refine such oil. TransCanada officials have said they have sufficient commitments from shippers to use the Keystone XL, but the company has not yet made the final financial commitment to build it.

Living on the Front Lines with Silica Sand Mines — The horror of fracking damages to life and land remain in the minds of most people who live near the massive land destruction from silica sand mining for what the unconventional oil and gas industry lovingly calls “proppant“. Very often, we in the Midwest wonder if the rest of the country knows that this specialized form of silica sand mining destroys our rolling hills, woodlands, and water sources in order for silica sand to feed the fracking industry’s insatiable proppant demand.. The largest sand mine in Bridge Creek Town lies one mile north of our tree farm. Two years ago, 40 acres of trees were culled for the installation of high intensity power lines to feed anticipated silica sand mine expansion under the legal provision of “Right-of-Way.” That document was signed by a previous land owner in 1948. No specific amount of land was specified on the original right-of-way, thus allowing significant legal destruction and permanent loss against the farm. The adjacent silica Hi-Crush sand mine depletes the hillsides and woodlots in its path. The weekly blasting away of the hillsides sends shock waves – shaking homes and outbuildings weekly, along with our nerves. Visible cracks appear in the walls of buildings, and private wells are monitored for collapse and contamination. The sand mine only guarantees repair to property lying within a half-mile of the mine. The mine blasts the land near Amish schools and has had a noticeable effect on the psyche of countless farm animals. The invisible silica is breathed by every living thing much to the mine’s denial, with deadly silicosis appearing up to 15 years after initial exposure. Our community is left to wonder who will manifest the health effects first. Blasting unearths arsenic, lead, and other contaminants into private wells and into the remaining soil. There has been no successful reclamation of the land after it is mined, with most residents wondering what the actual point is of developing a reclamation plan is if timely implementation and stringent reclamation metrics are not enforced. All useful topsoil has been stripped away and is dead with the land only able to support sedge grasses and very few of them at best. No farming on this mined land can occur even though these mining companies promise farm owners that when they are done mining, soil productivity will meet or exceed pre-mining conditions and much milder slopes than the pre-mining bluffs that contained the silica sand. Needless to say, land values of homes, farms, and property decrease as the mines creeps closer.

Driven by Trump Policy Changes, Fracking Booms on Public Lands – NYT – Reversing a trend in the final years of the Obama presidency, the Trump administration is auctioning off millions of acres of drilling rights to oil and gas developers, a central component of the White House’s plan to work hand in glove with the industry to promote more domestic energy production. Seeing growth and profit opportunities at a time of rising oil prices and a pro-business administration, big energy companies like Chesapeake Energy, Chevron, and Anschutz Exploration are seizing on the federal lands free-for-all, as they collectively buy up tens of thousands of acres of new leases and apply for thousands of permits to drill. In total, more than 12.8 million acres of federally controlled oil and gas parcels were offered for lease in the fiscal year that ended on Sept. 30, triple the average offered during President Barack Obama’s second term, according to an analysis by The New York Times of Interior Department data compiled by Taxpayers for Common Sense, a nonpartisan group that advocates budget discipline. Like the acreage offered for lease, the acreage actually leased by energy companies on federal lands hit its highest level last year since 2012, the height of the initial fracking boom in the United States. After 2012, a combination of Obama administration policy decisions and lower oil prices slowed demand for new drilling rights, a trend reversed since President Trump took office. That reversal has been propelled in part by the Interior Department’s willingness to go along with industry pressure to weaken rules that govern how these federal lands can be used, as regulators follow detailed industry scripts for rollbacks in protections for wildlife, air quality and groundwater supplies, documents show. The push amounts to one of Mr. Trump’s most comprehensive and controversial policy initiatives. It underscores the administration’s eagerness to reshape regulation at the behest of industry, and is playing out more immediately and visibly across big parts of the country than many of the other changes he is making to federal management of the environment.

New Mexico Communities Hand-Deliver Protest Comments On Expanded Fracking In Greater Chaco ― Community groups and advocates hand-delivered more than 10,000 citizen protest comments to the Bureau of Land Management’s New Mexico state office in snowy Santa Fe Wednesday in opposition to an oil and gas lease sale scheduled for December that would auction off close to 100,000 acres of public lands in New Mexico for industrialized fracking. In spite of the serious negative impacts that expanded fracking already has on local communities, the BLM has rolled back opportunities for the public to weigh in on this process, shortening “protest” or appeal periods from 30 days to just 10 days and refusing to hold any public hearings, even near impacted communities. Protest comments must be submitted by mail or hand-delivered, as the New Mexico agency no longer accepts emailed or faxed comments. More than 10,000 individual and unique protest comments were collected by dozens of tribal, community, and environmental organizations. Technical protest comments were submitted by Western Environmental Law Center, along with the Center for Biological Diversity, Chaco Alliance, Counselor Chapter House, Counselor Chapter Health Impact Assessment and HozhoÌoÌgoÌ naÌ adaÌ Committee, DineÌ Citizens Against Ruining Our Environment, Food & Water Watch, San Juan Citizens Alliance, Sierra Club and WildEarth Guardians. The New Mexico BLM plans to sell more than 84,000 acres of the Land of Enchantment to the oil and gas industry in a Dec. 6 online auction. This includes more than 43,000 acres in the Greater Chaco region of northwest New Mexico and 41,000 acres in southeast New Mexico’s Greater Carlsbad Caverns region. The sale also includes more than 5,000 acres in Oklahoma and Texas. Despite the fact that no additional study or tribal consultation has occurred, the BLM now plans to auction off 43,268 acres of public and tribal land in the area, including an additional 11,000 acres slated for sale in March of next year.

Colorado Proposition 112 Would Require 2500 ft. Setbacks for Human Safety. – The fight over Prop. 112 has lured big money and clashes over interpretation of health studies. “The OEHHA chronic benzene REL considers several studies published after USEPA’s 2002 benzene assessment, which found increased efficiency of benzene metabolism at low doses, decreased peripheral blood cell counts at low doses (800−1860 μg/m3)…” It takes another 20 words – with terms like “metabolic enzymes” and “benzene detoxification” – to close out this sentence from a recent University of Colorado study that looked at the potential health impacts of Front Range oil and gas operations. Thousands of equally abstruse passages fill hundreds of other studies from around the world examining the effects of drilling and hydraulic fracturing on human health. Welcome to the science behind Proposition 112, the oil and gas setbacks measure that will likely be among the most complex ballot issues to ever go before Colorado voters. The initiative aims to increase the required distance of any newly drilled wells from homes, schools and water sources to 2,500 feet. The current setback is 500 feet from homes and 1,000 feet from densely occupied buildings, like hospitals and schools. Opponents say the measure will block off so much acreage to drill rigs – it’s estimated that 85 percent of non-federal land in Colorado would be off-limits – that the $31 billion industry in Colorado would virtually collapse. Backers of 112 say without bigger buffers, Coloradans will continue to be exposed to noxious emissions from well sites, like toluene, formaldehyde, xylene, and cancer-causing benzene, to say nothing of the environmental harm from potent greenhouse gases, like methane. “It’s hard when we ask voters to vote on technical issues like this,” said Tanya Heikkila, a professor at CU Denver’s School of Public Affairs who focuses on environmental policy, management and law. She said few voters have the time, patience or expertise to navigate through the copious scientific research that has been done on energy extraction. As such, she said, they’ll likely turn to the people they know for advice on which box to check on the ballot – their friends, their neighbors, their doctor.

Energy Giants Choose Nuclear Option in Election’s Biggest Fight Over Fossil Fuel – “We have five oil and gas companies that want to amend our Constitution, our controlling document,” says Mark Foote, a dark-haired 45-year-old father of two who has been one of the legislature’s most outspoken critics of oil and gas companies. “They’re putting a lot of money into it, millions and millions of dollars. They may win, and they may buy a portion of our constitution that controls everything that we do.” Foote concedes that the ballot measure’s folksy artifice of frontier fairness seems compelling. On its face, it does not appear to be part of the now-familiar power-grab by Texas energy barons trying to install noxious fracking rigs next to idyllic neighborhoods in Colorado’s fast-growing suburbs. Instead, the amendment taps into fever-dream fears about Gestapo government. “The commercials typically show some salt-of-the-earth guy with a baseball cap that’s driving around a tractor on his farm. Supposedly he’s saying, ‘Well if government takes your property, then they should pay you,’ which sounds good, right?” Foote says as a few heads nod and an affirmative murmur ripples through the white-haired crowd. But, then, eminent domain folklore isn’t necessarily reality – and as its opponents tell it, Amendment 74 is not some good old grassroots common sense spontaneously crafted by hardscrabble ranchers. Foote explains that strong takings laws are already on the books, and that this constitutional initiative was meticulously engineered by a team of high-powered Denver attorneys and political operatives to achieve only one objective: shielding oil and gas corporations from all public interest regulations that may emerge as population growth and energy development collide in the Rocky Mountain West.

Wyoming Watching Colorado’s Anti-Fracking Ballot Issue – (AP) – Energy leaders in Wyoming are closely watching the fate of a Colorado ballot initiative that would severely limit fracking on non-federal land in that state.The Wyoming Tribune Eagle reports that Colorado-based opponents of the initiative warn it could drive jobs, capital and production northward into Wyoming.But Wyoming industry leaders say it’s way too early to say what impact the initiative could have on the Equality State’s economy.Colorado’s Proposition 112 would require that new oil and gas wells be at least 2,500 feet (750 meters) from occupied buildings and would allow local governments to enact even greater setbacks. Current requirements are 500 feet (150 meters) from homes and 1,000 feet (300 meters) from schools.It also would increase setbacks between new energy operations and “vulnerable areas” that include parks, creeks and irrigation canals. Current law gives the state jurisdiction over setbacks.It’s the latest attempt to harness drilling in Colorado’s rapidly expanding Denver metropolitan area. Previous efforts have failed, despite advocates’ concerns about health and drilling rigs close to schools.A state analysis suggests the initiative would rule out 85 percent of non-federal land in Colorado to development and drastically reduce property taxes paid by the $32 billion state industry.Proposition 112 is “literally a ban on new development,” argued Kathleen Sgamma, president of the Western Energy Alliance, a Denver-based oil and natural gas advocacy group. “So Wyoming would probably immediately see an increase in interest in the Powder River Basin. There’s already quite a lot of interest in the Powder right now.”The Powder River Basin, which straddles the Wyoming-Montanaborder, which straddles the Montana-Wyoming border, is the largest coal-producing region in the U.S. and, in Wyoming, hosts oil and natural gas drilling.

Corps: No new impacts found in Dakota Access pipeline review – The U.S. Army Corps of Engineers on Friday completed more than a year of additional study of the Dakota Access oil pipeline, saying the work substantiated its earlier determination that the pipeline poses no significant environmental threats.U.S. District Judge James Boasberg in June 2017 ruled that the Corps “largely complied” with environmental law when permitting the $3.8 billion, four-state pipeline built by Texas-based Energy Transfers Partners.However, the judge also ordered more study because he said the agency didn’t adequately consider how an oil spill under the Missouri River might affect the Standing Rock Sioux tribe’s fishing and hunting rights, or whether it might disproportionately affect the tribal community – a concept known as environmental justice. It aims to ensure development projects aren’t built in areas where minority populations might not have the resources to defend their rights. In its initial analysis of the Missouri River crossing that skirts the northern edge of the Standing Rock Reservation along the North Dakota-South Dakota border, the Corps studied the mostly white demographics in a half-mile (0.8-kilometer) radius, which the agency maintained is standard. But if the Corps had gone another 88 yards (80 meters) – not quite the length of a football field – the study would have included the reservation. The tribe accused the Corps of gerrymandering. The tribe believes an oil spill from the pipeline under the Lake Oahe reservoir on the Missouri River – from which the reservation draws its water – could have a detrimental effect on the tribal community. Standing Rock is leading a lawsuit joined by three other Dakotas tribes that seeks to shut down the pipeline.

is the Bakken facing another round of takeaway constraints? Part 2. – Pipeline capacity constraints are nothing new to producers in the Bakken. Prior to the completion of the Dakota Access Pipeline (DAPL) in mid-2017, market participants had been pushing area pipeline takeaway to the max. When DAPL finally came online following a lengthy political and legal battle, producers and traders were able to breathe a sigh of relief. But with Bakken production steadily increasing over the past 18 months – and primed for future growth – new constraints are on the horizon. Over the next year or so, Bakken output could overwhelm takeaway capacity and push producers to find new market outlets. The questions now are, which midstream companies can add incremental capacity, how much crude-by-rail will be necessary, and is there a chance a major new pipeline gets built? Today, we forecast Bakken supply and demand, discuss some upcoming projects and lay out the possible headaches for Bakken producers heading into 2019. We discussed the history and impact of DAPL in our Take My Crude Away blog, but here’s a quick recap. Prior to the commercial start-up of the new pipeline to Patoka, IL, in June 2017, Bakken producers had long battled with takeaway constraints. As far back as 2012, production (blue area in Figure 1) had outpaced the modest amount of pipeline capacity available (green line) and producers and traders resorted to moving excess production via crude-by-rail (CBR). CBR isn’t inherently bad, and does provide the ability to reach multiple markets, but it’s expensive, logistically challenging, and slow (compared to a pipeline). When DAPL came online, producers were faced with a new market dynamic – excess pipeline takeaway capacity. Bakken crude began to trade at a premium to West Texas Intermediate (WTI) at Cushing, as take-or-pay shippers were forced to compete with one another and pay up to incentivize barrels to move their way. Currently, Bakken barrels at the Clearbrook hub are trading at a $8/bbl discount to WTI at Cushing, influenced by market dynamics related to those also causing wide differentials for Canadian barrels, which we discussed in Part 1 of this blog series.

Big Oil Pours Record $30M to Sway Voters Against Nation’s First Carbon Tax – If voters approve Initiative 1631 on Nov. 6, Washington state will take a significant step in climate action by becoming the first state in the nation to enact a fee on carbon emissions. That is, unless Big Oil can stop it.The U.S. oil industry has pumped a record $30 million to stop the carbon tax, which environmentalists havetried to enact for years, Reuters reported, citing state data. Meanwhile, proponents – including green groups and climate activist billionaires Bill Gates, Michael Bloomberg, Tom Steyer and Laurene Powell Jobs, the widow of Apple founder Steve Jobs – have spent $15.2 million.”With Big Oil spending $30 million, that makes it a real fight,” Bill Holland, state policy director for the League of Conservation Voters, told Reuters. “It has been a frightening amount of money.”Washington ranks fifth in the nation in crude oil refining capacity for making gasoline and other petroleum products, according to the U.S. Energy Information Administration.Initiative 1631 imposes a starting fee of $15 per metric ton on carbon emissions, beginning in 2020. This fee rises $2 every year until the state hits its 2035 emissions reductions goals and is on track to meet its 2050 goals. If passed, the tax is expected to generate $2.3 billion in revenue for green infrastructure, clean transportation and help communities most impacted by pollution. A recent statewide Crosscut/Elway Poll among registered voters shows 50 percent approval of the measure, 36 percent opposed and 14 percent undecided.

More than 500 gallons of diesel spills after work crew hits line – Hundreds of gallons of diesel fuel was spilled near a Union Pacific track in Roseville on Friday. The Roseville Fire Department says a construction crew was out along the track near Atlantic Street and Tiger Way when they struck a four-inch diesel line. More than 500 gallons of diesel fuel spilled into the soil, Roseville Fire says. A third party clean-up crew is now at the scene Friday afternoon for mop-up work. No evacuations were ever issued for the surrounding neighborhoods, including nearby Roseville High School. Officials say the lines are owned by oil and gas line company Kinder Morgan. The lines run through the area and go into a pumping station in Rocklin.

Alaska natives call on banks to protect the Arctic national wildlife refuge from drilling – Tiliisia Sisto, a 23-year-old mother of two, lives in Venetie, Alaska, a Gwich’in Alaska Native village, and if she wants to eat affordably while also preserving her culture, hunting is key. So are the Porcupine caribou she and her people rely on. Now, a federal proposal to open the Arctic lands on which these caribou calve to oil and gas drilling threatens the Gwich’in’s primary food source and their way of life. That’s why Sisto traveled all the way to New York City this week to ask major banks to withhold funding for projects seeking to develop the Coastal Plain of the Arctic National Wildlife Refuge (ANWR). The Trump administration has been trying to fast-track an environmental impact statement to get extraction going here since the beginning of the year. “I’m speaking up for my children’s future.” Sisto, along with Bernadette Demientieff, the executive director of the Gwich’in Steering Committee, and two representatives with the Sierra Club, met with officials from eight banks this week – JP Morgan Chase, Barclays, Goldman Sachs, Bank of America, Morgan Stanley, Credit Suisse, UBS, and Citi – to explain why this 1.5 million-acre piece of land is so sacred to them. They want these institutions to understand that drilling in the refuge is not just an environmental issue. “This is a human rights violation,” Demientieff told Earther. Ultimately, the group wants the banks to publicly declare they’re opposed to drilling in this area and pledge they won’t financially support any such efforts. No banks made any promises, but Demientieff, at least, left feeling “hopeful”, she said. Bank of America directed Earther to its environmental website outlining its environmental commitments to regions like the Arctic but offered no additional information on how it plans to proceed. Credit Suisse and UBS confirmed the meetings but offered no specific information outside their commitments to protecting the environment and respecting indigenous communities.

U.S. monthly crude oil production exceeds 11 million barrels per day in August – EIA – U.S. crude oil production reached 11.3 million barrels per day (b/d) in August 2018, according to EIA’s latest Petroleum Supply Monthly, up from 10.9 million b/d in July. This is the first time that monthly U.S. production levels surpassed 11 million b/d. U.S. crude oil production exceeded the Russian Ministry of Energy’s estimated August production of 11.2 million b/d, making the United States the leading crude oil producer in the world. Monthly crude oil production reached a record high in several states. Texas had the highest record level at 4.6 million b/d, followed by North Dakota at 1.3 million b/d. Other states that had record-high production levels were New Mexico, Oklahoma, Colorado, and West Virginia. Production in the Federal Offshore Gulf of Mexico also hit a record high of 1.9 million b/d. The Permian region, which is located in western Texas and eastern New Mexico, accounts for about 63% of total Texas crude oil production and 95% of total New Mexico crude oil production. From January 2018 to August 2018, Texas crude oil production increased by 683,000 b/d (15%) and New Mexico production increased by 182,000 b/d (25%). The growth in Texas and New Mexico since the start of 2018 surpassed EIA’s previous expectations, which assumed that pipeline capacity constraints in the Permian region would dampen production growth in response to the increased differential between the West Texas Intermediate (WTI) crude oil price at Cushing, Oklahoma, and the WTI price at Midland, Texas. In August 2018, this differential had grown to more than $16 per barrel (b), up from $0.43/b in January. However, industry efficiencies in pipeline utilization and increased trucking and rail transport in the region have allowed crude oil production to continue to grow at a higher rate than EIA expected. From May through August, production in the Gulf of Mexico grew by an average of 130,000 b/d every month, a significant increase from the growth rate in the first four months of the year. This increase was primarily the result of a number of fields returning to full production after several months of maintenance and other infrastructure issues that arose from Hurricanes Harvey and Nate in 2017. U.S. crude oil production has increased significantly during the past ten years, driven mainly by production from tight oil formations using horizontal drilling and hydraulic fracturing. EIA estimates of crude oil production from tight formations in August 2018 reached 6.2 million b/d, or 55% of the national total.

U.S. crude output jumps to record 11.35 million bpd in August: EIA (Reuters) – U.S. crude oil production surged by 416,000 barrels per day (bpd) to a record 11.346 million bpd in August the U.S. Energy Information Administration said in a monthly report on Wednesday. The rise came as production climbed in Texas and North Dakota to fresh peaks of 4.58 million bpd and 1.28 million bpd respectively, the data showed. The agency revised its July production figure slightly lower to 10.93 million bpd. Output from the United States has boomed thanks to a shale revolution, with production from the nation’s largest oilfield, the Permian basin that spans West Texas and New Mexico, leading the increase. Meanwhile, natural gas production in the lower 48 U.S. states rose to an all-time high of 94.7 billion cubic feet per day (bcfd) in August, up from the prior record of 92.7 bcfd in July, according to EIA’s 914 production report. In Texas, the nation’s largest gas producer, production increased to a record high 24.9 bcfd in August, up 1.7 percent from July. That compares with output of 21.8 bcfd in August 2017. In Pennsylvania, the second biggest gas producing state, production rose to a record high 17.3 bcfd in August, up 1.8 percent from July. That compares with output of 14.5 bcfd in August 2017.

US oil output surges but growth likely to moderate in 2019- John Kemp (Reuters) – U.S. crude oil production is rising at the fastest rate on record as the increase in prices over the last year boosts drilling and completion activity and energy firms employ more horsepower to fracture larger wells. Crude and condensates output hit a record 11.35 million barrels per day in August, up from 10.93 million bpd in July, according to the U.S. Energy Information Administration (“Petroleum Supply Monthly”, EIA, Oct. 31). Crude output has increased by more than 2 million barrels per day over the past 12 months, an absolute increase that is unparalleled in the history of the U.S. oil industry (https://tmsnrt.rs/2P1FGR7 ). In percentage terms, output is up by nearly 25 percent over the last year, the fastest increase since the 1950s (excluding the recovery from hurricanes). U.S. oil production is now rising faster than at the height of the last drilling and fracking boom before prices slumped in the second half of 2014. Most of the increase is coming from onshore shale fields, where output has risen by more than 1.9 million bpd over the last year, with a smaller contribution from the Gulf of Mexico, where output is up 200,000 bpd. In the first nine months of the year, the number of wells drilled in the United States was up by 26 percent while well completions were up by 24 percent (“Drilling productivity report”, EIA, Oct. 15). Increasing U.S. output has helped alleviate earlier concerns about a possible crude shortage following the re-imposition of U.S. sanctions on Iran with effect from Nov. 5. Surging domestic output coupled with increased production from Russia, Saudi Arabia and a number of other OPEC countries has pushed oil prices lower and driven the futures markets back towards contango. Spot prices and calendar spreads for WTI have weakened rapidly since July, much further and faster than for Brent, in response to the improved availability of crude in the midcontinent of the United States.

Baker Hughes- US rig count down 1 unit to 1,067 – Oil & Gas Journal– The US drilling rig count is down 1 unit to 1,067 rigs working for the week ended Nov. 2, according to Baker Hughes data. The count is up 169 units from the 898 rigs working this time a year ago. Rigs drilling on land remained unchanged at 1,046 units for the week. Offshore units were down a single rig to 18 units working, while those drilling in inland waters remained unchanged at 3 rigs working for the week. US oil-directed rigs were down 1 unit from last week to 874 units working, and up from the 729 rigs drilling for oil this week a year ago. Gas-directed rigs remained unchanged at 193 units, up from the 169 units drilling for gas a year ago. Among the major oil and gas-producing states, Oklahoma saw the largest increase in rigs for the week with a 3-unit gain to reach 144. New Mexico, Louisiana, and Ohio each gained a single rig with 102, 62, and 18 rigs running, respectively. Six states were unchanged this week: North Dakota, 54; Colorado, 32; Wyoming, 30; California, 15; Utah, 6; and Alaska, 5. Texas dropped the most rigs, ending the week down 4 units to 533. Dropping a single unit were Pennsylvania, 43; West Virginia, 13; and Kansas, 0. Canada lost 2 rigs for the week. With 198 rigs running, the count is higher than the 192 units drilling this week a year ago. Canada dropped 3 oil-directed rigs to reach 121 units for the week but gained a single gas-directed rig to reach 77 units.

Prices Slide On Moderating Weather Forecasts And Record US Production — Kyle Cooper – Highlights of the Natural Gas Summary and Outlook for the week ending October 26, 2018 follow. The full report is available at the link below.

• Price Action: The November contract fell 6.5 cents (2.0%) to $3.185 on a 14.8 cent range ($3.250/$3.102).
• Price Outlook: Prices slid and established a new weekly after last week’s rare inside week. The market moved lower as weather forecasts moderated and the EIA reported a much larger than expected weekly storage change. Physical data has also turned bearish as the non-linear impact moderate temperatures reduced demand at the same time pipeline data suggested US production reached a new record level. However, pipeline data also indicated flows to US LNG export facilities reached a new record as well, partially mitigating rising US production. The current weather forecast is now warmer than 7 of the last 10 years. Pipeline data indicates total flows to Cheniere’s Sabine Pass export facility were at 3.5 bcf. This flow volume suggests feed gas is entering Train 5. Cove Point is net exporting 0.7 bcf.
• Weekly Storage: US working gas storage for the week ending October 19 indicated an injection of +63 bcf. Working gas inventories rose to 3,095 bcf. Current inventories fall (615) bcf (-16.6%) below last year and fall (618) bcf (-16.6%) below the 5-year average.
• Supply Trends: Total supply fell (1.2)bcf/d to 81.3 bcf/d. US production fell. Canadian imports fell. LNG imports fell. LNG exports rose. Mexican exports fell. The US Baker Hughes rig count rose +1. Oil activity increased +2. Natural gas activity decreased (1). The total US rig count now stands at 1,068 .The Canadian rig count rose +9 to 200. Thus, the total North American rig count rose +10 to 1,268 and now exceeds last year by +168. The higher efficiency US horizontal rig count rose +1 to 927 and rises +158 above last year.
• Demand Trends: Total demand rose +2.4 bcf/d to +72.7 bcf/d. Power demand fell. Industrial demand fell. Res/Comm demand rose. Electricity demand fell (4,636) gigawatt-hrs to 69,464 which trails last year by (187) (-0.3%) and trails the 5-year average by (640)(-0.9%%).
• Nuclear Generation: Nuclear generation fell (665)MW in the reference week to 76,458 MW. This is (9,003) MW lower than last year and (3,531) MW lower than the 5-year average. Recent output was at 75,871 MW.

The heating season has begun. With a forecast through November 9 the 2018/19 total cooling index is at (109) compared to (155) for 2017/18, (37) for 2016/17, (76) for 2015/16, (125) for 2014/15, (167) for 2013/14, (186) for 2012/13 and (162) for 2011/12.

Can U.S. Gas Demand Keep Up With Surging Production? – Natural gas production hit another high in the United States at approximately 87 billion cubic feet per day (Bcf/d) over the last weekend. The rise in production contributed to a total gas supply over 91 Bcf/d before we even head into the winter months.The surge in domestic natural gas production comes at the same moment as we are experiencing a shortage in storage going into the season with highest natural gas demand. Storage is vital during the winter months when demand for natural gas spikes and production is not able to keep up, causing the necessity to dip into reserves.Currently storage is at a 10-year low, coming in below 3.2 trillion cubic feet of available storage capacity. What’s more, net imports of Canadian natural gas have been low thanks to Enbridge’s pipeline rupture near Prince George, British Columbia. When the import volumes return to their normal levels, total gas supplies in the U.S. would rise even higher, potentially exceeding 92 Bcf/d.Most estimates for this week’s Energy Information Administration (EIA) weekly storage report project that there will be an injection in the low 50s Bcf, not nearly enough to make a dent in the persistent storage deficit.A Reuters poll of 18 market participants showed a range of 39 Bcf to 65 Bcf, with a median build of 51 Bcf. At this time last year, the build was 63 Bcf, and the five-year average is 77 Bcf for the corresponding period, emphasizing the shortcomings of this week’s storage injection.Natural gas demand can’t be expected to spike in early November either, with a very mild forecast for the coming weeks. We can therefore continue to expect a relatively low heating demand nationwide, despite several cold snaps in the Midwest and Northeast. In the face of this news, natural gas futures have been falling accordingly. Nymex futures settled at $3.166 for November, down 4.6 cents on the day. December plummeted 5.6 cents, ending up at $3.227, and the winter strip (November through March) went down 5.4 cents to $3.174. That being said, weather model volatility and market uncertainty means that big price swings more than likely in the near future. Meanwhile, despite depressed gas prices and major storage shortages, across the country production is natural gas production is ramping up.

NYMEX December gas rises despite warmer winter outlook – – NYMEX December natural gas futures contract rose 7.4 cents and settled at $3.261/MMBtu Wednesday, despite a warmer-than-average weather outlook The front-month contract traded between $3.207/MMBtu and $3.275/MMBtu. The National Weather Service calls for a likelihood of warmer-than-average temperatures over the next six to 10 days across much of the US. But prices were pushing up despite the expected warm start to winter, likely because the market is still indecisive about winter demand as storage stocks sit well below the five-year average. Current national stocks sit at 3.095 Tcf, a deficit of nearly 17%, or 624 Bcf, to the five-year average of 3.719 Tcf, according to the US Energy Information Administration. Bullish storage expectations are likely driving Wednesday’s gains. A consensus of analysts surveyed by S&P Global Platts expects a 52-Bcf injection for the week ended October 26, significantly below the five-year average of 62 Bcf. Total US supply is set to drop by 700 MMcf day on day to 88.1 Bcf Wednesday, according to Platts Analytics. Much of the declines are likely to be driven by total dry gas production, which is estimated to drop by 600 MMcf on the day to stand at 84.7 Bcf. Over the past five days, production averaged 85.1 Bcf/d, an increase of 600 MMcf/ d from the prior five days. Output increased 600 MMcf/d month on month to average 84.0 Bcf/d for October. Average production stood at 74.5 Bcf/d in October 2017. Platts Analytics projections show output is likely to average nearly 85 Bcf/d over the next two weeks. US demand is estimated to drop nearly 1 Bcf and slide to 70.2 Bcf Wednesday, according to Platts Analytics data, likely on mild temperature expectations. Over the next seven days, demand is projected to average 70.7 Bcf/d, which is largely in line with the 71.8 Bcf/d demand seen during the same time last year.

Weather Spooks Natural Gas For Halloween – It was a spooky Halloween for natural gas bears as the December natural gas contract shot up over 2% and continued running after the settle on significantly colder afternoon weather model runs. These bullish weather forecasts sent the December/January Z/F contract spread to new narrow levels. This came after firmer cash prices initially spiked the front of the strip higher this morning as well. Our Morning Update for clients did show many of these Week 2 cold risks that intensified overnight but appeared to die off into early Week 3. Though that trend held in afternoon model guidance, cold earlier in Week 2 was seen being even more intense. The result was a forecast with solidly more cold risks for the 8-14 Day time period per the Climate Prediction Center. Traders are now attempting to determine just how intense and long lasting any Week 2 cold shot(s) will be, weighing the latest forecasts against the EIA storage number that comes out tomorrow morning. In our Afternoon Update we broke down all the latest forecasts through the day as well as our thoughts on how intense the cold gets, when it may break, what EIA data should show tomorrow, and what that could mean for prices. To give this all a look, and see all our extensive coverage of weather and natural gas, here

Slightly Smaller Gas Injection Can’t Break Prices Up – After strength early this morning, the December natural gas contract settled down a bit less than a percent as record production numbers and bearish fundamental headlines outweighed a slightly smaller than expected storage injection as announced by the EIA. In what was a new development, it was the February contract that saw the largest losses on the day. Prices initially found strength on firm physical prices and overnight forecasts that were still relatively supportive. This was unsurprising as we noted in our Afternoon Update yesterday there was “short-term upside above $3.3 increasingly possible if this cold signal holds overnight…” as it did. Then our Morning Update outlined that “a brief bounce over $3.3 appears likely” but “…bounces above $3.3 appear likely to fail through tomorrow” thanks in part to forecasts that did not cool all that much more overnight, and sure enough prices reversed off a high of $3.318 down to a low of $3.216. Those forecasts did cool this afternoon, though, as we saw another slew of colder weather model guidance. While this did provide support, gas prices were already off solidly following an EIA print that was 5 bcf below our 53 bcf estimate but just a touch below the consensus. Of note was a meager build of just 1 bcf in the East thanks to much colder weather last week. In our Morning Update we outlined “slight downside risks to our +53 bcf estimate today” which played out but also had outlined that the number was expected to be loose overall either way. Then in our Afternoon Update we broke down what the print seems to mean for the natural gas market as well as what next week’s print would likely hold as we looked at this week’s weather-adjusted balances. We concluded with our view on how current weather forecasts are likely to shift into the weekend and how that should impact natural gas prices. To give this Update a look, and begin receiving all our detailed weather and natural gas-driven analysis, try out a 10-day free trial here.

Crazy Weather Models Shake Up Nat Gas – Weather continues to push around natural gas at will, with far warmer overnight weather models pushing prices far lower before colder afternoon model guidance shot prices back up to new highs. Weather was clearly the primary reason for the spike with the front of the strip making the largest gain on the day.

The result was another significant spike in the Z/H December/March contract spread. Prices initially were off significantly this morning as we noted a solid dip in GWDDs in the medium and long-range in overnight forecasts. The Climate Prediction Center noted these trends in the 8-14 Day outlook today, which warmed but did not take into account all of the colder afternoon model guidance. Afternoon GEFS weather model guidance trended significantly colder to start things off, sending prices soaring with a significant medium-range cold shot (model images courtesy of Tropical Tidbits). Headed into the weekend, traders were forced to decide whether these trends would hold or intensify, with clear volatility across weather models. In our Pre-Close Update we outlined how we expected weather models to trend over the weekend, while also looking at how the latest weather-adjusted balances could influence price action as we moved into next week.

Cold Snap Could Send Natural Gas To $5 – The natural gas market is looking rather tight, even as U.S. production continues to set new records. Inventories fell sharply last winter, leaving the country a little light on stocks heading into injection season. That did not concern the market much, with record-setting production expected to replenish depleted inventories. However, the past six months has not led to surging stockpiles, and inventories replenished at a much slower rate than expected. We are about to enter the winter heating season with inventories at their lowest level in 15 years. For the week ending on October 19, the U.S. held 3,095 billion cubic feet (bcf) of natural gas in storage, or 606 bcf lower than at this point last year, and 624 bcf below the five-year average. The reason for this is multifaceted, with seasonal weather playing a role, but also structural increases in demand. “Hot summer weather, LNG liquefaction demand, exports to Mexico, and the industrial sector have all mitigated the impact from a 8.7 bcf/d YoY production growth surge this summer,” Bank of America Merrill Lynch said in a recent note. Low inventories and potential deliverability risks led the investment bank to hike its price forecast for the first quarter of 2019 to $4 per MMBtu, up from a prior estimate of just $3.40/MMBtu. Peak winter demand in the early 2000s stood at around 75 to 85 billion cubic feet per day (bcf/d), according to BofAML. That figure spiked to 100 bcf/d last winter, helping to explain the rapid decline in inventories. There was a cold snap in early January, but the winter on the whole was “near normal,” BofAML argues, making the steep fall in stocks all the more remarkable. In other words, demand is structurally much higher than it used to be; the sudden tightness is not just because of a seasonal anomaly. A cold snap this upcoming winter could lead to a price spike, especially with the inventory buffer so low. “The Polar Vortex winter of 2013-2014 realized a record low salt inventory level of 54 bcf,” BofAML said. Salt inventories are those that can be called upon quickly. “Another Vortex, which on average has occurred once every 7 years in the 1950-2018 period, would be catastrophic,” Bank of America Merrill Lynch warned.

Gastar Exploration Files for Chapter 11 Bankruptcy – Gastar Exploration Inc., a pure play Mid-Continent independent energy company, has entered into a restructuring support agreement (RSA) with Ares Management LLC, the company’s largest funded-debt creditor and shareholder, Gastar announced Oct. 26. After Gastar’s failed efforts to repay or refinance debt or sell the company, it decided to file Chapter 11 bankruptcy. The restructuring will eliminate more than $300 million of the company’s debt and will provide $100 million in new, committed financing to fund the Gastar’s restructuring process and ongoing business operations.“The restructuring agreement we signed today is a comprehensive plan that will ensure Gastar remains competitive in its industry,” Gastar’s interim CEO Jerry R. Schuyler said in a company statement. “We can now set our sights on facilitating a smooth, efficient in-court restructuring while continuing to meet our obligations to our employee and vendor constituencies.” Gastar anticipates it will consummate the plan and emerge from Chapter 11 before the end of the year.

Shale oil becomes shale fail (and a nice subsidy for consumers) – I’m tempted to say the following to the writers of two recent pieces (here and here) outlining the continuing negative free cash flow of companies fracking for oil in America: “Tell me something I don’t already know.”But apparently their message (which has been true for years) needs to be repeated. This is because investors can’t seem to understand the significance of what those two pieces make abundantly clear: The shale oil industry in the United States is using investor money to subsidize oil consumers and to line the pockets of top management with no long-term plan to build value.There is no other conclusion to draw from the fact that free cash flow continues to be wildly negative for those companies most deeply dependent on U.S. shale oil deposits. For those to whom “free cash flow” is a new term, let me explain: It is operating cash flow (that is, cash generated from operations meaning the sale of oil and related products) minus capital expenditures. If this number remains negative for too long for a company or an industry, it’s an indication that something is very wrong.Only nine of 33 shale oil exploration and production companies reviewed in the report cited above had positive free cash flow for the first half of 2018. This is even though prices had risen all the way from a low of around $30 in 2016 to the mid-$70 range by the middle of this year.To get an idea of just how bad it has been even through periods when the price of oil averaged above $100 in 2011, 2012, 2013 and most of 2014, here are the annual free cash flows in dollars of those 33 companies combined since 2010 and they are all negative: -14 billion (2010), -21.9 billion (2011), -37.8 billion (2012), -16.8 billion (2013), -33 billion (2014), -34.4 billion (2015), -18.3 billion (2016), -15.5 billion (2017). Capital expenditures are what companies invest in future production – in this case, the acquisition of new oil deposits and the drilling and completion of new wells and associated infrastructure. Because operating cash flow has not been sufficient to cover the drilling of new wells, companies must either issue new debt or new shares to raise money to do so. The former makes companies more likely to go bankrupt if oil prices turn down and the latter dilutes the value of the company for existing shareholders. Either way, it’s not good news for investors.

US Shale Oil Industry- Catastrophic Failure Ahead — While the U.S. Shale Industry produces a record amount of oil, it continues to be plagued by massive oil decline rates and debt. Moreover, even as the companies brag about lowering the break-even cost to produce shale oil, the industry still spends more than it makes. When we add up all the negative factors weighing down the shale oil industry, it should be no surprise that a catastrophic failure lies dead ahead. Of course, most Americans have no idea that the U.S. Shale Oil Industry is nothing more than a Ponzi Scheme because of the mainstream media’s inability to report FACT from FICTION. However, they don’t deserve all of the blame as the shale energy industry has done an excellent job hiding the financial distress from the public and investors by the use of highly technical jargon and BS. For example, Pioneer published this in the recent Q2 2018 Press Release: Pioneer placed 38 Version 3.0 wells on production during the second quarter of 2018. The Company also placed 29 wells on production during the second quarter of 2018 that utilized higher intensity completions compared to Version 3.0 wells. These are referred to as Version 3.0+ completions. Results from the 65 Version 3.0+ wells completed in 2017 and the first half of 2018 are outperforming production from nearby offset wells with less intense completions. Based on the success of the higher intensity completions to date, the Company is adding approximately 60 Version 3.0+ completions in the second half of 2018. Now, the information Pioneer published above wasn’t all that technical, but it was full of BS. Anytime the industry uses terms like “Version 3.0+ completions” to describe shale wells, this normally means the use of “more technology” equals “more money.” As the shale industry goes from 30 to 60 to 70 stage frack wells, this takes one hell of a lot more pipe, water, sand, fracking chemicals and of course, money. However, the majority of investors and the public are clueless in regards to the staggering costs it takes to produce shale oil because they are enamored by the “wonders of technology.” For some odd reason, they tend to overlook the simple premise that… MORE STUFF costs MORE MONEY. Of course, the shale industry doesn’t mind using MORE MONEY, especially if some other poor slob pays the bill.

Why Majors Will Take a Bigger Role in US Shale – Independent producers will forever be pioneers of the U.S. shale sector, but as the play matures, expect major oil companies to play a growing and critical role in its future development. Majors, with their financial strength and integrated solutions, are well-equipped to handle the structural challenges that the U.S. shale sector now faces, from insufficient pipeline and export infrastructure in the Permian and Gulf Coast, to excessive gas flaring in Bakken. The time also looks right for majors get more involved and “scale up” in shale. Big Oil remains very light in U.S. shale oil relative to other upstream assets in their portfolio. Majors have traditionally focused on “megaprojects,” schemes such as those in deep water or oil sands, where capital investments are massive and payback periods are long. Giants like Royal Dutch Shell plc and Total S.A. have already exited from Canada’s oil sands, where they believe breakeven costs are too high. The onset of the low-carbon energy transition also must be considered, and the fact is that oil sands emit more carbon dioxide than any other oil projects and must produce for many years – at relatively high oil prices – to deliver sufficient financial returns. U.S. shale oil, on the other hand, has proven its mettle at low prices, having stood up to OPEC in a price war. Breakeven prices for shale have been driven below $40 a barrel and are even lower for companies fracking the best rock. Shale is a “short-cycle” upstream asset, meaning new production can be brought on within months after investment decisions are made. That’s a highly attractive feature to majors, which must not only manage today’s volatile prices but also consider the long-term demand outlook for new “long-cycle” megaprojects. Would majors greenlight a $55-billion project like Kashagan again? Probably not.

Canadian Producers Turn to Oil Trucks — The highways of Saskatchewan show just how desperate Canadian oil producers are to get their crude to market. Tanker trucks laden with oil are journeying almost 500 miles (800 kilometers) to pipeline and rail terminals. It’s a phenomenon that Ken Boettcher, president of Three Star Trucking Ltd. in Alida, Saskatchewan, started to see three or four months ago when oil shippers around Kindersley, near the Alberta border, began requesting trucks to move their crude, in some cases, as far south as North Dakota. “Its never been a common practice before,” he said in a phone interview. “They can probably buy it cheaper and bring it down here and blend it.” Canada’s pipeline bottlenecks are pushing Canadian crude prices to the lowest in at least a decade, which has made shipping oil by truck more cost effective. At Hardisty, Alberta, heavy Western Canadian Select sold for $52.40 a barrel less than West Texas Intermediate crude futures earlier this month, the biggest discount in Bloomberg data going back to 2008. Almost 230,000 barrels of crude were exported by truck in August, the most in data going back to January 2015, according to data provided by Statistics Canada. Every month since December, more than 100,000 barrels have been exported by truck. A typical tanker truck can carry about 250 barrels of oil, Boettcher said. Hiring a truck to ship crude from the Permian basin of West Texas to Houston, a distance of almost 500 miles, costs about $15 a barrel one way, or double that if the tanker returns empty, said Sandy Fielden, director of research for the commodities group at Morningstar Inc. Pipeline constraints in Canada, combined with a surge of new oil-sands production, have created more demand for oil trucks. One export pipeline, Enbridge Inc.’s Line 3, is scheduled to be expanded by late next year, but other projects continue to face delays, including the planned expansion of the Trans Mountain pipeline to the British Columbia coast.

Repairs completed on ruptured gas pipeline near Prince George, B.C.- Enbridge – Enbridge Inc. says it has successfully completed repairs on the section of a natural gas pipeline that ruptured and burned near Prince George, B.C., three weeks ago. The company says following a comprehensive integrity assessment, it expects to begin safely returning the repaired segment to service within the next two days. It says it will gradually increase flows of natural gas through the repaired segment until it reaches 80 per cent of its normal operating pressure. A smaller pipeline nearby returned to service two days after the explosion, also at 80 per cent of its normal pressure, which the company says helps ensure the ongoing safety and integrity of the system. Once the repaired segment is returned to service, Enbridge says the system is expected to safely deliver between 23 and 25 million cubic metres of natural gas per day to B.C.’s Lower Mainland and the U.S. Pacific Northwest. The return-to-service plan has been reviewed by the National Energy Board and Enbridge says it’s conducting a comprehensive dig to help further validate the integrity of the entire system. The company says until it’s fully satisfied it is safe to operate the lines at full capacity, and subject to regulatory review, both pipelines will continue to operate at reduced pressure. It adds there are a number of assumptions, risks and uncertainties that might delay its plans for returning the pipeline to service.

TransCanada Moves Ahead with $1.5B NOVA Gas Expansion – Calgary-based pipeline company TransCanada Corporation is moving forward with its $1.5 billion NOVA Gas Transmission Ltd. (NGTL) expansion, the company announced Oct. 31.The expansion will move gas from Alberta and British Columbia to markets all over North America.The expansion plan includes about 197 kilometers (122 miles) of large diameter pipeline, three compression units, meter stations and associated facilities.“The NGTL System continues to expand as parties require and contract for greater pipeline capacity to meet the growing demand for clean-burning natural gas from domestic and export markets,” Russ Girling, TransCanada’s CEO, said in a company statement. “This new investment brings the capacity expansion programs underway on the NGTL System to more than $9 billion.”Applications for approvals to construct and operate the facilities are expected to be filed with the National Energy Board in 2Q 2019. Construction could begin as early as 3Q 2020 with most of capital investments happening in 2021 and 2022. TransCanada just reported its third quarter profits at $928 million.

Greenland says China oil majors eyeing Arctic island’s onshore blocks (Reuters) – China National Petroleum Corp (CNPC) and China National Offshore Oil Corp (CNOOC) have expressed interest in bidding for onshore oil and gas blocks in Greenland to be offered in 2021, officials from the island said on Tuesday. The Arctic island, a self-ruling part of Denmark, is shifting its oil and gas licensing strategy from offshore to onshore in an effort to generate revenues faster, they said. The next blocks to be tendered will be on the Disko Island and Nuussuaq Peninsula area of West Greenland, industry and energy minister Aqqalu Jerimiassen told Reuters on the sidelines of a Greenland Day event at the Danish embassy in Beijing. Jerimiassen, who took office in May, said he met with the two Chinese oil majors, as well as China’s National Energy Administration, on Monday. The Chinese asked for follow-up meetings to discuss technical issues, said Jorn Skov Nielsen, Jerimiassen’s deputy. “They have not been active in Greenland earlier. It’s a new approach,” he added. “We are moving the short-term strategy of licensing onshore”. CNPC and CNOOC did not immediately respond to a request for comment. In neighbouring Iceland, CNOOC has been exploring the offshore Dreki area but has not reported any finds. Nielsen said it was too early to say how many blocks would be tendered, or to give an estimate for the resources in the “highly prospective” area. The U.S. Geogological Survey puts Greenland’s offshore oil and gas resources at about 50 billion barrels of oil equivalent, he said. Greenland’s domestic energy goal is to be powered 100 percent by clean energy by 2030, Jerimiassen later told a press conference, up from the current 70 percent, which is mostly from hydropower. Greenland will set up a representative office in Beijing “within a year,” to boost trade ties with China, Nielsen said. Denmark and the United States have been concerned about China’s interest in Greenland, notably over potential Chinese involvement in the financing and construction of airports.

Fracking in Lancashire- Second 0.8 tremor in 24 hours – A second tremor of 0.8 magnitude has been recorded within 24 hours at the UK’s only active site for fracking. It was detected on Saturday after drilling for shale gas resumed in Lancashire following a 0.8 tremor on Friday. Neither was felt at surface. Since 15 October, Little Plumpton has been the first UK shale fracking site after the process was halted in 2011 when it was linked with earthquakes. Fracking firm Cuadrilla said it aimed to resume operations on Monday. The process restarted on Saturday morning after a 0.8 magnitude tremor on Friday, which is categorised as a “red” event by the monitoring system regulated by the Oil and Gas Authority.Saturday’s tremor was detected at the firm’s site in Little Plumpton after work ended for the day on Saturday, when operations finish at 13:00.Any tremor measuring 0.5 or above means fracking must be temporarily stopped while tests are carried out. A Cuadrilla spokeswoman said that, as the operations had finished before the detection, “This is not an ‘red’ incident under the traffic light system operated by the Oil and Gas Authority as we were not pumping fracturing fluid as part of our hydraulic fracturing operations at the time.”However we will, as always, continue to monitor the seismic activity closely and plan to resume hydraulic fracturing on Monday 29 October.”She said all relevant regulators had been informed.A spokesman for the the Oil and Gas Authority said: “While the operations at the Preston New Road site have been designed to minimise any disturbance, minor events like these were expected.” He added: “Provided that the event is in line with the agreed Hydraulic Fracture Plan and the risk of induced seismicity continues to be appropriately managed, then operations may resume on Monday.”

Fracking stopped again in Lancashire after ‘biggest earthquake so far’ – Fracking has stopped at a gas exploration site in Lancashire for the third time in 15 days after the biggest earthquake recorded so far. Energy firm Cuadrilla confirmed work had stopped again as a micro-seismic event measuring 1.1 magnitude on the Richter scale was detected at about 11.30am on Monday. It’s the 27th earthquake – and biggest – since fracking began on October 15, and has officially been classed as a ‘red event.’A Cuadrilla spokesman said: ‘This is the latest micro-seismic event to be detected by the organisation’s highly sophisticated monitoring systems and verified by the British Geological Survey (BGS). ‘This will be classed as a ‘red’ event as part of the traffic light system operated by the Oil and Gas Authority, but as we have said many times, this level is way below anything that can be felt at surface and a very long way from anything that would cause damage or harm. ‘In line with regulations, hydraulic fracturing has paused for 18 hours now, during which seismicity will continue to be closely monitored by ourselves and the relevant regulators.

Cuadrilla hails natural gas flow from Lancashire fracking operation – Gas has begun to reach the surface of the Preston New Road site, after Cuadrilla used hydraulic fracturing to free a small section of shale rock inside an exploration well. “Tthis is a good early indication of the gas potential that we have long talked about,” said chief executive Francis Egan. While the gas volume is small, Cuadrilla has been restricted by several “micro-seismic” tremors at the site, where fracking has been stopped since 2011 after being linked to two earthquakes. The most recent tremor occurred on Monday, leading the firm to pause operations for 18 hours, and marking the fifth such event in six days. However, Cuadrilla said it plans to “fully test” flow from its first two exploration wells towards the end of this year and into early 2019. “This initial gas flow is by no means the end of the story. However it provides early encouragement that the Bowland Shale can provide a significant source of natural gas to heat Lancashire and UK homes and offices and reduce our ever growing reliance on expensive foreign imports.

Minor earthquakes emerge as major threat to UK fracking – Protests, legal challenges and planning rejections have failed to stop the return of fracking in Britain, but the government’s regulations on earthquakes are fast emerging as the biggest threat to the nascent shale gas industry. The energy company Cuadrilla has been forced to stop work at its Preston New Road site in Lancashire twice in four days – on Friday last week and on Monday – due to minor earthquakes occurring while it was fracking. The tremors breached a seismic threshold imposed after fracking caused minor earthquakes at a nearby Cuadrilla site in 2011. Francis Egan, the firm’s chief executive, told the Guardian on Monday that the limits were proving “extremely challenging” and it was time they were reconsidered. But the energy minister, Claire Perry, rejected that call, saying it would be “a very foolish politician” who relaxed standards “when we we are trying to reassure people about safety”. Fracking firms must temporarily halt operations if a quake is triggered above 0.5-magnitude – far below anything that could be felt at the surface. If a 0.5-magnitude tremor occurred at surface-level, it would be akin to the vibrations of a passing car. The architects of the regulations are split on whether there should be a rethink. Peter Styles, one of the geologists who set the threshold, said: “We have started this frack now. If we stop now, we will never learn what happens in the UK situation. My opinion is for better or for worse they’re [Cuadrilla] going to have to tough it out unless we get earthquakes that are significant enough to be disruptive.” Styles, professor emeritus in applied and environmental geophysics at Keele University, said it was right the government rejected calls by Egan to lift the limit.“They [Cuadrilla] don’t like it because it costs them money when they stop, but that’s part of this game. It’s not the time to raise it. Let’s carry it out under these rules, observe it, and then revisit it when we have the data.”

Study suggests why fracking causes earthquakes in some places but not others – New research is digging in to why fracking causes earthquakes in some areas but not in others. A paper published Monday in Geophysical Research Letters suggests the likelihood of an artificial earthquake is heavily influenced by how stable the ground was before the energy industry showed up. “Some places appear to be particularly responsive to (artificially-)occurring earthquakes while other places aren’t,” said Honn Kao, a seismologist with the Geological Survey of Canada and lead author. Related Stories References to fracking, oil, birth policies removed from CAQ website N.B. Liberals question Tory leader campaigning with Alberta’s Jason Kenney N.B. business groups call on province to reconsider fracking ban B.C. conducts study on effects of fracking for natural gas Scientists have known for some time that injecting fluids to dispose of wastewater or to free underground reserves of oil and gas can cause earthquakes. Regulatory records show there have been hundreds of seismic events since 2015 in a heavily fracked area of northwestern Alberta. Those earthquakes around the Fox Creek area have registered as high as 4.5 on the Richter scale — strong enough to rattle dishes and pictures. Alberta’s energy regulator has tightened restrictions on fracking in the area. Meanwhile, other regions see thousands of wells fracked while the earth remains still. While the link between fracking and earthquakes is well-established, precisely how that link works remains mysterious. Other studies have asked if it’s related to local geology or particular fracking practices, but Kao said he’s found a much more important contributor. “The background tectonic loading rate appear to be one of the predominant factors that control the region’s response to injection-induced earthquakes,” he said. In other words, the deep, underground shifting of Earth’s rocky tectonic plates create zones where tension is concentrated and stored like a coiled spring, called tectonic deformation. The sudden shattering of rock through fracking or the injection of high-pressure wastewater releases that pent-up energy in the form of an earthquake. The finding could help explain why western Alberta and northeast B.C. have a high rate of fracking-induced earthquakes and places such as Saskatchewan, which has thousands of fracked wells, doesn’t.

BP profit more than doubles on stronger oil prices — BP reported third-quarter profits more than doubled on Tuesday, underpinned by stronger oil prices. The British oil giant posted first-quarter underlying replacement cost profit, used as a proxy for net profit, of $3.8 billion for the three-month period ending Sept 30. Analysts at data firm Refinitiv had been expecting third-quarter net profit to come in at around £3.013 billion ($3.847 billion).In the third quarter of 2017, BP reported net profit of $1.865 billion.”Overall a good set of results with everything working well,” Brian Gilvary, CFO at BP, told CNBC’s “Squawk Box Europe” on Tuesday.Here are the key takeaways:

• Underlying replacement cost profit, used as a proxy for net profit, came in at $3.8 for the three-month period ending Sept 30.
• In the third quarter of 2017, BP reported net profit of $1.865 billion.
• Dividend of 10.25 cents a share for the third quarter, 2.5 percent higher than a year earlier

Earlier this year, BP announced the acquisition of BHP’s Billiton’s shale assets for $10.5 billion. At the time, the oil firm claimed the purchase would allow it to beef up its U.S. business and increase earnings and cash per share.The original deal was agreed with BP offering 50 percent cash and 50 percent shares for BHP Billiton’s shale assets. However, the company announced it would now complete the transaction at the end of the month from available cash without resorting to a rights issue as planned.Gilvary said this “simplified the transaction an awful lot.” Oil and gas production for the first nine months of the year rose to 2.5 million barrels of oil equivalent per day and was well placed to increase further, BP said, thanks in large part to its acquisition of BHP’s U.S. shale business.

Shell Produces One of Its Strongest Ever Quarters – Royal Dutch Shell’s CEO Ben van Beurden announced Thursday that good operational delivery across all Shell businesses produced one of the company’s “strongest ever quarters”. The company reported cash flow from operating activities of $12.1 billion in the third quarter (3Q), which included negative working capital movements of $2.6 billion, compared with $7.6 billion in the third quarter of 2017, which included negative working capital movements of $1.3 billion. “Excluding working capital movements, cash flow from operations of $14.7 billion mainly reflected increased earnings and higher dividends received,” Shell said in its latest results statement. Shell’s CCS (current cost of supplies) earnings attributable to shareholders in 3Q were $5.6 billion, excluding identified items, compared with $4.1 billion, excluding identified items, in 3Q 2017. “Earnings primarily benefited from increased realized oil, gas and LNG prices as well as higher contributions from trading in Integrated Gas, partly offset by lower margins in Downstream, higher deferred tax charges in Upstream and adverse currency exchange effects,” Shell said in its results statement.

Low Rhine River water levels disrupt petroleum product shipments to parts of Europe – Historically low water levels on the Rhine River in Europe have resulted in transportation disruptions for shipments of petroleum products by barge, which in turn have resulted in higher freight costs and higher prices in markets upriver, such as in southern Germany. These disruptions are occurring at a time when markets along the Rhine River typically build inventories of distillate fuel for space heating ahead of the winter. The Rhine River, which runs northwest from Switzerland through Germany, France, and the Netherlands into the North Sea, is a major petroleum product transportation corridor. The navigable portions of the river connect the major refinery and petroleum trading centers of Amsterdam and Rotterdam in the Netherlands and Antwerp in Belgium, collectively known as the ARA, to inland markets. Tanker barges carry petroleum products from the ARA upriver to inland bulk distribution terminals that provide petroleum products to nearby areas. Water levels on the Rhine River fluctuate with seasonal rainfall, and both high and low water levels can create problems for barges: high water levels on the Rhine may put barges at risk of potentially striking bridges over the river, and low water levels mean barges risk becoming stuck and hitting the river bottom. Within safety and operational constraints, barges adjust the amount of cargo they carry to balance bridge clearance and deep draft restrictions based on water levels. Low water levels mean barges must carry less cargo, increasing the freight rate per unit of cargo. Water levels on the Rhine River measured at Kaub, Germany – near the Rhine’s midway point – have recently reached historic lows. The average water level at Kaub in October was 1.7 feet, compared to the five-year average level of 4.8 feet. The record low water levels in October 2018 are a sharp contrast to the water levels of early 2018 when water levels were at more than 20 feet.

NT’s fracking emissions could cost more than $4b a year to offset by 2030, report finds – Offsetting emissions generated by fracking could cost up to $4.3 billion per year when the shale gas industry is at full production in the Northern Territory in 2030, according to new research by the Australia Institute. The huge sum is a warning sign of the mammoth task at hand for those responsible for developing a yet-to-be-implemented emissions offset framework in the Territory. The Australian Petroleum Production and Exploration Association has rejected the findings, labelling them a “deliberate attempt” to overstate potential emissions. Chief Minister Michael Gunner is bound by his word after he accepted in-full the fracking inquiry’s recommendation that the NT and Australian governments seek to ensure there is no net increase in greenhouse gas emissions from onshore gas produced in the NT. “The Government made a very clear undertaking publicly that it would require all emissions to be offset, it’s absolutely essential that it goes ahead,” Australia Institute principal adviser Mark Ogge said. Mr Gunner indicated that he is waiting on the Federal Government to take the lead on emissions policy. “There’s been a change of Prime Minister since those conversations [about national emissions policy] have started and the current Australian Government’s policy is not entirely clear,” he said.

Defiant Energy Policy of Mexico’s President-Elect Rattles Moody’s and Fitch – Moody’s has rated the $2 billion of senior unsecured notes due 2029 that Mexico’s state-owned oil company Pemex is in the process of issuing one notch above junk. Pemex is offering to pay a coupon interest rate of 6.5%. In its report on Friday, Moody’s blamed the company’s “weak liquidity, a heavy tax burden and the resulting weak free cash flow, high financial leverage and low interest coverage; and challenges related to crude production and reserve replacement.”Moody’s is also worried about the large amounts of debt coming due in 2020 and beyond. And Pemex will continue to be “dependent on debt capital markets to fund negative free cash flow,” it said.Fitch Ratings downgraded the outlook for Pemex’s debt from stable to negative amid concerns about the incoming government’s proposed energy policies. It rates Pemex three notches above “junk” (BBB+), but only because the company is state-owned. Its standalone credit profile – if Pemex were not backstopped by the Mexican state – is junk, seven notches into junk (CCC). Fitch has also warned earlier that if Pemex’s credit rating drops, so, too, will Mexico’s sovereign debt rating. Even a small deterioration in credit risk could exact a heavy toll on both the company and the country.

Argentina restarts natural gas exports to Chile – Argentina has begun exporting natural gas to Chile after a 12 year interlude, Chilean President Sebastian Pinera said on Tuesday, as the two South American neighbors seek to increasingly integrate their energy supply and electricity grids. The unconventional gas is being piped from Argentina’s oil- and gas-rich Vaca Muerta shale field to Chile’s southern province of Biobio. Argentina, which sits atop the world’s No. 2 shale gas reserves, was once a major supplier of natural gas to Chile, but triggered a diplomatic crisis in the mid-2000s by cutting off shipments when its own supplies ran low. Pinera said the two countries had very different, but often complementary, energy needs, and that depending on the time of year and circumstance, could either export or import fuel and electricity across their shared border. “This will permit us to back one another up without having to spend excess money to do so,” he said.

Oil spill detected in the channel of the Tuapse river Russia – According to the SCC of Rosmorrechflot, the operational duty officer of the Azov-Black Sea branch of the FBU “Morspasluzhba” received a message that pressure drop sensors in the pipeline operated at the Tikhoretsk-Tuapse oil pipeline in the port of Tuapse. ACF FBU MSS received a letter from the Transneft company with a request for help in eliminating the possible ingress of oil products into the open sea. A group of rescuers led by the head of the rescue operations of the port of Tuapse in a vehicle drove to the place of the alleged pollution of the sea area, since it is impossible to do this on the ship immediately due to floating large debris and trees at the place of deployment of the Bonsport Ship Valery Barsky. Visually observed rainbow spots in the river. Then “Valery Barsky” moved to the place of pollution of the waters of the river bed, which flows into the sea and began to explore the area. Separate foci of rainbow spots were discovered, which immediately began to be treated with a sorbent. From the port of Novorossiysk, the tugs Antares and Agat (tugboats owner – Transneft Service) were sent to help with the emergency oil spill response.

IMO meeting eliminates doubts over 2020 delay – – If any doubts remained that the International Maritime Organization’s tighter sulfur emission limits for ships in 2020 could be delayed or otherwise watered down, those doubts should have been laid to rest at a key committee meeting of the UN body last week. The IMO’s global marine fuels sulfur limit is set to drop from 3.5% to 0.5% at the start of 2020, forcing ship operators to use cleaner, more expensive alternatives to heavy fuel oil and bringing wide-ranging other consequences for commodity markets. S&P Global Platts Analytics forecasts a shift of approximately 3 million b/d of marine demand from high sulfur fuel oil to lower sulfur alternatives, and a significant jump in crude prices as refiners increase runs to maximize middle distillate output to meet the new demand. The January 1, 2020 implementation date for the new sulfur limit was decided two years ago, but doubts have repeatedly surfaced since then about whether it would be met, or could be postponed or phased in in a more relaxed manner. Those doubts were given another outing at a meeting of the IMO’s Marine Environment Protection Committee (MEPC) last week. A Wall Street Journal story on October 19 raised the prospect of the US putting obstacles in the way of the sulfur cap, quoting a White House source as saying the Trump administration would seek to “mitigate the impact of precipitous fuel cost increases on consumers.” The oil market reacted as if the Trump administration was opposing the lower sulfur cap outright: the 2020 hi-low fuel oil swap narrowed significantly on the morning of October 19, showing reduced expectations of a large-scale shift in marine demand that year.

Thousands of ships could dump pollutants at sea to avoid dirty fuel ban –Thousands of ships are set to install “emissions cheat” systems that pump pollutants into the ocean to beat new international rules banning dirty fuel. The global shipping fleet is rushing to meet a 2020 deadline imposed by the International Maritime Organization (IMO) to reduce air pollution by forcing vessels to use cleaner fuel with a lower sulphur content of 0.5%, compared with 3.5% as currently used. The move comes after growing concerns about the health impacts of shipping emissions. A report in Nature this year said 400,000 premature deaths a year are caused by emissions from dirty shipping fuel, which also account for 14 million childhood asthma cases per year. But the move to cleaner fuel could see harmful pollutants increasingly dumped at sea. According to industry analysis seen by the Guardian, between 2,300 and 4,500 ships are likely to install an exhaust gas cleaning system known as a scrubber to meet the regulations on low-sulphur fuel instead of buying the more expensive clean fuel. The scrubbers allow ship owners to continue buying cheaper high-sulphur fuel, which is washed onboard in the scrubber. In the case of the most used system, known as open loop, the waste water is discharged into the ocean. Although expensive at around $2-4m per ship fitting, the cost of buying and fitting a scrubber would be recovered in the first year, the industry analysis says. Cleaner low-sulphur fuel is likely to cost between $300 and $500 more a tonne, according to analysts. Ned Molloy, an independent shipping analyst, said that although the scrubbers were allowed by the IMO as a way to meet the lower-sulphur emissions rules, they were little more than an “environmental dodge”. Molloy said the scrubbers that had so far been fitted on the global fleet in advance of the 2020 deadline were mostly open-loop systems, which discharge into the sea, rather than the more expensive closed-loop systems, which require storage of waste water to be discharged into a facility on shore.

Pakistan works to contain oil spill near Karachi – AP News – Authorities in Pakistan have launched an operation to contain an oil spill that has damaged about 1.5 kilometers (nearly 1 mile) of coastline near the southern port city of Karachi. Moazzam Khan, of the Word Wildlife Fund, said Sunday that traces of oil have been found across an 8-kilometer (5-mile) stretch, endangering marine life. Residents suspect the oil leaked from an underwater pipeline at a nearby refinery. Mohammad Abid, of the Pakistan Maritime Security Agency, said two trails of oil can be seen from the air, but that the source is unknown. The refinery denied it was the source of the spill, but suspended operations after been ordered to do so by local authorities.

Damages from massive 2014 oil spill amount to NIS 281 million – The Environmental Protection Ministry said Sunday damages from a 2014 oil spill in southern Israel, considered to be the worst ecological disaster in the country’s history, totaled NIS 281 million ($75 million). According to the ministry, some 5 million liters of crude oil were spilled in December 2014 when a pipeline belonging to state-owned Eilat Ashkelon Pipeline Company (EAPC) ruptured, causing significant environmental damage to the Arava desert and Evrona Nature Reserve. The ministry’s announcement on the cost of the damages was included in a legal opinion it had ordered as part of mediation proceedings on the oil spill. “This opinion is a direct continuation of the ministry’s policies, according to which harming nature has a price, and therefore it must be ensured that companies that fail to protect the environment will fully bear the damages caused to the environment and the public,” the ministry said in a statement. The total damages included NIS 65 million ($17 million) in rehabilitation costs and NIS 216 million ($58 million) in compensation for the environmental damages, according to the ministry, the former of which was already paid by EAPC as part of clean-up efforts. The ministry said a criminal investigation has also been underway, but did not indicate who is suspected.

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