Oil, Gas, And Fracking News Reads: 06January, 2019 – Part 1

Written by rjs, MarketWatch 666

Here are some selected new articles from the week ended 06 January 2019.

This article is a feature every Monday evening on GEI.

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Natural gas prices see steepest monthly drop in 15 years; Christmas week natural gas withdrawal is smallest in 13 years

Oil prices rebounded into the new year, rising every day this week, largely on news of a drop in OPEC output and hints of progress on resolving the U.S.-China trade imbroglio…after falling 0.6% to $45.33 a barrel in volatile trading that saw prices drop as low as $42.36 a barrel last week, prices of US oil for February delivery initially rallied nearly 2% on Monday on comments from both the US and Chinese presidents indicating progress in trade talks, but later fell back to close with a gain of just 8 cents at $45.41 a barrel, thus ending 2018 down nearly 25 percent, the first annual decline since 2015…after opening the new year higher, oil prices then slid to as low as $44.35 on Wednesday morning, before staging a rally that lifted prices from near session lows of $44.50 to $46.50 in the matter of a minute, likely on a report that OPEC’s oil output plunged by the most in almost two years, and then rose to as high as $47.78 a barrel, before falling back to settle with a gain for the day of $1.13 at $46.54 a barrel, weighed down by concerns of a slowing global economy…oil prices were higher again in choppy trade on Thursday, first rising to $47.49 and then falling back to $45.35, before ending with a gain of 55 cents at $47.09 a barrel, as concerns about slowing economic growth and a glut of crude were offset by Saudi output cuts and weakness in the US dollar…oil prices rose to as high as $49.22 a barrel on Friday, supported by a drop in the oil rig count, on news that vice-ministerial trade talks between the US and China had been scheduled for next week, but again fell back late to close with a gain of just 87 cents at $47.96 a barrel, with gains capped by an EIA report of large increases in refined product inventories…US oil prices thus ended 5.8% higher on the week, their biggest weekly increase since August, while the international benchmark of Brent crude for March ended the week $3.85 or 7.2% higher at $57.06, its largest gain in more than two years…

Meanwhile, natural gas prices fell for the 5th week in a row as warm weather persisted and the the EIA reported the smallest Christmas week withdrawal in the modern record…prices of natural gas for February delivery fell 36.3 cents to $2.94 per mmBTU on Monday, trading below $3 per mmBTU for the first time since September…hence, natural gas finished the month of December down 36.3%, the sharpest monthly drop since March of 2003, and yes, a 36.3 cent drop on Monday did result in prices 36.3% lower than a month earlier…natural gas prices were then pretty much flat over the first two trading days of the new year, inching up 1.8 cents on Wednesday, but falling back 1.3 cents on Thursday, before rallying 9.9 cents or 3.3% on Friday to close the week at $3.044 per mmBTU, on the risk of colder weather come the 3rd week of January…

With that nearly historic drop in natural gas prices, we’ll include a graph of the recent price trajectory, to show you what that looked like..

The above graph is a Saturday afternoon screenshot of the interactive US natural gas price graph at Daily FX, an online platform that provides trading news, charts, indicators and analysis of the markets…each bar on the above graph represents natural gas prices for a day of trading between mid August of 2018 and Friday of this week, wherein the green bars represent the days when the price of natural gas went up, and red bars represent the days when the price of natural gas went down…for green bars, the starting natural gas price at the beginning of the day is at the bottom of the bar and the price at the end of the day is at the top of the bar, while for red or down days, the starting price is at the top of the bar and the price at the end of the day is at the bottom of the bar…also visible on this “candlestick” style graph are the faint grey “wicks” above and below each bar, to indicate trading prices during the day that were above or below the opening to closing price range for that day…you can see that before October, natural gas prices had stayed below $3 per mmBTU, and it was only when the possibility of a wintertime natural gas shortage became widely known that prices began to move higher…then prices shot up to nearly $5 when November turned cold, and withdrawals of gas from storage were much above normal…now, with the milder temperatures and smaller withdrawals from storage of the past few weeks, the natural gas traders are thinking that the crisis has past, and hence natural gas prices have fallen back to their previous baseline…

The natural gas storage report for the week ending December 28th from the EIA showed that the quantity of natural gas in storage in the US fell by 20 billion cubic feet to 2,705 billion cubic feet over the week, which left our gas supplies 450 billion cubic feet, or 14.3% below the 3,155 billion cubic feet that were in storage on December 29th of last year, and 560 billion cubic feet, or 17.2% below the five-year average of 3,265 billion cubic feet of natural gas that are typically in storage going into the last weekend of December….this week’s 20 billion cubic feet withdrawal from US natural gas supplies was much less than the 44 billion cubic feet to 47 billion cubic feet withdrawal that major surveys had forecast, and it was way below the average of 107 billion cubic feet of natural gas that have been withdrawn from US gas storage during the fourth week of December in the last 5 years…at it turns out, this week’s withdrawal was also the smallest Christmas week withdrawal since 2005..

For a visualization of what this week’s natural gas withdrawal looks like historically, we have a graphic showing this year’s weekly change in natural gas inventories as compared to last year’s and to the long term averages:

The above graph was copied from a blog post at Bespoke Weather that was published on Friday of this week, shortly after the holiday postponed release of the natural gas storage report…on this graph, the dark blue graph shows this year’s weekly additions to natural gas storage in billions of cubic feet above the zero line, and this year’s weekly withdrawals from natural gas storage in billions of cubic feet below the zero line; similarly, weekly additions and withdrawals of natural gas in 2017 are shown in red, the 5 year average weekly change of natural gas in storage is shown in green, and the historical average weekly change of natural gas supplies in EIA data going back to 1992 is shown in orange…at the far left, you can see the record withdrawal of 359 billion of cubic feet during the first week in January of this year, and a withdrawal of 288 billion cubic feet during the third week of January 2018 that would have also been a record withdrawal if not for the first week; those 2 big withdrawals thus dropped our natural gas supplies to 17.5% below normal to start the year, a deficit which persisted throughout the summer, despite near normal additions to storage….in the week ending November 16th, you can see the big blue spike down that represented the largest drop in our supplies ever in mid-November, which came after our natural gas supplies had already started the winter at a 15 year low…then, two weeks ago, there was also a large withdrawal, but as you can see, by that time the 5 year average withdrawal was already near that level for mid-December…now we have had two much smaller than normal withdrawals of gas from storage, with this recent week showing the smallest Christmas-week withdrawal since 2005; contrast that with Christmas week of last year (shown in red), when 193 billion cubic feet of natural gas were needed from storage to meet demand…while the past two weeks of low withdrawals have certainly taken the pressure off supplies, we aren’t completely out of the woods yet, since our gas stores are still more than 17% below recent averages, but barring a real frigid January, we should be able to make it through the winter with the supplies we now have on hand..

The Latest US Oil Supply and Disposition Data from the EIA

This week’s US oil data from the US Energy Information Administration, reporting on the week ending December 28th, indicated a big pickup in oil refining coupled with a modest decrease in our oil imports and a big drop in our oil exports, which together meant our commercial crude supplies remained statistically unchanged for the second week in a row…our imports of crude oil fell by an average of 264,000 barrels per day to an average of 7,392,000 barrels per day, after rising by an average of 233,000 barrels per day the prior week, while our exports of crude oil fell by an average of 732,000 barrels per day to an average of 2,237,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 5,155,000 barrels of per day during the week ending December 28th, 468,000 more 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 unchanged at 11,700,000 barrels per day, so our daily supply of oil from the net of our trade in oil and from wells totaled an average of 16,855,000 barrels per day during this reporting week…

Meanwhile, US oil refineries were using 17,760,000 barrels of crude per day during the week ending December 28th, 410,000 barrels per day more than the amount of oil they used during the prior week, while over the same period 1,000 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 906,000 barrels per day short of what refineries reported they used during the week plus what was added to storage….to account for that disparity between the supply of oil and the disposition of it, the EIA inserted a (+906,000) 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”…with our unaccounted for crude as high as 906,000 barrels per day, all of this week’s oil supply and disposition figures that we have cited must therefore be considered questionable…(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 rose to an average of 7,466,000 barrels per day, but was still 4.1% less than the 7,789,000 barrel per day average that we were importing over the same four-week period last year….the 1,000 barrel per day increase in our total crude inventories was due to a 1,000 barrel per day addition to our commercially available stocks of crude oil, since the oil stored in our Strategic Petroleum Reserve remained unchanged….this week’s crude oil production was reported unchanged at 11,700,000 barrels per day because the rounded figure for output from wells in the lower 48 states was unchanged at 11,200,000 barrels per day, while a 2,000 barrel per day decrease to 495,000 barrels per day in oil output from Alaska was not enough to change the rounded national total…last year’s US crude oil production for the week ending December 29th was at 9,782,000 barrels per day, so this week’s rounded oil production figure was 19.6% above that of a year ago, and 38.8% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016…

US oil refineries were operating at 97.2% of their capacity in using those 17,760,000 barrels of crude per day during the week ending December 28th, up from last week’s 95.1% of capacity, and the highest December capacity utilization rate on record….the 17,760,000 barrels per day of oil that were refined this week were thus again at a seasonal high for the time of year for the 27th time out of the past 31 weeks, and 0.9% higher than the previous December high of 17,608,000 barrels of crude per day that were being processed during the week ending December 29th, 2017, when US refineries were operating at 96.7% of capacity… …

Despite the increase in the amount of oil being refined, the gasoline output from our refineries was much lower, decreasing by 611,000 barrels per day to 9,533,000 barrels per day during the week ending December 28th, after our refineries’ gasoline output had decreased by 190,000 barrels per day during the week ending December 21st…with that decrease in this week’s gasoline output, our gasoline production during the week was 1.5% lower than the 9,682,000 barrels of gasoline that were being produced daily during the same week last year….at the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 147,000 barrels per day to 5,591,000 barrels per day, after that output had increased by 51,000 barrels per day the prior week….with that increase, this week’s distillates production virtually equal to the the 5,592,000 barrels of distillates per day that were being produced during the week ending December 29th, 2017….

Even with the pullback in our gasoline production, our supply of gasoline in storage at the end of the week increased by 6,890,000 barrels to 239,996,000 barrels by December 28th, the 6th increase in the past 11 weeks, and enough to finally lift our gasoline supplies back above those of early October….our gasoline supplies rose this week because the amount of gasoline supplied to US markets fell by 725,000 barrels per day to 8,623,000 barrels per day while our exports of gasoline rose by 21,000 barrels per day to 872,000 barrels per day and our imports of gasoline fell by 195,000 barrels per day to 314,000 barrels…with this week’s increase, our gasoline inventories are again at a seasonal high for anytime in December, 2.9% higher than last December 29th’s level of 233,187,000 barrels, and roughly 5% above the five year average of our gasoline supplies for this time of the year…

With the near record production of distillates, our supplies of distillate fuels increased for just the 4th time in fifteen weeks, rising by 9,529,000 barrels to 129,431,000 barrels during the week ending December 28th, after our distillates supplies had increased by a statistically insignificant 2,000 barrels during the prior week…our distillates supplies increased because the amount of distillates supplied to US markets, a proxy for our domestic demand, fell by 1,039,000 barrels per day to 3,203,000 barrels per day (after falling by 644,000 barrels per day the prior week), and because our exports of distillates fell by 184,000 barrels per day to 1,222,000 barrels per day, while our imports of distillates fell by 9,000 barrels per day to 195,000 barrels per day….but despite this week’s big increase, our distillate supplies finished the week 6.8% below the 138,834,000 barrels that we had stored on December 29th, 2017, and remained 7% below the five year average of distillates stocks for this time of the year…

Finally, with the week’s big drop in oil exports largely offset by lower imports and increased refining, our commercial supplies of crude oil rose by a statistically insignificant 7,000 barrels to 441,418,000 barrels on December 28th, from 441,411,000 barrels on December 21st, the first increase in 5 weeks but the 27th ‘up’ week of 2018….with our increases for the year now greater than our decreases, our crude oil inventories were thus roughly 8% above the five-year average of crude oil supplies for this time of year, and over 28% above the 10 year average of crude oil stocks for the last week of December, 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 this Fall, our oil supplies as of December 28th were only 4.0% above the 424,463,000 barrels of oil we had stored on December 29th of 2017, and remained 7.8% below the 479,012,000 barrels of oil that we had in storage on December 30th of 2016, and 2.1% below the 450,956,000 barrels of oil we had in storage on January 1st of 2015..

This Week’s Rig Count

US drilling activity decreased for the fifth time in seven weeks during the week ending January 4th, as drilling for oil has stagnated in light of depressed oil prices and a 6.7 month backlog of uncompleted wells… Baker Hughes reported that the total count of rotary rigs running in the US decreased by 8 rigs to 1075 rigs over the week ending January 4th, which was still 151 more rigs than the 924 rigs that were in use as of the January 5th report of 2018, but down from the shale era high of 1929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC announced their attempt to flood the global oil market…

The count of rigs drilling for oil fell by 8 rigs to 877 rigs this week, which was still 135 more oil rigs than were running a year ago, while it remained 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 bearing formations was unchanged at 198 natural gas rigs, which was still 16 more rigs than the 182 natural gas rigs that were drilling a year ago, but way down from the modern high of 1,606 natural gas targeting rigs that were deployed on August 29th, 2008…

Two of the rigs that were shut down this week had been drilling from platforms in the Gulf of Mexico, which reduced the Gulf of Mexico rig count to 22 rigs for the week, which was still 5 rigs more than the 17 rigs deployed in the Gulf of Mexico a year ago at this time…since there is no other offshore drilling off either coast or off Alaska at this time, nor was there during the same week of 2017-18, those Gulf of Mexico totals are identical to the US totals..

The count of active horizontal drilling rigs remained unchanged at 945 horizontal rigs this week, which was still 147 more horizontal rigs than the 798 horizontal rigs that were in use in the US on January 5th of last year, but down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014….on the other hand, the vertical rig count decreased by 4 rig to 64 vertical rigs this week, which was still up from the 62 vertical rigs that were in use during the same week of last year…at the same time, the directional rig count also decreased by 4 rigs to 66 directional rigs this week, which was still up from the 64 directional rigs that were operating on January 5th of 2018…

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 January 4th, the second column shows the change in the number of working rigs between last week’s count (December 28th) and this week’s (January 4th) count, the third column shows last week’s December 28th 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 the 5th of January, 2018…

In addition to the major producing states shown above, Mississippi also saw 4 rigs shut down this week, leaving 2 rigs active in the state, their lowest count since last January 12th…those 4 from Mississippi, and the 5 rigs pulled out of California, pretty much account for this week’s decrease (the 2 Gulf of Mexico rigs that were shut down come out of Louisiana’s count)…otherwise, i don’t see anything that’s hidden in this table, such as a “no change” masking a gas rig being swapped out for an oil rig, so what the table indicates this week is pretty much what happened…since the basin count above shows an increase of two rigs while the horizontal rig count was unchanged, two horizontal rigs had to have been pulled out of basins not tracked separately by Baker Hughes, such as those in California and Mississippi…then there were also 8 more rigs, 4 vertical and 4 directional, pulled out of those “other” basins not tracked separately by Baker Hughes, for a net decrease of 10 rigs in “other basins”….and all of those changes, including those shown above, were oil rigs; there were no changes to gas rig counts in any state…

AEP wants to change Stark-Carroll project – AEP Ohio Transmission is rebuilding power line from Carrollton to Canton Twp. An AEP Ohio affiliate wants to modify its plan to rebuild a century-old power line between Canton Township and Carrollton. AEP Ohio Transmission Co. started to rebuild the nearly 20-mile-long transmission line in December 2017. The company is spending $50 million to replace the original steel-lattice towers and copper conductor, built in 1916, with steel poles about 120 feet tall and a new conductor. The transmission line crosses Sandy, Osnaburg and Canton townships in Stark County and Brown, Center and Harrison townships in Carroll County and spans the southern end of Lake Mohawk. The original towers and conductor are far past their original life expectancy and need to be replaced to ensure reliable service. The transmission line brings power from the Ohio River to Canton and is in an area that has seen greater power demand due to Utica Shale processing plants and pipeline compressor stations, according to the company. On Dec. 28, AEP Ohio Transmission Co. asked the Ohio Power Siting Board for permission to modify the project due to engineering considerations and property-owner preferences.

Citizens need to know facts about injection well company – Roxanne Groff – As a service to citizens, it is necessary to provide facts in response to your Dec. 20, 2018, news article, “Injection Rejection – Citizens Make Passionate Case Against Injection Wells”, about the Dec. 18 public hearing hosted by the Athens County Commissioners. Requested by Athens County Fracking Action Network, the hearing allowed citizens to comment on Jeff Harper’s application to the Ohio Department of Natural Resources for a massive fourth injection well at his K&H facility adjacent to Torch, Ohio. Your article quoted extensive pre-hearing statements by Mr. Harper about the three injection wells already receiving toxic radioactive frack waste at the facility. Since confirmation of assertions by the operator of an industrial facility of extreme concern to our community is essential and since the article lacked any such confirmation, I did my own fact checking. Public testimony at the public hearing addressed many areas of concern, including: 1) harm from current air pollution; 2) harm from potential water contamination; and 3) harm from seismicity and potential earthquakes induced by injection. The results of my inquiries follow, with quotes from your article.

Fracking hub could harm our water – Cincinnati.com — This November, while most of us were focused on election results, the U.S. Department of Energy (DOE) published a report to Congress on “the feasibility of establishing an ethane storage and distribution hub in the United States.” The proposed “hub,” referred to by its acronym ASTH, would include “hundreds of miles of pipelines, fracked gas processing facilities, and underground storage of petrochemicals and fracked gas liquids… [stretching] along the Ohio-West Virginia border from Pennsylvania to Kentucky along the Ohio River.” The report has been accepted, and Congress has given the go-ahead to begin work on this massive infrastructure project.Why should Cincinnatians care about this? The Ohio River, which constitutes one of the “spokes” of the proposed hub, provides the region with 88 percent of its drinking water. Fracking produces massive quantities of radioactive waste water which may well make its way into our river. And legal protections that have prevented companies from dumping waste into the river for over four decades have recently been repealed.That means Cincinnati drinking water may soon be subject to pollutants leftover from natural gas extraction.Other people have reported on the Ohio River Valley Water Sanitation Commission’s (ORSANCO) decreasing standards for Ohio River water quality. The Ohio River is a notoriously polluted body of water, and has been for a long time. But the Appalachian Storage and Trading Hub poses a new threat in its scale.

Shale gas production in up Pennsylvania – Shale gas production in Pennsylvania increased 12.9 percent over the first three quarters of this year, compared with the first nine months of 2017. Washington and Greene were the second- and third-most productive counties, respectively, according to data from the state Department of Environmental Protection. DEP reported Susquehanna County, in the northeastern quadrant of the state, was first with 1.07 billion McF of natural gas from 1,352 active wells. (One McF equals 1,000 cubic feet.) Susquehanna, bordering New York state, was a prolific producer, accounting for nearly one-fourth of the commonwealth’s 4.47 billion McF. The two southwesternmost counties weren’t far behind, though. Washington produced 862.4 million McF through September, a 27.2 percent bump year over the year before. More specifically, that was an increase of 184.4 million McF from the three-quarters point of last year. Washington had more active wells – 1,493 – than any county, a 14.1 jump from 1,308. Greene ended the third quarter with 560.7 million McF, a rise of 12.9 percent from the same period of 2017. The county had 1,066 active wells through September, a 14 percent rise. Those three were among nine counties that topped 100 million McF of production during the period. Filling out the top 10, production-wise, were: Bradford, Wyoming, Lycoming, Tioga, Butler, Sullivan and Allegheny. Westmoreland was 11th, Fayette 12th and Beaver 16th.

Too big to fail: How one gas company can leave a mark on Pennsylvania – Diversified Gas & Oil PLC may be the largest operator of old oil and gas wells in the country. Another way of saying that is the Alabama-based company might have the most responsibility for plugging wells across Appalachia. That’s not lost on Pennsylvania regulators. On July 25, the state Department of Environmental Protection announced that it had ordered three companies – Alliance Petroleum Corp., XTO Energy Inc. and CNX Gas Co. – to plug 1,058 abandoned wells statewide after production records showed the wells had not produced any oil or gas for a year. The agency didn’t spell out a key detail: Nearly all of those unproductive wells are now owned by Diversified, which has grown at a breakneck pace over the past year – swallowing up smaller companies and picking up shallow gas assets that the company has referred to as “unloved” and “forgotten” by big shale drillers. Diversified is following a strategy of keeping the conventional wells active as long as possible without drilling new ones – counting on its volume and efficiency to allow it to profit on the fuel production that others have abandoned. And Pennsylvania is increasingly alarmed that, once the wells have been wrung dry, the cost of plugging all of them might overwhelm the company and land in the state’s lap. The state has never before faced such a concentration of liabilities in one company. Diversified now controls more than 50,000 wells. About 24,000 of those are in Pennsylvania. To put that into perspective, in the decade between 2006 and 2016, no one operator had more than 5,700 conventional wells at the same in the state. Mr. Hutson said Diversified has “an active plugging program that’s in place constantly year to year,” and that the company can plug wells in the average range of $8,000 to $10,000 a piece. The high end would be $25,000, he said. Diversified’s numbers are the most optimistic of a variety of sources, which include local conventional and shale gas producers, regulators and plugging companies.“If wells are [shallow and] in good condition, it could be $8,000 to $10,000 a well,” said Mark Cline, who runs Cline Oil in Bradford, Pa., and serves as president of the association of Pennsylvania Independent Petroleum Producers. His company was just quoted a price of $33,000 a well to plug some 3,000-foot-deep holes.Plugging a well means cleaning out the wellbore, removing uncemented pipe and debris, and filling it with cement. How much that costs depends on a number of factors, including the age of the well – one that has been sitting around unserviced for many years is more likely to be in worse shape – the depth, and whether it has an access road to get equipment to the site.

Natural gas pipeline now online, path goes through Cumberland County – The liquid natural gas pipeline that traverses underground through the state, cutting through Cumberland County, is now in operation.Energy Transfer announced Saturday that the Mariner East 2 pipeline is in service.According to the company, the 350-mile pipeline transports domestically-produced ethane, propane and butane east from processing plants in Ohio, across West Virginia and Pennsylvania to Energy Transfer’s Marcus Hook Industrial Complex in Delaware County, where its stored for distribution locally, domestically and overseas.The Mariner East 2X pipeline, which parallels the Mariner East 2, is expected to be in service by late 2019.According to the company, the total impact from construction of the pipelines is estimated to be more than $9.1 billion in Pennsylvania, providing more than 9,500 construction jobs over six years.Through construction, it has been the source of some controversy locally and around the state. Chester County District Attorney Tom Hogan announced earlier this month he opened a criminal investigation into construction of the pipeline that has drawn blame for causing sinkholes and polluting drinking water and waterways, The Associated Press reports. In August, state officials levied a $148,000 fine against the company for harming private wells while building the Mariner East 2 pipeline in Lebanon, Berks and Chester counties.

After years of legal battles, natural gas pipeline spanning Pa. is officially in service – Following years of legal battles and state-mandated shutdowns, Sunoco’s Mariner East 2 pipeline officially began service Saturday, according to a news release from its parent company, Energy Transfer LP of Dallas, Texas.The 350-mile pipeline transports domestically produced ethane, propane and butane from processing plants in Ohio across West Virginia and Pennsylvania to Energy Transfer’s Marcus Hook Industrial Complex in Delaware County. The news comes shortly after a county prosecutor in Pennsylvania announced he would be opening up a criminal investigation into the construction of the pipeline, looking for potential crimes including causing or risking a catastrophe, environmental violations and corrupt organizations.The Mariner East 2X pipeline, which runs parallel to Mariner East 2, is expected to be in service late 2019. Lisa Dillinger, Energy Transfer spokeswoman, said the Mariner East project is anticipated to create more than 9,500 construction-related jobs a year during construction, and between 360 to 530 permanent jobs.

‘Frankenpipe?’ Critics take aim at Sunoco’s hybrid Mariner East 2 – Sunoco/Energy Transfer has named the long-delayed pipeline, which went online Saturday and started shipping highly volatile liquid gases to a facility in Marcus Hook Mariner East 2. But that’s being disputed by the project’s critics, who maintain that while the original plan for a 20-inch pipeline was called Mariner East 2, they have a few other names for what now appears to be a mish-mash of three pipelines or what Sunoco says is a “work-around” of 12-inch, 16 inch and 20 inch pipelines is known as the Mariner East 2. Some critics call it the “Dragonpipe,” while others prefer “Frankenpipe.” Nevertheless, the multi-billion dollar project is now in fact delivering product while spanning the entire width of Pennsylvania, starting in Ohio and winding up in Marcus Hook. The original 20-inch Mariner East 2 pipeline is mostly complete and carries the product through much of the state. Butane, ethane and propane, in places, flow along the 16-inch pipe or what was originally called the Mariner East 2X. An 80-year-old 12-inch pipe bypasses about 23 miles of pipe, much of it incomplete, in Chester County and reconnects with the original Mariner East 2 in Delaware County. The pipeline travels 11 miles through Delaware County where Sunoco has been unable to finish work on the original Mariner East 2 pipeline. “This cobbled together 12-inch line, if the allegations are true, has much uncertainty as to its ability to safely transport these products,” Casey said. “But for Sunoco to pull a bait-and-switch to now call this pipeline ‘Mariner’ does a disservice to the intelligence of state regulators.

Mariner East startup renews safety fears for some residents in Delaware County – Homeowners focus on integrity of repurposed 12-inch pipeline first built in 1930s – Lora Snyder was already worried about plans for a natural gas liquids pipeline going past her Delaware County property, but now that the pipeline has started operating, she’s thinking it’s time to sell and move away. The 12-inch pipe, a repurposed gasoline line originally built in the 1930s, has leaked at least twice before, and Snyder predicts that it will do so again – despite a $30 million upgrade in 2016, according to Sunoco – with potentially catastrophic consequences. “Our real concern here is that the 12-inch has leaked at least two times that we know of in Edgmont,” said Snyder, 50, in an interview at her home. “I’m fearful. I don’t know how I will sleep at night, truthfully, because of the history of the pipe. The chances are pretty good that we will see another leak soon. Now we have to worry about being blown up.” Critics’ concerns were renewed over the weekend of Dec. 29-30 when the whole cross-state pipeline finally began pumping ethane, propane and butane after many delays caused by regulatory shutdowns and technical problems during its almost two-year construction. Sunoco said in a statement on Saturday that the pipeline “is in service” effective that day. The startup meets the company’s latest target of beginning operation by the end of 2018.After hoping that the project would hit yet another roadblock, critics began to focus on the reality of living with a pipeline that they say could cause mass casualties if it leaks and explodes highly volatile liquids in a densely populated area like Delaware County. An independent assessment for Delaware County Council said in December that a worst-case rupture of the pipe would kill anyone within about a mile, but that the chance of that happening were less than that of someone dying in a car crash.

Lawmakers introduce comprehensive pipeline legislative package — State Sens. Andy Dinniman, D-19, and Tom Killion, R-9, announced Wednesday that they have introduced a comprehensive legislative package aimed at reforming Pennsylvania’s pipeline regulatory process to improve safety at schools and in local neighborhoods and communities. “For years, I’ve been working to protect our communities from the potential safety risks of the Mariner East pipeline project. Along the way, I’ve identified several areas that are in dire need of improvement in the Commonwealth,” Dinniman said. “These bills are a result of that ongoing effort and a necessary starting point to refocus and re-energize our efforts in the new year. I am committed to working in the spirit of bipartisanship and for the sake of Chester County residents and families to achieve real and lasting pipeline safety reform in the 2019-2020 legislative session.” “Pipelines are transporting highly flammable and toxic materials under high pressure through densely populated areas. Having new laws in place to ensure the safety of families living in pipeline communities is long overdue,” Killion said. “I look forward to working with Senator Dinniman on passing these bills. Pipeline industry oversight and public safety are top concerns for our constituents, and I’m pleased to be partnering with him on these important issues.” The bipartisan package consists of 12 bills, six sponsored by Dinniman and six sponsored by Killion. Both senators also serve as first prime co-sponsor of each other’s bills. They are as follows:

Pa. PUC prepares to collect millions in past impact fees after ‘stripper well’ ruling – About 17 natural gas companies are expected to get invoices early this year for millions of dollars of impact fees they owe on low-producing shale wells following a state Supreme Court decision last week.The Pennsylvania Public Utility Commission is in the process of generating invoices for shale gas producers who disputed and did not pay impact fees on some wells in recent years based on a legal debate about what counts as a “stripper well” that is exempt from the annual fees.Judges disagreed about whether a well had to produce more than 90,000 cubic feet of natural gas per day for one month of the year – or every month of the year – for the fee to be imposed.The state Supreme Court settled the debate on Dec. 28, ruling that only wells that fall below the production threshold every month of the year can be considered stripper wells.The decision confirmed the PUC’s interpretation but was a blow to Armstrong County-based natural gas producer Snyder Brothers Inc. and the Pennsylvania Independent Oil and Gas Association, which had argued that the law’s exemption for stripper wells was more expansive.Now the PUC is readying to collect fees that were left in limbo during the years-long case.“We estimate that the recent Pa. Supreme Court decision will involve hundreds of wells with outstanding impact fees totaling millions of dollars,” PUC spokesman Nils Hagen-Frederiksen said. The agency does not yet have precise figures.Last June, Mr. Hagen-Frederiksen said 17 producers disputed that they owed fees on more than 300 wells due to the stripper well debate. That reduced the impact fee collection for 2017 by $6.1 million.Producers disputed impact fees on 160 wells for 2016 and 35 wells for 2015, according to PUC records, although it is not clear if all of those disputes had to do with the stripper well definition. PIOGA general counsel Kevin Moody said producers who agreed with the association’s interpretation of the stripper well definition had little choice but to withhold fees for their disputed wells while the case was being considered, because the law does not allow for refunds once fees are paid.

State of New Jersey continues fight against PennEast pipeline – Last month, Federal Judge Brian Martinotti ruled the PennEast Pipeline project will benefit the public and allowed the project to proceed in the Garden State. On Friday, State Attorney General Gurbir Grewal asked the feds to reconsider the ruling arguing the state has “sovereign immunity” from eminent domain under the 11th Amendment. Tom Gilbert with the New Jersey Conservation Foundation is pleased with the the attorney general’s continued pursuit. “It shows they’re obviously taking their responsibility for those lands very seriously,” said Gilbert. Two weeks ago, Gilbert led a group of elected officials and property owners in protest of the federal court’s decision at a resident’s home in Hopewell Township, Mercer County. That home sits right in the middle of where the proposed pipeline would be. The pipeline would push a billion cubic feet of natural gas a day through Pennsylvania and New Jersey. But before it can begin construction, PennEast needs approval from both states. “No matter what the outcome here, we know that PennEast has a very, very long way to go,” said Gilbert. Grewal has requested a hearing on the matter for later this month. In response to the filing, a PennEast spokesperson said “We are reviewing the State’s motions, but are very confident in the well-reasoned and sound rulings from Judge Martinotti.”

Orphan Wells: States Wrestle With Soaring Costs For Oil & Gas Industry Mess – WOUB – Across the country, many state regulators have few resources to deal with an ever expanding list of abandoned wells. “The states are pretty good at regulating wells that are being explored, are being fracked, are in production, but they kind of lose interest once that happens,” said Alan Krupnick, a senior fellow with the nonpartisan environmental think tank, Resources For the Future. “There’s not enough attention being paid to reducing the risk from these abandoned wells.”Across the Ohio Valley, thousands of oil and gas wells sit idle. An analysis of state data by the Ohio Valley ReSource estimates more than 8,000 oil and gas wells are considered “orphan.” Definitions of orphan and abandoned wells vary by state, but in general, orphan wells lack an operator or company that can pay to plug them. That responsibility then falls to state regulators who are frequently struggling to keep up with demand and scrambling to find money to clean up the mess.. Recent legislation passed in Ohio and West Virginia funnels more money toward plugging orphan wells. In Kentucky and West Virginia, agencies tasked with plugging those wells rely on forfeited bonds. That money is collected in a fund and used to plug the highest priority wells. Well plugging can be an expensive undertaking. Across the Ohio Valley, regulators reported figures as low as a few thousand to upwards of $200,000 to plug a single well. “We may have an emergency repair on a big well and we may have had bonds forfeited on several small wells and those funds just don’t add up,” said Lanny Brannock, a spokesperson with the Kentucky Energy and Environment Cabinet. “So, we’re constantly behind on funding for orphan wells.” Since 2012, Kentucky has plugged 33 wells and has about $950,000 in an orphan well fund. West Virginia’s funding situation is similar. Since 2012, the state has plugged seven wells. The West Virginia Department of Environmental Protection can use a portion of each $150 well work permit application fee as well as any forfeited bonds to plug orphan wells.

PSC gives OK to gas pipeline into Jefferson – After getting hundreds of comments from citizens opposed to Mountaineer Gas Co.’s extending a natural gas pipeline into Jefferson County, the West Virginia Public Service Commission has given the project the green light. The PCS’s decision clears the way for Mountaineer to lay gas lines from Martinsburg to Charles Town, with service to the Rockwool insulation factory site in Ranson along with future commercial and residential customers. The PSC called Mountaineer’s $16.5 million service expansion plans in the Eastern Panhandle “reasonable and in the public interest.” The agency’s approval of Jefferson County gas service involved a five-year, nearly $120 million expansion plans and system upgrades that Mountaineer will pursue across West Virginia. In announcing the move, the PSC acknowledged numerous written and oral public comments filed to oppose the extension. While calling the public concerns over gas service “sincere and deeply held,” the PSC stated the arguments presented against extending Mountaineer’s service did not address state law that directs the agency “to encourage and accommodate the extension of natural gas service to unserved and underserved areas of West Virginia.” Jefferson County households and business have no access to natural gas service. “It is undisputed that, notwithstanding the enormous amount of natural gas available in West Virginia, natural gas utility service is not yet available to many residents and businesses in the Eastern Panhandle,” the agency wrote. Jefferson County economic development officials have said offering natural gas is an important factor needed to attract new commercial and industrial operations to the county. Moses Skaff, a spokesman for Mountaineer, has said the utility has been working with Jefferson officials to bring gas service to the county since at least 2014. Many opposed to the Rockwool factory hope to prevent or delay the facility from obtaining public sewer and water service. Rockwool plans to open its 460,000-square-foot factory on Charles Town Road with natural gas service by the summer of 2020.

Pipeline company wants Elliston-area tree-sitters out – Two people face removal from trees because they are blocking the Mountain Valley Pipeline project near Elliston, a pipeline attorney said in court papers. A person who said he is one of the protesters expressed defiance Thursday. The person, who identified himself as 24-year-old Phillip Flagg, said only “if the pipeline were stopped” would he leave the tree voluntarily. He said he was speaking from about 50 feet above the ground in a chestnut oak near Yellow Finch Lane. He said he has ample supplies to stay alive, and another tree-sitter is nearby. The location is a steep slope below Poor Mountain in eastern Montgomery County, he said. Even though the project has been slowed by legal and regulatory impediments related to alleged environmental violations, Mountain Valley recently said in court papers that the company “intends to seek removal of these individuals,” calling them Tree-Sitter 1 and Tree-Sitter 2. It’s not clear from the filings whether Mountain Valley knows their names. While they don’t own any of the land involved, the tree-sitters can be sued as “persons claiming an interest in the property,” the company’s Dec. 20 filing said. “The tree sitters are occupying the property with the express purpose and intent of preventing MVP from exercising its rights under the Court’s order.” The Roanoke federal court gave Mountain Valley an easement to access the privately owned land where it intends to bury the pipe and where, according to an Appalachians Against Pipelines Facebook post, the Montgomery County tree-sitters have occupied an oak and a pine for 112 days as of Christmas. Landowner Cletus Bohon, who opposes the pipeline’s use of his property, said Thursday the tree-sitters did not seek his permission before entering his land three months ago.

Virginia Landowners Petition US Supreme Court Over Eminent Domain – – A lawsuit involving the Mountain Valley Pipeline may be headed to our nation’s highest court. Wednesday, Virginia landowners filed a reply arguing their case does have merit to be heard after non-decisions by lower courts. They want to challenge the constitutionality of eminent domain before the United States Supreme Court, arguing the system is flawed and needs re-working. It even has the backing of some conservative legal scholars. The Natural Gas Act of 1938 is the groundwork for what we now have today, the Federal Energy Regulatory Commission, otherwise known as FERC. These are the folks that authorized the Mountain Valley Pipeline to use eminent domain to build on private land. Now, the Supreme Court is deciding whether or not they’ll allow Roanoke lawyers to argue why they say the 80-year-old law is unconstitutional, which could change the rules for pipelines across the country. And in the briefing submitted Wednesday, arguing FERC and the private company should have never been given that power to begin with. There’s a real possibility the nine justices of the United States Supreme Court may soon be looking into the Mountain Valley Pipeline. “The case deals with two primary issues, both of which are essential to the preservation of individual liberty,” Gentry Locke lawyer Mia Yugo said. “The first issue is the private non-delegation doctrine and the second issue is the right to private property.” Yugo, alongside Tom Bondurant and other colleagues at Gentry Locke, are petitioning the United States Supreme Court to hear a case on whether the use of eminent domain for private pipeline companies is legal, arguing 80 years ago, Congress made a mistake with the Natural Gas Act of 1938. “So just because Congress passes a statute, doesn’t mean that Congress gets it right,” Yugo said. “And when they don’t get it right the individuals or really anybody can go into court, if you have standing, can go into court and challenge that statute as unconstitutional and that’s precisely what we’ve done.”

Supreme Court deciding whether to hear Mountain Valley Pipeline lawsuit– A lawsuit involving the Mountain Valley Pipeline may be headed to our nation’s highest court. Wednesday, Virginia landowners filed a reply arguing their case does have merit to be heard after non-decisions by lower courts. They want to challenge the constitutionality of eminent domain before the United States Supreme Court, arguing the system is flawed and needs re-working. It even has the backing of some conservative legal scholars. The Natural Gas Act of 1938 is the groundwork for what we now have today, the Federal Energy Regulatory Commission, otherwise known as FERC. These are the folks that authorized the Mountain Valley Pipeline to use eminent domain to build on private land. Now, the Supreme Court is deciding whether or not they’ll allow Roanoke lawyers to argue why they say the 80-year-old law is unconstitutional, which could change the rules for pipelines across the country. And in the briefing submitted Wednesday, arguing FERC and the private company should have never been given that power to begin with. Pipeline fighters have been giving it their all in the last three years, but their biggest accomplishments may be just around the corner. There’s a real possibility the nine justices of the United States Supreme Court may soon be looking into the Mountain Valley Pipeline. “The case deals with two primary issues, both of which are essential to the preservation of individual liberty,” Gentry Locke lawyer Mia Yugo said. “The fist issue is the private non-delegation doctrine and the second issue is the right to private property.”

As court challenges pile up, gas pipeline falls behind – Protesters banging drums may get more attention, but what has really damaged the controversial Atlantic Coast Pipeline in 2018 has been quiet action taking place in courtrooms. Opponents represented by the Southern Environmental Law Center have won a string of legal victories that have brought work on the $7 billion, 600-mile natural gas pipeline to a halt, at least temporarily. Several rulings are under appeal, while an even bigger case looms in the new year. Taken together, the federal court rulings suggest a permitting and approval process that was hasty and, possibly, misguided.“They all have the same narrative,” said D.J. Gerken, a lawyer in the SELC’s Asheville, N.C., office who has argued some of the cases. “Atlantic was very arrogant in the selection of this route . . . and counted on bullying these agencies to get it through.”The pipeline is planned to carry fracked natural gas through rugged mountain terrain and several national forests from West Virginia through central Virginia and into North Carolina. Investors still seem confident the project will move ahead, but Dominion Energy – the company spearheading the pipeline – has lately complained of painful consequences from the delays.“We’ve been forced to lay-off or delay hiring more than 4,500 construction workers on the project,” Aaron Ruby, a Dominion spokesman, said via email. “We’re confident we will ultimately prevail in the courts and be able to resume construction, but that won’t undo the hardship many working families are going through during the holiday season.” In a report to investors last month, Dominion said delays had increased the cost of the project from $6.5 billion to $7 billion and pushed its completion date from late next year into the middle of 2020.

Court declines to speed review to help with Atlantic Coast Pipeline scheduling woes – Despite Atlantic Coast Pipeline’s warnings that the current court schedule could delay the 600-mile, 1.5 Bcf/d natural gas project, a federal appeals court declined to speed the pace for briefing and oral argument for a challenge to federal endangered species permitting. ACP previously has said it paused work on nearly the entire project designed to move Appalachian shale gas to Mid-Atlantic market, after the 4th US Circuit Court of Appeals December 7 stayed the federal approvals in question while litigation proceeded. Seeking to ease the impact on the project schedule, ACP on December 14 asked the court to move up oral argument, tentatively set for March, to the end of January. It contended that time-of-year restrictions that prohibit tree felling after mid-March could mean a delay of up to a year under the current schedule for briefing and oral argument. It also told the court that the cost of stopping construction is about $20 million per week, and that significant delays could mean most of the 3,000 full-time workers in West Virginia and North Carolina would be released. But the 4th Circuit Court of Appeals December 28 denied ACP’s motion to expedite briefing and oral argument. ACP still has an outstanding request pending with the court that could help it to get back on track faster, if granted. It has asked the court to clarify that the intended scope of the stay was narrower or to reconsider the stay entirely (Defenders of Wildlife v. US Department of Interior, 18-2090). . Environmental petitioners in the case did not directly oppose ACP’s request to expedite the court schedule but have been arguing in the court docket over whether DOI and FWS have withheld important documents and failed to file a complete administrative record in the case. The environmentalists have sought to demonstrate that agency staff were pressed to cut corners in issuing permits to avoid interfering with the applicant’s project schedule. Of note, DOI and FWS have asked the court to stay all pending deadlines in light of the lapse of federal appropriations during the partial government shutdown in Washington. The case involves FWS’ biological opinion, which determines whether an action is likely to jeopardize continued existence of vulnerable species, and its incidental take statement, which specifies the amount of impacts to species allowed as a result of a project.

State lawmakers sign letter to stop proposed Western Md. pipeline – More than 50 Maryland state lawmakers signed a letter urging the Maryland Board of Public Works to reject a deal that would let TransCanada build a pipeline in Western Maryland. Columbia Gas, owned by TransCanada, hopes to build a 3-mile long distribution line near Hancock, Maryland to allow natural gas to be carried from Pennsylvania to West Virginia. TransCanada has said the construction is needed to allow economic growth in West Virginia. Opponents, including environmental groups and dozens of Maryland state lawmakers including Delegate David Moon, D-Montgomery County, worry the pipeline could threaten waterways and wetlands in the proposed right of way. A proposal for an easement to allow the project to move ahead goes before the Maryland Board of Public Works on Wednesday. The board – made up of Gov. Larry Hogan, State Treasurer Nancy Kopp and Comptroller Peter Franchot – decides all state capital appropriations, preserves and protects all submerged lands and wetlands and handles state contracts. Those who signed the letter argue that since Maryland banned fracking in 2017, it doesn’t make sense to allow a pipeline to run through the state. The pipeline would run underneath the Potomac River and cross part of the Western Maryland Rail Trail.

Hogan votes against ‘Potomac Pipeline’ following years of opposition from activists – Maryland officials voted Wednesday to block Columbia Gas from using state land to build a natural gas pipeline that activists have been fighting for two years. The unanimous vote by the Board of Public Works, which includes Gov. Larry Hogan (R), came after more than 60 members of the General Assembly wrote a letter urging the board to deny a request from Columbia Gas to construct a distribution line under the Western Maryland Rail Trail. The board’s decision presents a serious hurdle for the project, which had been approved by federal and state regulatory agencies. Columbia Gas, a subsidiary of TransCanada, could challenge the board’s decision. The company “will consider our options over the coming days to keep this project on track,” spokesman Scott Castleman wrote in an email. “Today’s vote denying our easement request is unfortunate,” Castleman wrote. “That being said, it does not change the need for, or the company’s commitment to, our Eastern Panhandle Expansion Project.” The 3.5-mile pipeline, known as the “Potomac Pipeline,” would bring natural gas from Pennsylvania to West Virginia, bisecting the narrowest slice of Maryland’s panhandle and running beneath the Potomac River and Chesapeake and Ohio Canal in Western Maryland. Castleman called the pipeline “critical” for West Virginia’s eastern panhandle and said an extensive review process has “confirmed that through proper design and construction our project can be completed in an environmentally responsible and safe manner.” Environmentalists said the pipeline could jeopardize the drinking water supply of about 6 million people, many of them in the Washington area, even though the proposed Maryland route is about 100 miles from the District.

Low natural gas storage stocks contribute to recent natural gas futures price volatility – While the volatility of the Nymex near-month natural gas futures prices at the Henry Hub was low for most of 2018, it has increased significantly since October. The rise in natural gas price volatility coincides with historically low pre-winter levels of working natural gas storage stocks and rising natural gas consumption relative to current natural gas production levels.During most of 2018, record natural gas production moderated natural gas prices and natural gas price volatility. The January 2019 natural gas futures price averaged about $3.12 per million British thermal units (MMBtu) from April through October despite relatively low natural gas inventories, partly because of natural gas production gains. Low winter natural gas futures prices may have reduced the economic incentive for storage customers to inject natural gas over the summer at underground storage facilities for use in winter. Natural gas storage stocks ended the refill season (October 31) at 3,208 Bcf, their lowest level in 13 years. However, natural gas fundamentals shifted during October, driving up natural gas futures price volatility. Cold weather in November led to increases in residential and commercial consumption, along with already high levels of net natural gas exports and natural gas use in the electric sector. Together, this rise in consumption led to sizable early winter natural gas storage withdrawals, which further increased the storage deficit relative to the previous five-year average (covering 2013 through 2017). For the first nine months of 2018, the average daily price range, or difference between the daily high and low value, for the Nymex near-month natural gas futures contract was 8¢ per million British thermal unit (MMBtu); the daily price range averaged 10¢/MMBtu for the same period in 2017. In the final quarter of the 2018, the average range jumped to 22¢/MMBtu, with several trading days in the middle of November seeing ranges nearing $1.00/MMBtu. Inter-day trading, or the difference between average prices on consecutive days, was also unusually stable during much of 2018, averaging 4¢ per day in absolute value terms for the first three quarters of the year, compared to 6¢ per day in the first three quarters of 2017. In contrast, thus far in the final quarter of 2018, the average absolute value of inter-day trading has increased to 11¢, compared to 6¢ in the fourth quarter of 2017. By this metric, natural gas price volatility rose to its highest level since 2009.

Prices Collapse As Mother Nature Has Turned Bearish – Highlights of the Natural Gas Summary and Outlook for the week ending December 28, 2018 follow. The full report is available at the link below.

• Price Action: The February contract fell 44.7 cents (11.9%) to $3.303 on a 52.1 cent range ($3.773/$3.252).
• Price Outlook: This week’s 52.1 cent range remains elevated as the market contemplates the near-term bearish weather forecast against the bulls hope that January may turn cold as some models suggest. While the winter is far from over, each day that passes with above normal temperatures significantly reduces upside price potential as the fears of storage shortages wanes. The current weather forecast is now warmer than 8 of the last 10 years. Pipeline data indicates total flows to Cheniere’s Sabine Pass export facility were at 4.1 bcf. Cove Point is net exporting 0.7 bcf. Corpus Christi is exporting 0.327 bcf. Cameron is exporting 0.01 bcf.
• Weekly Storage: US working gas storage for the week ending December 21 indicated a withdrawal of (48) bcf. Working gas inventories fell to 2,725 bcf. Current inventories fall (607) bcf (-18.2%) below last year and fall (640) bcf (-19.0%) below the 5-year average.
• Supply Trends: Total supply fell (0.3) bcf/d to 81.0 bcf/d. US production fell. Canadian imports fell. LNG imports fell. LNG exports fell. Mexican exports rose. The US Baker Hughes rig count rose +3. Oil activity increased +2. Natural gas activity increased +1. The total US rig count now stands at 1,083 .The Canadian rig count fell (61) to 70. Thus, the total North American rig count fell (58) to 1,153 and now exceeds last year by +88. The higher efficiency US horizontal rig count rose +5 to 945 and rises +149 above last year.
• Demand Trends: Total demand fell (14.3) bcf/d to +87.1 bcf/d. Power demand fell. Industrial demand fell. Res/Comm demand fell. Electricity demand fell (3,693) gigawatt-hrs to 76,247 which trails last year by (146) (-0.2%) and trails the 5- year average by (662)(-0.9%%).
• Nuclear Generation: Nuclear generation rose 1,799 MW in the reference week to 93,393 MW. This is (3,510) MW lower than last year and (1,624) MW lower than the 5-year average. Recent output was at 93,857 MW.

The heating season has begun. With a forecast through January 11 the 2018/19 total heating index is at (1,400) compared to (1,185) for 2017/18, (1,114) for 2016/17, (987) for 2015/16, (1,300) for 2014/15, (1,475) for 2013/14, (1,256) for 2012/13 and (1,235) for 2011/12. pdf: Natural Gas Summary and Outlook for the week ending December 28, 2018

After New Year’s Eve Gas Rout Prices Pause – After getting slaughtered almost 11% on the last trading day of 2018, the February gas contract settled up less than a percent today with trading much slower overall. It was only the prompt month February contract that logged a gain on the day, though, with the rest of the gas futures curve still selling off. The result was a decent move higher in the February/March G/H spread even with the February contract not gaining much on the day. Trading today fit our expectations well as we highlighted in our Morning Update that “…we see strong support for prompt gas at $2.92 that should hold without further weather model deterioration…” yet as prices bounces in the AM we similarly highlighted that, “…we are skeptical it is that sustainable.” This verified well with bounces generally failing through the day and prices dipping into the settle even as $2.92 held. Later in the day we published our updated Seasonal Trader Report as well, where we highlighted where we saw risk skewed for gas prices over the coming months. We looked at how the strip had moved over the past year as well, and noticed for the first time in a little while the front of the strip was settling below where it was a year ago. We updated our 5-month GWDD forecast as well as our storage modeling out to the end of withdrawal season. This came following our Note of the Day looking at the latest weather-adjusted supply/demand balances in the gas market, where of note was a recent dip in LNG exports. The report highlighted why there was some support today but also that it would be hard to pull prices off $2.92 into the settle, which worked well with afternoon weather model guidance and forecasts not changing much. Now, traders will be watching how balances begin changing with the New Year’s festivities behind us. We saw some of the first evidence of what these lower prices are bringing today, but it should be more clear into next week, while Friday’s EIA print should show just how loose balances were able to get last week.

The Natural Gas Pause Continues – It was another slower trading day for natural gas today, with the February contract settling down around half a percent as traders weighed a dip in production against weather forecasts that still showed very few cold risks. Losses were about equal at the front of the strip, with the front few contracts generally moving in tandem after the February contract was initially the weakest early this morning. Our Morning Update highlighted a Neutral sentiment again today but said that our $2.92 support level was “at risk” of being temporarily broken today as overnight forecasts did not trend much more impressive. This happened through the morning on cash weakness, but only briefly. Yet we also saw early signs that afternoon model guidance could trend more favorable for cold weather in the long-range for the first time, with our 12z expectations in our Morning Update finally ticking slightly bullish. Sure enough, afternoon GEFS weather model guidance ticked a bit colder in the long-range, helping provide some support at the front of the natural gas strip (images courtesy of Tropical Tidbits). Of course, this colder weather comes after a period of significant warmth, limiting any potential bullish impact. Meanwhile, traders are closely watching tomorrow’s EIA print for evidence of just how much balances loosened over the Christmas holiday. While there was a slight tick higher in GWDDs week-over-week, the Christmas holiday destroyed quite a bit of demand and traders are expecting a decently smaller withdrawal. Our Afternoon Update ran through our expectations for the EIA print out tomorrow, and we will release our EIA Rapid Release and Note of the Day immediately after the number tomorrow putting it into context. It will be a matter of how loose, not if it is loose, meaning we’ll be closely looking at the front of the gas strip to see just how much loosening it seems traders have already priced in. To read all our latest analysis and make sure you don’t miss out tomorrow, try out a 10-day free trial here.

Potential January Cold Helps Natural Gas Futures Shake Off Bearish EIA Storage Report – The natural gas futures market managed to shake off a particularly bearish government storage report Friday as forecasts for a potential shift to colder temperatures later this month seemed to inspire some buying after recent declines. In the spot market, a mild forecast for much of the Lower 48 accompanied continued sub-$3 pricing in most regions, though reports of upcoming maintenance coincided with gains in the Northeast; the NGI Spot Gas National Avg. shed 10.0 cents to $2.700/MMBtu. The February Nymex futures contract closed out the week above the psychologically significant $3 mark, adding 9.9 cents to settle at $3.044 Friday. March added 9.3 cents to settle at $2.905.“Weather model guidance has finally begun to pick up on the colder weather risks we expected to develop in the middle third of January, with a weak cold shot now expected to arrive later” in the week ahead and a “stronger one potentially developing into the following week,” Bespoke Weather Services told clients Friday.Bespoke expects colder trends to gradually creep into forecasts, pointing to shifts in the Eastern Pacific Oscillation and the North Atlantic Oscillation that would “allow for cold to be forced down more across the eastern U.S. Already models are showing a lobe of the tropospheric polar vortex sitting across the Hudson Bay, with just a modest upstream perturbation necessary to force much more cold across the country.The EIA reported a 20 Bcf withdrawal from natural gas stocks for the week ended Dec. 28, sharply to the bearish side of expectations for what already figured to be a lighter-than-normal pull. The report, released a day later than usual because of the New Year’s holiday, initially had a relatively muted impact on Nymex futures, despite the 20 Bcf withdrawal coming in much lighter than estimates and the year-ago and five-year-average comparables. Last year, EIA recorded a 193 Bcf withdrawal for the period, and the five-year average is a pull of 107 Bcf. Estimates ahead of the report pointed to a light withdrawal, but few market participants had pegged a pull as light as the actual number. Responses to major surveys had clustered around minus 44 Bcf to minus 47 Bcf, with estimates ranging from minus 25 Bcf to minus 92 Bcf. Intercontinental Exchange EIA Financial Weekly Index futures had settled Thursday at a 33 Bcf pull.The 20 Bcf withdrawal for the week made a big dent in the hefty year-on-year and year-on-five-year deficits. Total Lower 48 working gas in underground storage stood at 2,705 Bcf as of Dec. 28, 450 Bcf (14.3%) below last year’s stocks and 560 Bcf (17.2%) lower than the five-year average.By region, EIA reported a 20 Bcf build in the South Central that caught a number of market observers by surprise, including a 22 Bcf build into salt stocks. The largest weekly withdrawal was in the Midwest region at 20 Bcf, followed by the East, which withdrew 15 Bcf for the week. The Mountain and Pacific regions each withdrew 3 Bcf, according to EIA. Even after factoring in the typical demand impact of the holidays, Friday’s EIA report stands out as particularly bearish, Genscape Inc. analyst Eric Fell told NGI.

Gas Tries To Set A Bottom Despite Very Bearish EIA Storage Number – Excitement began to return to the natural gas space as the February contract shook off a very small storage draw announced by the EIA to rally over 3%. The February contract was not alone, as the entire natural gas strip rallied today. Such a bullish move was not particularly surprising as this morning in our Morning Update we changed our daily natural gas sentiment to “Slightly Bullish” for the first time as we saw “increased long-range cold risks” that could support prices, with GWDD additions helping cancel out what we said would be, “…a very bearish EIA print…” Yet this very bearish EIA print turned out to be even more bearish than we expected, as we were looking for a -42 bcf net implied flow to be announced by the EIA before they announced a minuscule -20 bcf net implied flow. All last week we had been warning clients that we were looking at the loosest weather-adjusted power burns of the season, and we did see bearish risks with our estimate today, but the magnitude of the miss was certainly a surprise with a large 22 bcf build in Salt storage. While the print was quite loose relative to the last several weeks, there is little doubt that the Christmas holiday played a large role too, as comparatively the storage withdrawal was not *as* loose when looking at just other weeks that held Christmas. Yet gas prices shook this off as we warned was possible in our Morning Update, and some colder risks on afternoon GEFS weather model guidance helped as well (images courtesy of Tropical Tidbits). Following the EIA print we released our EIA Rapid Release, running through our reading of weather-adjusted balances from the storage number, as well as our Note of the Day looking at Week 3 weather forecasts and daily weather-adjusted demand and supply.

State Senator Linda Stewart Files Legislation to Permanently Ban Fracking in Florida – State Senator Linda Stewart (D-Orlando) has filed legislation to permanently ban fracking in Florida. “Fracking poses a dangerous threat to our environment, especially here in Florida,” said Senator Stewart, a leading advocate for protecting Florida’s natural resources. “The fracking process involves a host of toxic chemicals injected in the extraction process which could contaminate the fresh water supply for millions of people and our wildlife. It’s just not worth the risks.” SB 146 is the latest effort to ban the highly controversial energy extraction method. Despite more than 90 such bans filed by local governments throughout the state, and bi-partisan support in both chambers of the legislature, previous legislative measures have fallen short of garnering a hearing or mustering the necessary votes for passage. “This time may well be the charm,” Senator Stewart said. “We’re about to inaugurate a governor whose environmental platform included a ban on fracking. We intend to hold Governor-elect Ron DeSantis to that promise, and I’m sure he’ll be supportive of this good bill.” Senator Stewart’s legislation, which has been filed for the upcoming legislative session, would not only ban fracking in future wells, but would prohibit the extraction process in wells already permitted for drilling or operation. If successful, the measure would take effect immediately.

Whitmer seeks Nessel opinion to block Line 5 tunnel – Michigan Gov. Gretchen Whitmer has asked newly elected Attorney General Dana Nessel for a legal opinion on the Mackinac Straits Corridor Authority in an apparent attempt to block construction of a tunnel for Enbridge’s Line 5 oil pipeline. The authority, assembled days before the close of 2018, voted Dec. 19 to approve an agreement with Enbridge for the construction of the 4-mile-long tunnel underneath the Straits of Mackinac. The project would cost up to an estimated $500 million. The approvals came amid a time crunch before the Jan. 1 inaugurations of Whitmer and Nessel, who campaigned on promises to shut down the aging pipeline rather than allow it to operate for up to 10 years during construction. Whitmer’s letter outlines what appears to be the basis for Democratic elected officials’ arguments against the corridor authority. It questions the length of appointments, the title of the law, and potential conflicts with the state Constitution. “Resolving any legal uncertainty” around the agreement “is necessary to assure that we can take all action necessary to protect the Great Lakes, protect our drinking water and protect Michigan jobs,” Whitmer said in statement. “I pledged to take action on the Line 5 pipeline on day one as governor, and I am holding true to that campaign promise.” In a Wednesday statement, Nessel said she welcomed the request regarding “serious and significant concerns” surround the new law that was “passed without the care and compassion” expected for such an issue. She said she would consider the request immediately and encouraged interested parties to send her briefs or legal memos on the issue. “Let me remind those who stand to benefit from this act: take heed that this request raises serious legal concerns,” Nessel said. “In no way should any entity rely on this act to move forward unless and until these matters have been resolved.”

US rigs drop by two, gas rigs post gains – The overall number of US oil and gas rigs dropped by two this past week to 1,145, although that figure reflects more natural gas-oriented rigs added to the fleet and even more oil rigs taken out, S&P Global Platts Analytics data showed Thursday. In all, oil rigs were down by 11 over the New Year’s holiday week, leaving 897, while eight rigs chasing gas were added for a total of 226, Platts data showed. In addition, the number of rigs classified as oil/gas, which usually indicates offshore Gulf of Mexico rigs, was up by two to 19. Movements within specific domestic onshore plays were minor at the end of the holiday season. The Eagle Ford Shale in South Texas showed the most positive movement, with an increase of four rigs to 91. Both the Permian Basin, of West Texas/New Mexico, and the Marcellus Shale, which is largely in Pennsylvania, added three rigs apiece for respective totals of 474 and 63. Also, the DJ Basin of Colorado fell by two to 34. In the SCOOP/STACK in Oklahoma, the Williston Basin of North Dakota/Montana and the Utica Shale of Ohio, there was no change. There, rig counts remained at 105, 63 and 16, respectively. The rig count has fallen 7% since its most recent high of 1,233 for the week ended November 14, 2018. That is in keeping with historic trends that typically see the rig count falling 2% to 3% in any given year between the third and fourth quarters, owing to the North American holiday season at year-end. But in January, the tendency is for a flattish rig count for the first couple of weeks. After that, the rig count typically follows oil prices, with a lag of two to three months between price movement and rig adds or reductions. Also, 1,426 permits were added as the new year began this week, up by 563 or 65% as the new year began. The DJ Basin showed the most permitting activity of the eight named basins at 209, up by 161. The Permian was a distant second at 80 permits added, although it was down by five week on week, while the Marcellus added 41 permits, up by 16. The other five prominent basins added fewer than 30 permits apiece, Platts data showed. Commodity prices were slightly lower in the week. WTI for the week ended January 2 averaged $45.49/b, down 26 cents, while WTI Midland in the Permian Basin was $39.68/b, down 73 cents. The Bakken composite price was $42.39/b on average for the week, down 22 cents. For gas, the Henry Hub price averaged $3.03/MMBtu for the week, down 45 cents, while Dominion South prices in Appalachia averaged $2.71/MMBtu, down 36 cents.

Oil Spill Continuing for 14 Years Could Become Nation’s Worst Environmental Disaster — It may be a New Year, but there is an old oil spill that keeps on spilling. The trouble is that you will probably have never have heard about the spill. But you need to know. Because, for more than 14 years, some 10,000 to 30,000 gallons of oil has leaked daily from a sunken oil rig owned by Taylor Energy into the Gulf of Mexico, about 12 miles south of the mouth of the Mississippi River. The disaster began way back in September 2004, when the company’s oil platform, known as MC-20 Saratoga, was destroyed by Hurricane Ivan. Although the company contained some of the pollution caused by the loss of the platform, it did not stop all the leaks. Unless the oil spill is stopped, the sunken rig could carry on leaking for 100 years, becoming America’s worst environmental disaster. Even now, if you take the high end of the leak estimate, the site may have released an estimated 150 million gallons of oil. This is silently creeping towards the estimated 200 million gallons spilled by BP during the Deepwater Horizon oil spill in 2010. Back in November last year, the U.S. Coast Guard directed Taylor Energy to implement a new containment plan which “must eliminate the surface sheen and avoid the deficiencies associated with prior containment systems.” In theory the company could be fined $40,000 a day for failing to comply. As you would expect, the company responsible for the spill, Taylor Energy not only disputes the figures concerning the leaks, but even whether it is to blame for the leak itself. Over the years it has tried to dismiss the leak as nothing more than a mere “trickle.” That is hardly surprising because it could cost an estimated $1 billion to fix. The bottom line is that this a slow unseen disaster that could have been stopped years ago. As NOLA reports, some six years ago, Skytruth, an environmental group based in Shepherdstown, measured the oil sheen coming from the platform at over 20 miles long and urged the authorities to act. However, it was not until 2016 that the U.S. authorities began investigating the ongoing pollution.

South Texas feedgas demand ramping up with Corpus Christi LNG – Feedgas demand for U.S. LNG exports has accelerated in recent months with the addition of new liquefaction and upstream pipeline capacity. The latest export facility contributing to the winter surge in feedgas flows is Cheniere Energy’s Corpus Christi LNG (CCL) in South Texas – the first greenfield LNG export terminal in the Lower 48 and the first such terminal, greenfield or otherwise, in Texas. Train 1 has yet to be commercialized, but already it’s added 0.5 Bcf/d of gas demand to the Texas market through December. The facility sources its gas via a number of legacy interstate and Texas intrastate pipelines, many of which have undergone reversals and expansions in order to serve LNG terminals but also another competing export market: Mexico. How will CCL change gas flows in South Texas? Today, we provide an update of feedgas flows to Corpus Christi, including a closer look at the upstream pipeline routes facilitating those flows. This is Part 3 in our blog series examining recent changes in U.S. LNG export demand and the pipeline flows feeding it – a subject we cover comprehensively on a weekly basis in RBN’s LNG Voyager report (published each Tuesday morning). In Part 1 of the series, we started with the latest on Cheniere’s Sabine Pass Liquefaction terminal (SPL) in Cameron Parish, LA, where the start-up activities for Train 5, along with the full in-service of a new feedgas route via Kinder Morgan Louisiana Pipeline’s Sabine Pass Expansion project, have boosted feedgas flows to well over 3 Bcf/d in recent weeks. Then, in Part 2, we shifted our focus to Dominion’s Cove Point LNG export facility in Maryland, where the in-service of two pipeline expansions – Williams/Transco’sAtlantic Sunrise and TransCanada/Columbia Gas Group’s WB Xpress – has improved supply connectivity, with daily volumes consistently near or at capacity for the first time since the single-train facility began producing LNG.

In Booming Oil Field, Natural Gas Can Be Free –“American energy companies have spent billions of dollars in the past decade exploring for natural gas. But in parts of Texas and New Mexico, there is now so much of it that it is sometimes worthless. Some companies have even had to pay buyers to take it away”, according to a story in today’s Wall Street Journal.”Shale drillers in the Permian Basin are producing vast amounts of gas as a byproduct of prospecting for oil. But there aren’t enough pipelines to take all the gas to market, causing some of it to become landlocked, and sending local prices into free fall.””Gas prices in parts of the prolific region hovered near zero last month and some trades went negative, to as low as a negative 25 cents per million British thermal units, according to S&P Global Platts. The price-reporting agency said it was the first time on record that gas traded for less than zero at the Waha hub in West Texas. While prices have since ticked up, averaging $1.68 per million British thermal units for the four weeks through Dec. 21, that is still 40% of the $4.20 per million British thermal units that gas has fetched in that time at the main U.S. benchmark, Henry Hub in Louisiana.””Energy companies say last month’s zero pricing could be a sign of things to come in the Permian area next year, as more oil pipelines get built and companies ramping up production of crude, a far more lucrative product, get stuck with more gas that has nowhere to go. The U.S. Energy Information Administration estimates December gas production will top 12 billion cubic feet a day in the region, up about 34% from a year earlier”, according to the Journal article. ““You’ll see things get worse and worse and worse as oil production grows and gas production grows alongside it,” “The situation in the Permian underscores just how plentiful natural gas has become in the U.S. since companies using hydraulic-fracturing and horizontal-drilling techniques began unlocking vast amounts of it from shale-rock formations. Natural gas now helps generate about one-third of U.S. electricity, and it has become a valuable export commodity as ships take liquefied natural gas to Asia and Europe. Still, Henry Hub prices have hovered below $5 a million British thermal units for almost all of the past decade, according to EIA data.“

As oil and gas exports surge, West Texas becomes the world’s “extraction colony” – Drilling booms have come and gone in this oil town for nearly a century. But the frenzy gripping it now is different. Overwhelming. Drilling rigs tower over suburban backyards. There’s a housing crunch so severe that rents are up 30 percent in the last year alone. Tax-averse city officials raised fees this spring just to keep basic services afloat. This boom is engulfing the rest of West Texas, too, extending to areas that drilling hasn’t touched before. As communities welcome the jobs and the new business, they’re struggling with an onslaught of problems that include spikes in traffic accidents and homelessness. What’s happening is unprecedented. In December, companies in the Permian Basin – an ancient, oil-rich seabed that spans West Texas and southeastern New Mexico – were producing twice as much oil as they had four years earlier, during the last boom. Forecasters expect production to double again by 2023. Texas Gov. Greg Abbott and others say the drilling spree is ushering in a new era of American energy independence, but American demand isn’t driving it. Foreign demand is.In late 2015, Congress cut a deal to lift 40-year-old restrictions on the export of crude oil. That opened the floodgates. The U.S. sold 230 million more barrels of crude to other countries in the first half of this year than it did three years earlier – a surge made possible by a virtually identical spike in Permian production.The U.S. just surpassed Russia as the world’s top oil producer. The International Energy Agency predicts that American oil – most of it from the Permian – will account for 80 percent of the growth in global supply over the next seven years. That’s bringing big profits to oil companies as well as lung-searing pollution to places where drilling has skyrocketed, while threatening to exacerbate climate change. Hydraulic fracturing – better known as fracking – made this boom technologically possible, but exports are the reason there’s so much new drilling. U.S. refineries built for heavier varieties of oil than the Permian produces can’t handle the enormous new quantities of Texas light crude. Instead, companies are shipping it abroad and finding lucrative new markets.

Why The Permian Basin May Become The World’s Most Productive – Consider for a moment that the Permian Basin has been producing oil since the 1920s, and reached the two million BPD mark in the 1970s. Production slowly declined, until dipping back under one million BPD around the turn of the 21st century. Permian Basin oil production slowly crept back up to one million BPD in 2010, and then hydraulic fracturing sent production soaring. By the end of 2018, production had reached 3.8 million BPD, vaulting the Permian into second place among the world’s leading oil fields. In under a decade — and after already producing oil for a hundred years — Permian Basin production has increased by 3 million BPD: But are there indications that Permian production will continue to grow? Yes. Consider the soaring inventory of drilled but uncompleted (DUC) oil wells. These are oil wells that have undergone the initial process of drilling (i.e., the hole in the ground has been drilled). However, to get the well ready for production requires casing, cementing, perforating, and hydraulic fracturing.The final piece of the puzzle is the amount of oil that remains to be extracted. In just the Texas part of the Permian, ~30 billion barrels of crude and ~75 trillion cubic feet (Tcf) of natural gas have already been extracted. But a new assessment by the U.S. Geological Survey (USGS) has suggested that there’s still a lot to be extracted.In 2016, the USGS had estimated that the Wolfcamp shale in the Midland Basin portion of the Texas Permian Basin contains a mean of 20 billion barrels of oil, 16 Tcf of associated natural gas, and 1.6 billion barrels of natural gas liquids (NGLs). This estimate was for undiscovered, technically recoverable resources, and was the largest estimated continuous oil accumulation that USGS had ever assessed in the U.S. In its most recent report, the USGS has included the Wolfcamp shale and Bone Spring Formation of the Delaware Basin portion of the Permian Basin for the first time, and the estimates are eye-popping. The new estimated mean of undiscovered, technically recoverable resources in the Permian basin are 46.3 billion barrels of oil, 281 Tcf of natural gas (17.5 times higher than the 2016 estimate!), and 19.9 billion barrels of NGLs.

How An Oil Boom in West Texas Is Reshaping the World –My view from the window seat of a small regional jet landing in Midland, Texas, is either a testament to the advances of human civilization or a sign of its impending demise, depending on your perspective. Countless oil wells, identified by their glowing red flames, dot the dark landscape.We are descending into the Permian Basin, the heart of American oil country, where the massive oil and gas boom is changing not just Texas but also the nation and the world.This year the region is expected to generate an average of 3.9 million barrels per day, roughly a third of total U.S. oil production, according to the U.S. Department of Energy. That’s enough to make the U.S., as of late 2018, the world’s largest producer of crude. The windfall has turned a nation long reliant on foreign oil into a net exporter in a few short years.Not even the plunge in oil prices in recent months, which led some companies to scale back their plans for the Permian, has stopped the enthusiasm. By 2025, U.S. oil production is expected to equal that of Saudi Arabia and Russia combined, according to the International Energy Agency (IEA). The power of the Permian oil and gas boom is easy to spot in the basin itself, which stretches across more than 75,000 sq. mi. of scrubby ranchland in West Texas and New Mexico. So-called man camps – hastily constructed short-term housing for oil-field workers – have sprung up everywhere, amid new luxury construction projects and shiny billboards advertising Rolexes to laborers pulling in six-figure salaries. But the impact extends far beyond the region.During the past three years, the boom in these parts has transformed the U.S. economy, upended the international energy industry, undermined global environmental efforts and tilted the balance of power among Beijing, Moscow and Washington. In places like Saudi Arabia, uncertainty over future oil profits driven by rising U.S. production contributed to a rethinking of the economy. In theory, less reliance on Saudi oil also gives the U.S. more leverage in other areas, like the war in Yemen, although the Trump Administration hasn’t prioritized such efforts. The vast new U.S. oil reserves have provided cover for the imposition of tough sanctions against nations like Iran and Venezuela, moves that at other times might have crippled global supply. And around the world, the boom in the U.S. has inspired other countries to race to develop their own shale resources

Dallas Fed: Texas energy sector fell flat in fourth quarter — Growth in the Texas energy sector came to an abrupt halt in the fourth quarter as oil prices plummeted 40 percent in the last three months of 2018, according to survey data Thursday from Federal Reserve Bank of Dallas The survey, which polls oil and gas executives in the region, found that activity virtually flat-lined near the end of the year. The survey’s associated business activity index, which the Dallas Fed considers the the broadest measure of the health of the energy sector, plunged from a score of 43.3 in the third quarter to 2.3 in the final three months of the year. The results remained positive, which mean the sector is still growing, but just barely. Energy executives were less optimistic about what lies ahead. The Fed’s company outlook index, which measures views of future conditions, recorded its first negative result since early 2016 when the last oil bust bottomed out at $26 a barrel. This time around, oil prices have sunk from more than $76 a barrel in early October down to a low of $42 per barrel in late December because of fears of a global glut of oil, driven by the combination of record production from the United States and slowing demand worldwide. Crude settled in New York on Thursday at $47.09 a barrel, up 55 cents for the day. Analysts are watching to see if OPEC nations – led by Saudi Arabia – and allies like Russia decrease their crude oil production levels as promised through the first six months of the year and possibly beyond. Uncertainty about global economic growth and its impact on oil demand, especially in Asia, also is also weighing on prices, said Karr Ingham, an economist for the trade group Texas Alliance of Energy Producers “It seems like we’re at a bit of a precipice right now,” Ingham said. “If prices stabilize in the first quarter and then go up a bit, then we’d be in pretty good shape.” The Federal Reserve district surveyed consists of Texas, northern Louisiana and southern New Mexico. The Dallas Fed survey was conducted from Dec. 12 to Dec. 20 with the participation of 167 energy companies. The U.S. oil benchmark fell from more than $51 a barrel down to below $46 during that time frame.

Dallas Fed: Oil and Gas Firms Start 2019 with Raised Uncertainty – Growth in the Eleventh District’s energy sector slowed significantly in fourth quarter of 2018 amid a decline in oil prices, according to results from the Dallas Fed’s quarterly energy survey released Jan. 3. The survey of oil and gas executives from E&P and oilfield service companies in Texas, northern Louisiana and southern New Mexico revealed a business activity index that barely remained positive. The business activity index, the survey’s broadest measure of conditions facing energy executives, plummeted from 43.3 in 3Q 2018 to 2.3 in 4Q 2018. “Following a dramatic decline in oil prices, the oil and gas sector is entering the new year with heightened uncertainty and a bit of pessimism,” Dallas Fed senior economist Michael D. Plante, said a statement emailed to Rigzone. “While activity remains at a high level, growth stalled in the fourth quarter, and survey respondents reported much greater uncertainty surrounding their outlook.” Survey results also pointed to moderation for both employment and work hours growth in the fourth quarter, particularly for oilfield services, while wage growth accelerated. The Dallas Fed warned last week that job growth in Texas – home to the prolific Permian Basin – would weaken in the first half of 2019 if oil prices remain depressed. Energy executives were also asked special questions related to their firms’ capital spending outlooks. “Lower oil prices are also affecting spending plans for 2019, with 53 percent of respondents reporting they have reduced planned capital spending due to the recent price decline,” Plante said. “Despite this, many still expect capital spending to be higher in 2019 than in 2018, of which about 37 percent expect a slight increase and 16 percent a significant increase.” The company outlook index posted its first negative reading since 1Q 2016, plummeting 57 points to -10.2 in the fourth quarter. This drop was most pronounced among oilfield services firms, with company outlook dropping 64 points to -17.2. The uncertainty index jumped 34 points to 42.4, marking heightened uncertainty regarding firms’ outlooks. Almost 58 percent of firms reported greater uncertainty.

It Turns Out Fracking Is A Water Hog That’s Stealing Our Futures – Food and Water Watch – For years, the American people have been assured by energy companies that fracking is harmless and doesn’t use more water than other energy sources. The Duke research team that recently put out a new report begs to differ. They examined data across 12,000 wells and five years of operation. Here are key findings from the report and what they mean for our survival. The Findings:

• Water is staying trapped in the shale, or if it does re-emerge, isn’t treated: Only a small fraction of the fresh water injected into the ground returns as flowback water, while the greater volume of FP (flowback and produced) water returning to the surface is highly saline, is difficult to treat, and is often disposed through deep-injection wells.
• The amount of water used by fracking has been critically underestimated. The study finds that from 2011 to 2016, the water use per well increased up to 770 percent.
• The toxic wastewater produced is a much bigger problem than previously understood. The study found that toxic wastewater produced from fracking had increased up to 1440 percent between 2011 and 2016. There has been no satisfactory practice of water treatment that returns this water to usable condition for humanity – and at this scale, one can reason that fracking is on pace to destroy U.S. water sources and leave us without water for our population’s consumption: The total water impact of hydraulic fracturing is poised to increase markedly in both shale gas – and oil-producing regions. On the basis of modeling future hydraulic fracturing operations in the United States in two scenarios of drilling rates, we project cumulative water use and FP water volumes to increase by up to 50-fold in unconventional gas-producing regions and up to 20-fold in unconventional oil-producing regions from 2018 to 2030, assuming that the growth of water use matches current growth rates and the drilling of new wells again matches peak production.

Oil-patch states brace for change under new leadership – The new year could bring a fresh round of legislative battles to state capitals across the oil patch. Democrats are ready to flex their muscles when legislative sessions open this month, after picking up gains in New Mexico and Colorado. Republicans held onto control in Oklahoma, Texas and North Dakota but could face challenges from Democrats on everything from pipeline regulations to taxes. And falling oil prices could provide a fiscal challenge, as the states dig out from the price crash that stretched from 2014 to 2016. New Mexico, where business is booming thanks to the prolific Permian Basin, could see the most significant changes. Democratic U.S. Rep. Michelle Lujan Grisham will replace Republican Gov. Susana Martinez, and Democratic state Rep. Stephanie Garcia Richard will replace Land Commissioner Aubrey Dunn, a Libertarian.Lujan Grisham has said she plans to create a statewide rule on methane emissions from the oil and gas industry, something that’s already on the books in neighboring Colorado. She’ll also be able to appoint two members of the state Oil Conservation Division, which oversees energy regulation in New Mexico (Energywire, Nov. 7, 2018). At the State Land Office, Garcia Richard will oversee oil and gas leasing on 13 million acres of subsurface minerals. Money from leasing on state lands goes to a trust fund that supports education. One of her first priorities, which will require action in the state Legislature, is raising the royalty rate on state land from 18.75 percent to 25 percent, the same rate as Texas. A similar dynamic could play out in Colorado. Gov.-elect Jared Polis is widely seen as less friendly to the oil and gas industry than John Hickenlooper, a fellow Democrat who is leaving office because of term limits. Democrats also won control of the state Senate and widened their margin in the House.In the Lone Star State, state Rep. Rafael Anchia (D) of Dallas is drafting legislation to strengthen pipeline safety enforcement at the Railroad Commission of Texas, which oversees the state’s energy industry. The bills would speed up replacement of aging pipelines, boost fines for safety violations and require companies to report leaks to the public in a real-time, searchable map. In Oklahoma, Democrats are hoping to preserve a package of tax increases that passed last year in the wake of a statewide teacher walkout. Legislators voted last spring to raise the gross production tax on oil from 2 percent to 5 percent, the first statewide tax increase since 1990, to reverse a string of budget shortfalls that had led to drastic cuts in education spending (Energywire, March 29, 2018).

Weld County oil and gas spill report for Dec. 30 – The following spills were reported to the Colorado Oil and Gas Conservation Commission in the past two weeks. Information is based on Form 19, which operators must fill out detailing the leakage/spill events. Any spill release that may impact waters of the state must be reported as soon as practical. Any spill of five barrels or more must be reported within 24 hours, and any spill of one barrel or more, which occurs outside secondary containment, such as metal or earthen berms, must also be reported within 24 hours, according to COGCC rules. .

• • WHITING OIL & GAS CORPORATION, reported Dec. 25 a tank battery spill about 7 miles northwest of Avalo, near Weld County roads 120 and 133. About nine barrels of produced water spilled. .
• • EXPEDITION WATER SOLUTIONS COLORADO LLC, reported Dec. 23 a well pad spill about 3 miles northeast of Firestone, near Weld roads 20 and 19. Between two and three barrels of oil-based mud spilled. The oil-based mud hauler failed to completely close the valve on the back of his truck.
• • VERDAD RESOURCES LLC, reported Dec. 23 a tank battery spill about 3 miles northeast of Keota, near Weld roads 100 and 109. Between one and five barrels of oil spilled. A leak formed in a line to a tanker truck, spilling oil on roadbase.
• • PDC ENERGY INC, reported Dec. 20 a historical well spill about 4 miles southeast of Kersey, near Weld roads 48 and 61. Less than five barrels of oil spilled. Waters of the state were impacted or threatened.
• • PDC ENERGY INC, reported Dec. 20 a historical tank battery spill about 2 miles east of Garden City, near U.S. 34 and Weld road 47. Less than five barrels of oil spilled. Crews found the spill while abandoning the tank battery.
• • HIGHPOINT OPERATING CORPORATION,reported Dec. 20 a tank battery spill about 2 miles northwest of Hereford, near Weld roads 138 and 79. About 40 barrels of produced water spilled. A hole formed in the tank below the bottom load out valve, spilling produced water into unlined containment.
• • KERR MCGEE OIL & GAS ONSHORE LP,reported Dec. 20 a well spill about 2 miles north of Hudson, near Weld roads 18 and 47. About two barrels of oil spilled outside containment. Overpressure on the tubing caused the stuffing box rubbers to fail.
• • PDC ENERGY INC, reported Dec. 18 a historical tank battery spill about 3 miles northeast of Greeley, near Colo. 392 and Weld road 47. Less than five barrels of oil spilled. Crews found the spill while abandoning the tank battery.
• • PETROSHARE CORPORATION, reported Dec. 17 a historical tank battery spill about 5 miles south of Keenesburg, near Weld roads 6 and 57. Between five and 100 barrels of oil spilled.. The spill was less than 200 feet from the Henrylyn Canal.

North Dakota legislator seeks to deter tampering of pipelines, infrastructure – A legislator from the northeast North Dakota district, where an oil pipeline valve was tampered with in 2016, is pushing for a stronger deterrent for damaging critical infrastructure. Sen. Janne Myrdal, R-Edinburg, is sponsoring a bill that amends the language of state law to better define that it’s illegal to willfully tamper with or damage energy facilities and other infrastructure. Myrdal said the proposal was prompted by the incident in October 2016 involving activists who turned an emergency valve on TransCanada’s Keystone Pipeline in Pembina County, stopping the flow of oil for more than seven hours. “There was concern both from law enforcement and during the trial that we just didn’t have enough teeth per se in our Century Code to go after people who do that,” Myrdal said. Her proposal also would make a fine 10 times greater if an organization is found to be a conspirator with an individual who tampers with or damages infrastructure. “If groups from outside of our state are paying for activists to come here and paying for damage, we need to make them accountable for that as well,” Myrdal said. Michael Eric Foster, the Seattle man found guilty of turning the pipeline valve, said making the law more severe would not have stopped him. Foster and other members of Climate Direct Action were part of a coordinated effort in four states to stop the flow of pipelines that carry tar sands oil from Canada into the United States in protest of the oil industry’s contribution to climate change. “What I did, I did to protect my family because everything else is failing.

Brine spill reported in Williams County — An equipment failure caused a brine spill at a well site in Williams County on Monday, according to a statement released by the North Dakota Oil and Gas Division on Wednesday. Whiting Oil and Gas Corp. reported that 469 barrels, or 19,698 gallons, of produced water spilled 10 miles southeast of Epping due to a valve connection leak. The brine was contained at the well site and cleanup is underway. A state inspector has been to the site and will monitor cleanup.

Dakota Access pipeline developer slow to replace trees – – The developer of the Dakota Access oil pipeline missed a year-end deadline to plant thousands of trees along the pipeline corridor in North Dakota, but the company said it was still complying with a settlement of allegations it violated state rules during construction. Texas-based Energy Transfer Partners, which built the $3.8 billion pipeline that’s now moving North Dakota oil to Illinois, is falling back on a provision of the September 2017 agreement that provides more time should the company run into problems. The company must provide 20,000 trees to county soil conservation districts along the pipeline’s 359-mile (578-kilometer) route across North Dakota. The deal with North Dakota’s Public Service Commission settled allegations that ETP removed too many trees in some areas and that it improperly handled a pipeline route change after discovering Native American artifacts. The artifacts were not disturbed. The agreement required the company to replant trees and shrubs at a higher ratio in the disputed areas, along with an additional 20,000 trees along the entire route. ETP filed documents in October detailing efforts by a contractor to plant 141,000 trees and shrubs, but the PSC asked the company a month later to provide more documentation that it had complied with all settlement terms.

TigerSwan loses bid for attorney fees in North Dakota case (AP) – A North Dakota judge has refused to award attorney fees to a North Carolina security company that won a court case in the wake of protests over the Dakota Access oil pipeline. North Dakota’s Private Investigative and Security Board sued TigerSwan in 2017, alleging the company that handled security for the pipeline developer illegally operated without a state license. Judge John Grinsteiner dismissed the case, and TigerSwan sought reimbursement for at least $165,000 in attorney fees. Grinsteiner last month rejected the request, saying the board’s case wasn’t frivolous even though the board lost. TigerSwan hasn’t decided whether to appeal. The board has appealed the dismissal of its case to the state Supreme Court and also is seeking up to $2 million in fines against TigerSwan through an administrative complaint .

How TigerSwan Infiltrated Standing Rock and the Dakota Access Pipeline Movement – – For months, a man calling himself Joel Edwards had posed as a pipeline opponent, attending protests, befriending water protectors, and paying for hotel rooms, supplies, and booze. He told some people he had a job with a hotel that allowed him to travel, others that he was a freelance journalist reporting on the pipeline resistance. But five former contractors for TigerSwan, the secretive security firm hired by Energy Transfer to guard the pipeline, confirmed to The Intercept that Joel was an undercover intelligence operative. His real name was Joel Edward McCollough, and he had been sent to collect information on the protesters, explicitly targeting those who were down on their luck. Horne, who struggled with addiction, appeared to be a perfect target. McCollough passed along what he learned to his superiors at TigerSwan, who attempted to use the information to thwart protest activity and identify people or plots that represented threats to the pipeline. Traces of his surveillance turned up in TigerSwan’s daily situation reports, which were written for Energy Transfer and at times passed to law enforcement. The former TigerSwan contractors interviewed by The Intercept, who declined to be named because it would threaten their continued work in the industry, had either worked with McCollough directly or knew of him through internal communications.Like other contractors working for TigerSwan, McCollough had developed the skills he deployed in the Dakota Access pipeline fight during the U.S. war in Iraq, where he served as a Marine Corps interrogator and counterintelligence specialist. McCollough was participating in something akin to a massive experiment in U.S. military-trained operatives applying lessons learned fighting insurgencies abroad to thousands of pipeline opponents engaged in protest against a Fortune 500 energy giant at home. Behind the operation was Energy Transfer, whose pipeline empire has been key to propelling the U.S. oil and gas boom at a moment when the devastating impacts of climate change demand a rapid halt in fossil fuel production.

Halliburton chairman retires amid probe into land deal with Zinke – The chairman of oilfield services firm Halliburton Co. has retired amid a federal investigation into a land deal he negotiated with outgoing Interior Secretary Ryan Zinke. David Lesar’s retirement was planned at least since May 2017. There is no indication that the ongoing probe by the Interior Department’s Office of the Inspector General (OIG) implicates Lesar, since it is focused on whether Zinke violated federal ethics standards in the deal. Lesar’s retirement was effective Monday. Halliburton said Wednesday that Jeff Miller, the current president and CEO, will also serve as chairman going forward.Zinke, through a nonprofit he used to head, negotiated the deal with a development backed in part by Lesar regarding a plot of land the nonprofit owned in Zinke’s hometown of Whitefish, Mont. The deal was first reported by Politico last year.The OIG has since referred the probe to the Justice Department for potential criminal prosecution. The office, which is closed as part of the ongoing partial government shutdown, didn’t respond to a request for comment Wednesday.Zinke resigned last month from Interior, and his last day in the post is Wednesday. He has consistently argued that he did nothing wrong.Shortly after Politico reported on the deal in June 2018, he called the report “fake news.” “Clearly, I’m not on the board anymore. My wife runs the board,” Zinke said of the nonprofit on Montana radio show Voices of Montana. “And they make a letter of intent for my wife that, you know what, the community is for this project, the city approves it, it’s a good project for Whitefish, we’ll share some parking lots with you. That’s it,” he said. Halliburton has refused to comment on the matter, saying it involves Lesar strictly in his personal capacity.

Fracking Bust? Shale Wells Across US Churning Out Less Oil Than Projected – The implementation of hydraulic fracturing has helped propel the U.S. into an energy superpower, but there are signs that the fracking boom might not be as productive as developers assumed. The U.S. surpassed Saudi Arabia and Russia in September to become the largest oil producer in the world. The historic milestone came as American oil production roughly doubled over the course of just eight years. While the fracking boom predates President Donald Trump’s time in office, the gains in production were aided in the Trump administration’s aggressive regulatory rollback and streamline of drilling permits that encouraged development on federal lands. The U.S. shale boom has even rivaled the Organization of the Petroleum Exporting Countries’ (OPEC) influence on the market, with the international oil cartel being forced to work around the vast increase in supply. However, an investigation by The Wall Street Journal suggests that thousands of shale wells in the U.S. are not yielding as much as developers originally projected to their investors. After analyzing around 16,000 wells that are operated by 29 of the largest fracking companies in oil basins in Texas and North Dakota, WSJ found two-thirds of the projections made by producers between 2014 and 2017 in the country’s four top drilling regions were too optimistic. Altogether, fracking companies that made forecasts are on course to pump almost 10 percent less oil and gas than they originally projected, WSJ reported Wednesday. This number is commensurate to nearly 1 billion barrels of oil and gas over three decades, and worth over $30 billion.

California 2018 crude-by-rail imports reach highest level since 2013-14: state – California crude imports by rail in 2018 rebounded from the year prior and are nearing levels not seen since the initial crude-by-rail heyday of 2013-14, according to the latest figures from the state government. California imported an average of 447,063 b/d in the first nine months of 2018, according to the latest figures from California Supply Analysis Office data shared Wednesday with S&P Global Platts. That is the highest level after a record high of 524,731 b/d in 2013 and 478,090 b/d in 2014. California receives crude by rail from New Mexico, Wyoming and Canada. The surge in imports in 2018 is due to exports more than doubling from New Mexico and Canada. New Mexico’s crude-by-rail to California in September was about 207,000 b/d compared with just over 80,000 b/d in January. Western Canada sent nearly 275,000 b/d in September compared with 116,000 b/d at the beginning of the year. In comparison, imports over 2018 from Wyoming, home to some of the Bakken shale formation, were essentially stable over the initial nine months at about 90,000 b/d. Canada’s oil industry has been forced to take a second look at crude by rail to alleviate what has been a glut of supply and no spare takeaway capacity. Pipelines are full and yet the production has continued to rise there, leading to record-high exports from the country to the US by rail. It is worth noting, however, that there is some discrepancy between California’s data and figures from Canada. In May-September of 2018, California reported imports of roughly 306,000 b/d of crude from Canada on average. Canada’s National Energy Board figures showed the country exported about 222,000 b/d during that time. Though the two agencies’ figures do not exactly align, it is clear Californian refiners are taking advantage of increased oil production in nearby regions as an offset to crude imported by water from outside North America.

Keeping watch, pipeline protesters brave cold nights on Burnaby Mountain – The pipeline protesters aren’t allowed to have heating or a fire but are persisting in their months-long vigil, keeping tabs on the nearby tank farm and standing in opposition to the planned expansion of the pipeline, which carries diluted bitumen from Alberta. The Watch House has stood just meters from the outer gate of the tank farm since March, when it was built in Forest Grove Park by members of the Tsleil-Waututh Nation. The cedar building hasn’t moved since, even as the nearby Camp Cloud protest camp was evicted forcefully by Burnaby RCMP and municipal staff. The Watch House was built in March, during a day of protest against the proposed expansion of a pipeline, which carries diluted bitumen from Alberta. – Jennifer Gauthier In September, Will George, a Tsleil-Waututh man designated as a guardian of the Watch House, told the NOW the structure was set to come down following the Federal Court of Appeal ruling that quashed federal approval of the pipeline’s proposed expansion. But that plan changed when it became clear Prime Minister Justin Trudeau planned to move forward with the project – now owned by the federal government. The nearby support camp, set up in a soccer field, came down voluntarily. Protests raged on the mountain and at the nearby Westridge Marine Terminal throughout the summer, at times resulting in daily arrests of demonstrators who allegedly violated a court injunction. But the blockades also stopped as the FCA ruling put a halt to the controversial expansion project. But the Watch House remains. Layden said he plans to keep sleeping in the cold until it’s time for the building to come down. That will only happen if a court orders its removal or the expansion project is cancelled once and for all, he said. Layden said locals regularly bring food and words of support. And a pair of Squamish carvers are working on a totem pole just outside the Watch House. The pole includes a watchman, the Watch House’s symbol; a wolf, the totem of the Tsleil-Waututh Nation; and Tahlequah, the mother orca also known as J35 who carried her dead calf for 17 days off the coast of B.C. and Washington this past summer.

Oil and Gas Commission Confirms Fracking Caused Earthquakes Felt by Hundreds – TheTyee.ca – British Columbia’s energy regulator confirmed that Canadian Natural Resources Ltd. caused three felt earthquakes while conducting hydraulic fracturing operations south of Fort St. John last month. In an industry bulletin, the regulator also revealed that CNRL well operators expected that “induced seismicity was likely to occur, but events larger than magnitude 3 were not expected.”Instead the company triggered events measuring magnitude 3.0, 4.0 and 4.5 on Nov. 29 that rattled homes and were felt by hundreds of citizens, as well as construction workers at the Site C dam site.“All hydraulic fracture operations within the lower Montney formation will remain suspended” at the CNRL well pad “pending the results of a detailed technical review,” said the bulletin. Gail Atkinson, one of Canada’s top seismic hazard experts, told The Tyee that if the magnitude 4.5 earthquake had occurred in a densely populated area it would have caused property damage. In 2017 fracking operations in Sichuan, China, did just that by triggering a similar sized tremor. Industry operations induced a magnitude 4.7 earthquake that damaged or destroyed nearly 600 homes. According to a 2017 study published in the science journal Nature, China’s fracking industry has triggered four magnitude 4.0 quakes or greater in addition to 2,400 smaller scale tremors in the Sichuan Basin, the country’s richest natural gas deposit. B.C.’s fracking industry has chalked up a similar record of seismic activity in the Montney basin, a major shale gas resource stretching across B.C. and Alberta. Since 2014, B.C.’s fracking industry has triggered thousands of quakes, including 43 greater than a magnitude of 3.0 and three greater than magnitude of 4.0, according to an Oil and Gas Commission presentation at a Banff scientific conference last October.

Opinion- Our house is on fire, and many Albertans want more lighters – Do we want to save the planet or get rich and watch it die? It boils down to this. 1) Albertans have become very wealthy by exporting fossil fuels. 2) Scientists state that the climate crisis is an existential threat to civilization. 3) The only way to minimize catastrophic climate change is to immediately decrease our fossil fuel use as quickly as possible. 4) 3 threatens 1. Let’s unpack some of this, shall we? 1) Due to geographical fortune, our province sits on a vast reservoir of fossil fuels: coal, natural gas and oil. With their high energy content and transportability, they have been highly desired for (historically) a much higher value than their extraction cost, which has made us extraordinarily rich. Even now, in the downturn, even as many people are hurting financially, we still have the highest average monthly income in Canada. Being rich is fun, and we don’t want it to end. The problem is Point 2. As time passes, and we put more and more greenhouse gases into the atmosphere, it’s becoming increasingly clear that all that we love is at risk. Our ecosystems, food systems, economic systems, life support systems. Scientists are talking about a doomsday scenario where it all just collapses, within our lifetimes, if we don’t act now. There is this persistent hope that we here in Alberta we’ll be somehow spared from this fate. We live up in the North, so we’ll just get nicer winters. And the joys of being landlocked is we don’t even have a coastline to deal with as the seas rise. These are false hopes. Of the five most costly natural disasters in Canadian history, three have occurred in Alberta, all in the last decade. And it is going to get much, much worse as temperatures rise. We are not safe

Downtown Gatineau oil spill contaminates Ottawa River – A large but undefined amount of heating oil has found its way into the Ottawa River following a spill in downtown Gatineau. The spill ironically occurred near the offices of the provincial environment ministry. According to ministry spokesperson and Outaouais Environmental Control Center regional director Alexandre Ouellet, the spill happened at 170 rue de l’Hôtel de Ville during a delivery the week before Christmas. An initial statement by the Quebec Ministry of Environment and Fight Against Climate Change said that the spill was between 700 and 1,200 litres. A later report pegged the spilled amount to around 200 to 300 litres. Ouellet said that the oil spilled on to the pavement and found its way into a storm drain, which flows into the Ottawa River. The minister offered assurances that an environmental emergency team has been dispatched to mitigate the damage and to ensure the safety of the public. The minister additionally claimed in a statement on December 23 that the impact of the spill to the river is still low. CBC News reported that the Ottawa River is a source of potable water for up to two million people. “An oil spill in the aquatic environment is never good news,” said Patrick Nadeau, executive director of Ottawa Riverkeeper, a charity organization dedicated to keeping the river and its tributaries safe. Nadeau added that the oil spilled into the river while it was still covered in ice, which could complicate any clean-up.

Arctic refuge moves closer to opening for oil – The Trump administration moved closer on Dec. 20 to opening thousands of miles within Alaska’s pristine Arctic National Wildlife Refuge to oil and gas leasing, issuing a draft report that concluded the polar bears, caribou and other wildlife could safely share their untouched wilderness with oil and gas producers. The report released by the Bureau of Land Management studied the environmental impact of opening between two-thirds and all of 1.65 million acres of coastal plain within the remote refuge for oil and gas leasing. Release of the legally required environmental impact statement marks one of the last major actions in office by Interior Secretary Ryan Zinke, an ardent supporter of the oil and gas industry who leaves office Jan. 2 amid ethics investigations. In a statement, Zinke called the step toward opening Alaska’s North Slope for oil and gas development a move toward an “energy-dominant America.” A strong leasing program within the wilderness area “helps us realize our tremendous energy potential without harming our environment or way of life,” said Sen. Lisa Murkowski, R-Alaska, chairwoman of the Senate’s Energy and Natural Resources Committee, in another statement.The administration’s environmental review acknowledged that opening the coastal plains within the nation’s largest wildlife refuge would impact Alaska Native hunters, as well as caribou herds and other arctic animals and migratory birds that depend upon the refuge. The report concluded, however, that the lease sales could be carried out “while balancing biological and ecological concerns.”

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