Written by rjs, MarketWatch 666
Here are some selected new articles from the week ended 10 February 2019.
This article is a feature every Monday evening on GEI.
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Not out of the woods on natural gas stores; EIA will report record oil production in excess of 12 million bpd next week
Oil prices gave up last week’s gains and then some this week, while still remaining in the same narrow range they’ve been in over the past month…after rising nearly 3% to $55.26 a barrel on the new sanctions on Venezuelan oil exports last week, prices for US oil for March delivery fell 70 cents to $54.56 a barrel on Monday, after unexpected weakness in U.S. factory data raised concerns that an economic slowdown would reduce demand for oil…oil prices then fell another 90 cents to $53.66 on Tuesday, after a survey showing that euro zone business expansion had nearly stalled in January heightened concerns about a global economic slowdown….however, oil prices reversed early losses on Wednesday, after the weekly EIA data showed a drop in product inventories and a smaller rise in U.S. crude stockpiles than the Tuesday API report suggested, and went on to close up 35 cents for the day at $54.01 a barrel…selling returned on Thursday, with March crude prices tumbling 2.5% to $52.64 a barrel, amid indications that the trade war between the U.S. and China would continue….oil prices managed to gain 8 cents against a strong dollar to close at $52.72 a barrel in quiet trading on Friday, but still ended the week 4.6% lower–the largest weekly percentage loss for a front-month contract since the week ended Dec. 21…
Meanwhile, natural gas prices continued lower after falling to a 28 week low last week, as the March contract ended this week down 15.1 cents at $2.583 per mmBTU, the lowest closing price since last March, despite an EIA gas storage report that showed the largest draw this season…the natural gas storage report for the week ending February 1st from the EIA indicated that the quantity of natural gas held in storage in the US fell by 237 billion cubic feet to 1,960 billion cubic feet over the week, which meant our gas supplies were 135 billion cubic feet, or 6.4% below the 2,095 billion cubic feet that were in storage on February 2nd of last year, and 414 billion cubic feet, or 17.5% below the five-year average of 2,375 billion cubic feet of natural gas that have typically been in storage as of the 1st weekend in February….this week’s 237 billion cubic feet withdrawal from US natural gas supplies was somewhat less than the S&P Global Platts’ survey of analysts expectations that 249 billion cubic feet of stored gas would be needed, but it was quite a bit more the average of 150 billion cubic feet of natural gas that have been withdrawn from US gas storage during the same winter week over the last 5 years…
With the polar vortex pushing temperatures more than 20 degrees below normal, 84 billion cubic feet of natural gas were needed frpm storage in the Midwest during the week, well above the normal 51 billion cubic foot pull for the region, and as a result the region’s natural gas supply deficit increased to 14.7% below normal for this time of year, while at the same time natural gas supplies in the South Central region fell by 79 billion cubic feet, as their supply deficit increased to 12.2% below the normal for the first weekend of February…the Eastern states also saw an above normal withdrawal of 59 billion cubic feet of gas, as their natural gas deficit increased to 11.7% below their 5 year average of gas stores at the beginning of February….9 billion cubic feet were pulled out of natural gas supplies in the sparsely populated Mountain region, which normally pulls out 7 billion cubic feet for the same week, as their deficit from normal rose to 26.1%, but since temperatures in the Pacific states stayed above normal during the polar vortex, they only needed 6 billion cubic feet of gas from storage for the week, and their deficit from normal fell to 25.9% below their five year average for this time of year as a result…
While the EIA reports that “total working gas is within the five-year historical range”, that’s because the 5 year reference period includes 2014, which saw multiple outbreaks of the polar vortex, with a withdrawal of 990 billion cubic feet over 4 weeks in February that helped drive that year’s natural gas supplies to the lowest on record by the end of March…we certainly don’t expect to approach that kind of cold anymore this year, but the temperatures after January of last year were not exceptional, and yet we still approached the current heating season with our natural gas supplies at the lowest level in 15 years…since our natural gas supplies are 6.4% below those of a year ago as of this week, it will take smaller withdrawals through the remainder of this winter and/or larger inventory building this spring and fall to avoid entering the winter of 2020 in the same or worse shape than we entered this one…that fact isn’t lost on natural gas traders, who are still pricing natural gas for January 2020 delivery more than 15% higher than the price of the front month contract for natural gas today…
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 February 1st, indicated that we again managed a modest addition of surplus oil to our commercial crude supplies, despite a big jump in our crude oil exports, largely because of a large swing from unaccounted for crude demand to unaccounted for crude supply…our imports of crude oil rose by an average of 63,000 barrels per day to an average of 7,146,000 barrels per day, after falling by an average of 1,108,000 barrels per day the prior week, while our exports of crude oil rose by an average of 926,000 barrels per day to an average of 2,870,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 4,276,000 barrels of per day during the week ending February 1st, 863,000 fewer barrels per day than the net of our imports minus exports during the prior week…over the same period, field production of crude oil from US wells was estimated to be unchanged at a record 11,900,000 barrels per day, so our daily supply of oil from the net of our trade in oil and from wells totaled an average of 16,176,000 barrels per day during this reporting week…
Meanwhile, US oil refineries were using 16,633,000 barrels of crude per day during the week ending February 1st, 170,000 more barrels per day than the amount of oil they used during the prior week, while over the same period 180,000 barrels of oil per day were reportedly being added to the oil that’s in storage in the US….thus, 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 637,000 fewer barrels per day than the oil that was added to storage plus what refineries reported they used during the week….to account for that disparity between the supply of oil and the disposition of it, the EIA inserted a (+637,000) 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”…since that “unaccounted for crude” figure was at minus 445,000 barrels per day the prior week, it represents a swing of 1,082,000 barrels per day in that error margin, enough to consider this week’s week over week changes very unreliable….(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 7,487,000 barrels per day last week, which was 7.3% less than the 8,078,000 barrel per day average that we were importing over the same four-week period last year…. the 180,000 barrel per day increase in our total crude inventories was all added to our commercially available stocks of crude oil, while the oil stored in our Strategic Petroleum Reserve remained unchanged….this week’s crude oil production was reported unchanged at 11,900,000 barrels per day because the rounded estimate for output from wells in the lower 48 states was unchanged at 11,400,000 barrels per day, while a 9,000 barrel per day increase to 498,000 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 February 2nd was at 10,251,000 barrels per day, so this week’s rounded oil production figure was 16.1% above that of a year ago, and 41.2% 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…
As we’ve often mentioned, these weekly oil production figures we report are preliminary, and the EIA also releases confirmed monthly oil production figures a few months later, after they have collected all the precise production reports that aren’t available on a weekly basis….that monthly report for November was released this week, and since the monthly data shows a production jump that’s not yet reflected in the weekly figures, we’ll include a graphic showing both, so we can see what that difference looks like…
The above graph was taken from this week’s OilPrice Intelligence Report, and it shows the history of confirmed oil production data monthly from January 2016 to November 2018 in blue, and then the weekly estimates of US oil production up until the current week in yellow after that period, with both metrics in thousands of barrels per day (note the yellow arrow is a bit off)….above the graph, OilPrice also gives us the rounded weekly estimates of oil production in thousands of barrels per day for the weeks ending December 28th through February 1st, as was reported by the EIA….we follow that weekly data because it’s what the oil traders follow, and hence it moves oil prices and ultimately the decisions on the part of exploitation companies to start drilling for oil…however, the confirmed oil production figures for November were released this week and showed our crude production at a higher than expected 11,900,000 barrels per day average during that month, up from the confirmed 11,555,000 barrels per day in October…the weekly production estimates for November, on the other hand, had ranged from 11,600,000 barrels per day to 11,700,000 barrels per day, and thus averaged 220,000 barrels per day lower than the confirmed figures….when the confirmed oil production figure comes in that much higher than the weekly estimates, the EIA will subsequently adjust their weekly estimate to reflect the new confirmed production totals…hence, it’s reasonable to assume that EIA’s production estimate for next week will be at least at 12,100,000 barrels per day, and most likely higher, hence topping 12 million barrels per day for the first time in history…
US oil refineries were operating at 90.7% of their capacity in using 16,633,000 barrels of crude per day during the week ending February 1st, up from the prior week’s 90.1% of capacity, and a fairly high capacity utilization rate for this time of year….however, the 16,633,000 barrels per day of oil that were refined this week were 1.0% below the 16,797,000 barrels of crude per day that were being processed during the week ending February 2nd, 2018, when US refineries were operating at an even higher 92.5% of capacity…
Even with the modest increase in the amount of oil being refined, the gasoline output from our refineries was a bit lower, falling by 48,000 barrels per day to 9,856,000 barrels per day during the week ending February 1st, after our refineries’ gasoline output had increased by 300,000 barrels per day the prior week….with the decrease in this week’s gasoline output, our gasoline production was 2.3% lower than the 10,085,000 barrels of gasoline that were being produced daily during the same week last year….meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 102,000 barrels per day to 5,121,000 barrels per day, after that output had decreased by 185,000 barrels per day the prior week….with that increase, this week’s distillates production was little changed from the 5,129,000 barrels of distillates per day that were being produced during the week ending February 2nd, 2018….
Despite the decrease in our gasoline production, our supply of gasoline in storage at the end of the week rose by 513,000 barrels to 257,893,000 barrels by February 1st, after falling by 2,235,000 barrels over the prior week….our gasoline supplies rose this week mostly because the amount of gasoline supplied to US markets fell by 491,000 barrels per day to 9,073,000 barrels per day, after increasing by 999,000 barrels per day over the prior two weeks, and because our imports of gasoline rose by 102,000 barrels per day to 625,000 barrels while our exports of gasoline rose by 288,000 barrels per day to 895,000 barrels per day….having set a record high two weeks ago, our gasoline inventories are still at a seasonal high for the first weekend of February, 5.1% higher than last February 2nd’s level of 245,474,000 barrels, and roughly 5% above the five year average of our gasoline supplies for this time of the year…
Although there was an increase in our distillates production, our supplies of distillate fuels decreased for the 14th time in twenty weeks, falling by 2,257,000 barrels to 139,013,000 barrels during the week ending February 1st, after our distillates supplies had decreased by 1,122,000 barrels over the prior week…our distillates supplies decreased this week because the amount of distillates supplied to US markets, a proxy for our domestic demand, jumped by 551,000 barrels per day to 4,673,000 barrels per day, not surprising given the heating needs for the week, while our exports of distillates rose by 37,000 barrels per day to 1,229,000 barrels per day and our imports of distillates rose by 324,000 barrels per day to 459,000 barrels per day…with this week’s decrease, our distillate supplies are now 2.0% below the 141,826,000 barrels that we had stored on February 2nd, 2018, and fell to roughly 4% below the five year average of distillates stocks for this time of the year…
Finally, with the caveat that the source of much of this week’s crude supply was unaccounted for, our commercial supplies of crude oil in storage increased for the 4th time in the past 10 weeks, rising by 1,263,000 barrels over the week, from 445,944,000 barrels on January 25th to 447,207,000 barrels on February 1st…with weekly increases now in 14 out of the last 20 weeks, our crude oil inventories are roughly 6% above the five-year average of crude oil supplies for this time of year, and nearly 30% above the 10 year average of crude oil stocks for the first weekend of February, with the disparity between those figures arising because it wasn’t until early 2015 that our oil inventories first rose above 400 million barrels…since our crude oil inventories had mostly been rising since this past Fall, after falling until then through most of the prior year and a half, our oil supplies as of February 1st were thus 6.4% above the 420,254,000 barrels of oil we had stored on February 2nd of 2018, while still remaining 12.1% below the 508,592,000 barrels of oil that we had in storage on February 3rd of 2017, and 5.0% below the 470,676,000 barrels of oil we had in storage on February 5th of 2016…
This Week’s Rig Count
US drilling activity, as evidenced by the number of drilling rigs active at the end of the week, increased for the second time in 6 weeks this past week, but still remains well below the levels of October and November, when both oil and natural gas prices were considerably higher….Baker Hughes reported that the total count of rotary rigs running in the US rose by 4 rigs to 1049 rigs over the week ending February 8th, which was also 74 more rigs than the 975 rigs that were in use as of the February 9th 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 rose by 7 rigs to 854 rigs this week, which was also 63 more oil rigs than were running a year ago, while it was well below the recent high of 1609 rigs that were drilling for oil on October 10th, 2014…at the same time, the number of drilling rigs targeting natural gas bearing formations decreased by 3 rigs to 195 natural gas rigs, which was still 11 more rigs than the 184 natural gas rigs that were drilling a year ago, but way down from the modern era high of 1,606 natural gas targeting rigs that were deployed on August 29th, 2008…
Offshore drilling activity was unchanged, with 19 rigs still deployed in the Gulf of Mexico this week, with all of those offshore from Louisiana…that was still 3 more Gulf rigs than were drilling a year earlier, when 15 rigs were deployed offshore from Louisiana and a rig was also active offshore from Texas….since there is still no other offshore drilling off either coast or off Alaska at this time, nor was there during the same week of 2018, this week’s Gulf of Mexico totals are again identical to the overall US offshore totals…
The count of active horizontal drilling rigs decreased by 2 rigs to 923 horizontal rigs this week, which was still 91 more horizontal rigs active than the 832 horizontal rigs that were in use in the US on February 9th of last year, but was down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014….on the other hand, the vertical rig count increased by 5 rigs to 68 vertical rigs this week, which was still down from the 70 vertical rigs that were in use during the same week of last year…meanwhile, the directional rig count increased by 1 rig to 58 directional rigs this week, which was also down from the 73 directional rigs that were operating on February 9th 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 February 8th, the second column shows the change in the number of working rigs between last week’s count (February 1st) and this week’s (February 8th) count, the third column shows last week’s February 1st active rig count, the 4th column shows the change between the number of rigs running on Friday and those running before the equivalent weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 2nd of February, 2018…
As you can see, this week’s rig increases were primary in Alaska and California, both major producing states, but neither of which have been in the vanguard of new drilling activity in recent years…we didn’t see any news on where new drilling might be taking place in Alaska, but considering the time of year, it’s unlikely it was anywhere on the North Slope or in the Arctic National Wildlife Refuge, where the administration is barreling ahead with plans to drill for oil…even with those Alaska and California increases, however, the state totals shown above don’t add up to the 4 rig increase we reported, because Mississippi drillers also added a rig this week and now have 4 rigs running, up from 3 rigs a year ago…while the major basin count does reflect the decrease of 2 horizontal rigs, that doesn’t mean there weren’t changes elsewhere, just that the additions and subtractions in those ‘other’ basins netted out to zero…that’s obvious from the natural gas rig count changes, which showed one natural gas rig added in the Dallas / Ft Worth area Barnett shale, where an oil rig was concurrently pulled out, one natural gas rig pulled out of the south Texas Eagle Ford, which saw two oil rigs added at the same time, and 3 natural gas rigs pulled out of basins not tracked separately by Baker Hughes…meanwhile, it looks like the three rig decrease in the Permian was spread out across the basin, with one rig pulled from Texas Oil District 8, which would be the core Permian Delaware, one rig pulled from Texas Oil District 7C, which would be the southern Permian Midland, and one Permian rig pulled out of the Permian Delaware in New Mexico…
Ohio Utica well permits rose in January – Permits to drill wells in Ohio’s Utica shale rose slightly in January from the month prior. The state approved 58 permits in January, up by eight permits from December 2018, according to data from the Ohio Department of Natural Resources. December permits soared by 92pc from November, likely on the start-up of more takeaway capacity from the Appalachian production region and expectations of increased winter demand. Monthly permit counts have rebounded recently after spending much of 2018 below levels in 2017. January permits were more than double the 26 approved in January 2018, while December permits were 19pc higher than a year earlier. Permits issued per month in 2018 ranged from nine to 50, and totaled 253 for the full year, a 44pc drop from total permits issued in 2017. Spot natural gas prices at Dominion Transmission South in January averaged $2.85/mmBtu, 10pc lower than a year earlier. Argus forward prices show Dominion South averaging $2.42/mmBtu in March, suggesting lower demand next month. Production in the Appalachia shale region in December topped 31.1 Bcf/d, according to estimates from the US Energy Information Administration, with January output expected to rise above 31.3 Bcf.
Ohio residents file federal civil rights lawsuit, stemming from fracking concerns – (WKBN) – Members from seven community groups in Ohio have filed a federal civil rights lawsuit against their board of elections and the Ohio Secretary of State. The complaint stems from citizens wanting a frack-free community and it claims officials have violated the plaintiffs’ constitutional rights of freedom of speech, right of assembly, right to petition the government for redress of grievances, right to vote, right of due process, and right of local, community self-government.The lawsuit claims the plaintiff communities have collected signatures to place initiatives on the ballot at some point between 2015 and 2018 and that all the communities have been blocked from the ballot by the defendants’ “unlawful actions.”The complaint describes these actions as “placing unlawful blockades, insurmountable hurdles, and arbitrary and irrational procedures between the people of Ohio and their exercise and enjoyment of direct democracy.”Members of Frackfree Mahoning Valley, say they have attempted to exercise the right to initiative by preparing and collecting signatures for proposed amendments to the Youngstown Municipal Charter.The proposed charter amendments have addressed such issues as community rights, a ban on horizontal hydraulic fracturing (fracking) for oil and gas, the right to clean water, and the right to free and fair elections. The seven groups filing the suit are from several Ohio cities and counties, including Youngstown, Toledo and Columbus, as well as Portage, Medina, Athens and Meigs counties. “Our government is based on the premise that the people create government to protect their rights and that when government is no longer doing that, the people have the right to alter, reform or abolish that government and form a new one that does,” said Susie Beiersdorfer, Youngstown Plaintiff. “When the very government that is violating the people’s rights is blocking them from making change, we cannot accept this. We need to challenge it and protect our right to self-govern. In Ohio, we need to protect our right to direct democracy through the initiative process. That is what this lawsuit is about.” You can read the full Lawsuit here.
Environmentalists from Youngstown, six counties file federal lawsuit – WFMJ– A coalition of activists from Youngstown and other parts of Ohio have filed a federal lawsuit accusing the state and local elections boards of violating their constitutional rights by preventing voters from deciding environmental issues. The 62-page civil suit was filed in U.S. District Court by members of grassroots environmental groups in seven Ohio counties, including Susie Beiersdorfer and Dario Hunter of Frackfree Mahoning Valley, which has been unsuccessful eight times in backing a ballot issue to ban fracking inside Youngstown city limits. In addition to former Ohio Secretary of State Jon Husted, the boards of elections in Mahoning and six other counties are named as defendants. The lawsuit claims that election boards and the Ohio Secretary of State have violated the groups’ constitutional right to free speech and due process by rejecting petitions signed by hundreds and thousands of registered voters seeking ballot space on issues dealing with clean water, fracking, injection wells, and other environmental concerns. The groups say election officials and the Secretary of State should not be allowed to keep questions from the voters based on the content of the issues. The suit also challenges the constitutionality of House Bill 463 passed in 2017 which the lawsuit says further enforces the ability of election boards to reject voter initiatives based on the content of those initiatives. In addition to Frackfree Mahoning Valley, other plaintiffs include members of the Columbus Community Rights Group which failed to place an anti-fracking issue on the ballot after it was rejected by the Franklin County Board of elections. Members of Toledoans for Safe Water claim in the lawsuit that Lucas County Board of Elections rejected their initiative to enact a “Lake Erie Bill of Rights” after algae blooms in the lake caused a shutdown of the regional water supply in 2014. The Meigs County Home Rule Committee’s efforts to enact a home rule charter that included bans on underground injection wells was rejected by the Secretary of State, according to the lawsuit. In southeastern Ohio, the Athens Community Bill of Rights Committee circulated petitions for a county-wide vote to ban injection wells was rejected by the Athens County Board of Elections. Efforts by Sustainable Medina County included an effort to put a stop to the Nexus gas pipeline, which runs from Columbiana County to Michigan. The lawsuit says petitions for a county charter initiative opposing the pipeline were rejected by then Secretary of State Husted. A county charter initiative that would have included prohibitions on fracking and injection wells by the Portage Community Rights Group was given a thumbs down by the Portage County Board of Elections. The suit asks a federal judge to declare as unconstitutional, parts of House Bill 463 that allows the review of ballot initiatives based on their content.
Environmental advocates sue over Ohio’s methods of reviewing ballot measures – cleveland.com – Members of environmental activist groups in seven Ohio counties sued Republican Secretary of State Frank LaRose and several boards of elections over what it said were unconstitutional tactics that kept certain ballot initiatives from going in front of voters.The lawsuit, filed Friday in federal court in Youngstown, says the system the state has to set up to approve and deny ballot measures violates the First Amendment and other constitutional rights because elections boards and the secretary of state are allowed to review the substance of the measures, instead of just seeing whether those measures conform with state elections law.The activists come from Athens, Franklin, Lucas, Mahoning, Medina, Meigs and Portage counties and all say their measures were unconstitutionally blocked from the ballot. State courts, including the Ohio Supreme Court, previously ruled against placing on the ballot many of the measures the groups wanted to put in front of voters.“For several years, Ohio election statutes have unconstitutionally restricted Plaintiffs’ rights to place proposed measures on the ballot by allowing Defendants to engage in content-based, pre-enactment review of proposed ballot measures,” the lawsuit states.(You can read the lawsuit here or at the bottom of this story.)The lawsuit asks a federal judge to invalidate sections of Ohio law “that permit substantive, content-based review” by elections officials. Among those suing are members of Sustainable Medina County, an environmental advocacy group that sought to place proposals on the ballot that would ban fracking, oil injection wells and oil pipelines from going through the county. The group vociferously opposes the installation of a natural gas pipeline that will run from Ohio to Canada, the lawsuit states. The Medina County Board of Elections certified the group’s petition in 2015, but someone protested. Then-Secretary of State Jon Husted, now the lieutenant governor, subsequently invalidated the group’s petition and the Ohio Supreme Court upheld Husted’s decision, the lawsuit notes.The group altered and re-submitted petitions in 2016 and 2017, but Husted again denied them. The courts provided the group no relief, according to the lawsuit.Similarly, the Portage Community Rights Group tried in 2016 to place a measure on the ballot in Portage County that, among other things, would prohibit fracking and injection well usage. The county elections board denied the measure, saying the governmental structure proposed under the measure did not include a county executive, according to the lawsuit. Husted denied the group’s protest and told the elections board not to place the measure on the ballot. The Ohio Supreme Court later upheld that decision, the suit states.
Northeast Ohio Could be Looking at a New Economic Boost from Underground – Ethane is critical for making things like polymers, plastic, and paint. It’s also a companion product from natural gas wells–and wells in Ohio’s Utica shale are typically rich with it. A U.S. Energy Information Administration report finds the country is now leading the world in an international export market for ethane.University of Akron economist Amada Weinstein says that might mean a resurgence of drilling. And it may convince companies thinking about building multi-billion dollar chemical processing facilities known as crackers to go ahead and do so. “Yes. So basically, if prices are going up for these petrochemicals for polymers then they have even more incentive to build these cracker plants being built in Pennsylvania and other places.” According to state figures, there has been in excess of $63-billlion in investment in shale development in the Ohio since 2011. (see comments)
“Salt Water Disposal Wells” (SWD) Are Contaminating Our Region in PA, WV & OH – From a Study by Matt Kelso, FracTracker Alliance, January 31, 2019 – Oil and gas development generates a lot of liquid waste. Some of the waste comes that comes out of a well is from the geologic layer where the oil and gas resources are located. These extremely saline brines may be described as “natural,” but that does not make them safe, as they contain dangerous levels of radiation, heavy metals, and other contaminants. Additionally, a portion of the industrial fluid that was injected into the well to stimulate production, known as hydraulic fracturing fluid, returns to the surface. Some of these substances are known carcinogens, while others remain entirely secret, even to the personnel in the field who are employed to use the additives. In many states, much of this waste is disposed of in facilities known as salt water disposal (SWD) wells, a specific type of injection well. These waste facilities fall under the auspices of the US Environmental Protection Agency’s Underground Injection Control (UIC) program. Such wells are co-managed with states’ oil and gas regulatory agencies, although the specifics vary by state. The oil and gas industry in Pennsylvania has not used SWD wells as a primary disposal method, as the state’s geology has been considered unsuitable for this process. The ban on surface “treatment” being discharged into Pennsylvania waters has increased the pressure for finding new solutions for brine disposal. This is compounded by the fact that the per-well volume of fluid injected into shale gas wells in the region has nearly tripled in that time period. Much of what is injected comes back up to the surface and is added to the liquid waste stream. Chemically-similar brine from conventional wells has been spread on roadways for dust suppression. This practice was originally considered a “beneficial use” of the waste product, but the Pennsylvania Department of Environmental Protection (DEP) halted that practice in May 2018. There are numerous concerns with salt water disposal wells. In October 2018, the PA-DEP held a hearing in Plum Borough, on the eastern edge of Allegheny County, where there is a proposal to convert the Sedat 3A conventional well to an injection well. Some of the concerns raised by residents include:
- >>> Fluid and/or gas migration – There are numerous routes for fluids and gas to migrate from the injection formation to drinking water aquifers or even surface water. Potential conduits include coal mines, abandoned gas wells, water wells, and naturally occurring fissures in crumbling sedimentary formations.
- >>> Induced seismicity – SWD wells have been linked to increased earthquake activity, either by lubricating or putting pressure on old faults that had been dormant. Earthquakes can occur miles away from the injection location, and in sedimentary formations, not just igneous basement rock.
- >>> Noise, diesel pollution, loss of privacy, and road degradation caused by a constant stream of industrial waste haulers to the well location.
- >>> Complicating existing issues – Plum Borough and surrounding communities are heavily undermined, and in fact the well bore goes right through the Renton Coal Mine (another part of which has been on fire for decades). Mine subsidence is already a widespread issue in the region, and many fear that even small seismic events could exacerbate this.
- >>> Possibility of surface spill – Oil and gas is, sadly, a sloppy industry, with unconventional operations having accumulated more than 13,000 violations in Pennsylvania since 2008. If a major spill were to happen at this location, there is the possibility of release into Pucketa Creek, which drains into the Allegheny River, the source of drinking water for multiple communities.
- >>> Radioactivity and other contaminants – Flowback fluids are often highly radioactive, contain heavy metals, and other contaminants that are challenging to effectively clean. The migration of radon gas into homes above the injection formation is also a possibility.
Marathon working to fix flare at Detroit refinery that caused odor – Marathon Petroleum Corp. said it was working to fix a malfunctioning flare at its Detroit refinery that created a pungent odor that permeated the air in metro Detroit on Sunday morning. “We don’t have an estimate for when the repair work will be complete, but we have significantly reduced the amount of material going to the flare, and anticipate being able to de-pressure the vessels connected to the flare by the end of the day tomorrow,” Marathon anticipates workers will finish removing the contents of the vessels connected to the flare by the end of the day on Monday, and this will allow them to deactivate the flare. At that point, repair work will begin, he said. According to the statement, Marathon believes the odor is largely from mercaptan, which is a substance added to natural gas to give it a detectable smell. The statement added that an investigation to determine what caused the release is ongoing, and once that is determined, Marathon plans to implement “necessary corrective actions so that this does not happen again.” The Marathon refinery is located in southwest Detroit and borders the city of Melvindale, Kheiry said. Wind blowing from the west carried the odor north and northeast. Some people noticed it miles away in Warren in Macomb County. Early Sunday, around 4 a.m., Michigan State Police and local 9-1-1 centers began receiving phone calls from metro Detroit residents reporting a strong odor permeating the air, MSP said. In a series of tweets, MSP said it suspected that the smell was coming from Marathon Oil properties, and that its Emergency Management and Homeland Security Division has been in contact with Marathon, plus local authorities around the Detroit/Dearborn border. “At this time Marathon still shows NO air quality issues on their meters,” MSP said in a tweet. “Based on wind direction Marathon agrees their facility could be the source.”
Consumers fire highlights ongoing gas safety issues in Michigan, regulator says – The fire at Consumers that put Michigan in a precarious natural gas situation during the bitter cold last month is one in a series of concerning natural gas incidents, the Michigan Public Service Commission said when it opened an investigation into the matter Thursday.The commission will investigate a Jan. 30 fire at the Consumers Ray Natural Gas Compressor Station in Macomb County that jeopardized heat for Michigan residents during a period of extreme cold. Consumers avoided service interruptions by securing agreements from large energy users to cut back and asking residents to voluntarily turn down their heat to 65 degrees. “Events of the past week, let alone the past year, have significantly heightened the Commission’s safety concerns with Michigan gas utilities,” said Commissioner Norman Saari.He pointed to numerous recent natural gas issues, including aPontiac explosion and a Warren gas line issue.Commission Chair Sally Talberg said in a number of these incidents no one has been injured, but it’s an issue the commission sees and is following.And part of it, she said, comes down to infrastructure.“The gas distribution lines, a lot of them are quite old, they were made of cast iron or bare steel,” she said. “Since 2011 we’ve accelerated the replacement of those so that we can protect against accidents.” Talberg said any time there was an explosion MPSC staff were on-site taking measurements and data to identify the cause and any potential violations. But in this case the commission opened a more formal investigation because of the broad impacts on customers.
Group raises questions about Enbridge’s insurance on Line 5 – A new report says the State of Michigan did not thoroughly review Enbridge’s ability to cover costs in the case of a spill from its twin Line 5 oil pipelines before it signed an agreement with the company. The pipelines run underneath the Straits of Mackinac. Water law non-profit “For Love of Water,” or FLOW, released a report saying both Wisconsin and Minnesota have hired experts to assess Enbridge’s insurance on its projects in those states, but Michigan has not done the same. Skip Pruss, FLOW’s board chair, said that both assessments in other states found problems with Enbridge’s coverage.“Given the fact that our two sister states did comprehensive background analyses and risk management studies and employed experts to do it, we wanted to know what Michigan has done,” he said. “Michigan apparently hasn’t done any expert review. No experts have been retained.”Pruss called Enbridge’s Line 5 insurance “likely deficient and inadequate,” based in part on consultations FLOW had with the firm that did assessments in Wisconsin and Minnesota.Additionally, the report details six specific concerns with Line 5’s spill coverage, including the dollar amount of insurance and whether it extends to Enbridge subsidiaries.FLOW released the report during a joint press conference with the group “Oil and Water Don’t Mix” and the tribal chairman of the Bay Mills Indian Community, Bryan Newland. Newland spoke about his ongoing concern that a Line 5 spill would irreparably damage the ancestral lands of indigenous people in the area.”We enjoy a treaty right to use the waters of the Great Lakes for fishing for commercial purposes and also subsistence, and no amount of financial insurance is going to be able to replace that if it’s gone,” he said. “When the integrity of our sacred locations is disrupted, it can’t be repaired by purchasing another place or by getting an insurance check.” The Line 5 pipelines carry up to 23 million gallons of crude oil daily.
State, crews monitoring problem in deep gas well in Westmoreland County – CNX Resources Corp. has spent the past week trying to get a Utica Shale well near the Beaver Run Reservoir in Westmoreland County under control after a problem there was followed by gas pressures spiking at nearby shallow wells. The Cecil-based oil and gas firm was fracking its Shaw 1G well in Washington Township on Jan. 26 when it detected a strong drop in pressure, the company told environmental regulators. It stopped fracking and found some type of obstruction in the well bore, said state Department of Environmental Protection spokeswoman Lauren Fraley. CNX also told the DEP that four conventional – that is, shallower, vertical wells – nearby showed spikes in pressure, a sign of communication between the gas in the Utica well and the four other wells in the vicinity. Neighbors described a parade of trucks and hard-hatted workers dispatched to the Shaw pad and to properties with shallow wells, some of which are being flared to relieve the pressure. Residents were on guard about the activity – and what it might mean for conventional wells on their properties. A DEP crew has been stationed at the site around the clock and will remain there until “we feel confident that the situation is under control,” Ms. Fraley said. A special well control team had been summoned from out of state to “kill” the well, a procedure that involves pumping heavy mud into the wellbore to stop the flow and keep it down. That had not yet happened by Saturday evening. The path of the well travels under the reservoir but it isn’t clear how far along that path the well had been fracked when the problem occurred. According to the well records available in DEP’s database, the Shaw 1G well plunged 13,740 feet below the surface, more than 2 miles deep, and extended some 8,000 feet horizontally. It is not yet known how the gas from it impacted the four conventional wells that are many thousands of feet shallower.
CNX says Utica well now under control, after more shallow wells saw pressure spikes. – CNX Resources Corp. reported Tuesday morning that the operation to bring its problematic Utica Shale well in Westmoreland County under control was successful. “While we continue to evaluate the cause of the initial pressure anomaly, we believe it is isolated to this well,” the company said in a statement. “As a precaution, we will continue to monitor the well for the next several days.”Containing the deep, horizontal well meant pumping very heavy mud into the wellbore, a process that began Monday afternoon. The problem began a week from Saturday, when CNX was fracking its Utica Shaw 1G well and lost pressure on it. Over the next week, the company discovered pressure spikes at nine nearby conventional wells, which it was flaring on Monday to relieve the pressure. The company has expanded the search for pressure anomalies in nearby conventional wells to a 2-mile-radius from the farthest impacted well, Department of Environmental Protection spokeswoman Lauren Fraley said Monday. “This includes the discovery of an unpermitted private gas well,” she said. This means that more wells could potentially be diagnosed as impacted, as the company works its way through the area. It is still not clear what went wrong with the Utica well or how its problem ended up impacting wells thousands of feet away. Ms. Fraley noted that no environment damage has been reported by field staff at the agency’s oil and gas, safe drinking water and air quality departments.None of the impacted conventional wells are in the path of the Shaw 1G, which runs more than a mile in a southeast direction. Instead, the overpressured wells are to the north, west, and east of the Utica well.
Utica shale gas well in Washington Township contained – CNX Resources contained a Utica shale gas well that experienced a significant drop in pressure last week, the company said Tuesday. Well “killing” operations on Shaw 1G well in Washington Township began at about 5 p.m. Monday and were completed by 11 p.m., said Lauren Fraley, spokeswoman for the state Department of Environmental Protection’s Southwest Regional Office. Killing involves pumping heavy mud and cement into the well, essentially sealing it off. “We are still evaluating next steps for the Shaw 1G well and the other three wells on that pad,” CNX spokesman Brian Aiello said, noting well drilling was completed Jan. 5 and fracking started the next day. The Canonsburg-based company experienced a significant loss of pressure with the new well during fracking operations Jan. 26, Fraley said. The pressure decrease was accompanied by “potential communication with other nearby conventional wells,” she said. CNX has since expanded flaring to nine conventional wells in the vicinity of the Shaw 1G well, she said. The DEP describes flaring as a combustion device used to control emissions by burning off flammable gas, often to reduce pressure. In the meantime, fracking operations on the four-well Shaw pad, on the northwestern side of Beaver Run Reservoir, have been suspended while CNX investigates the cause of the incident, the company said in a statement. “We believe it is isolated to this well,” the statement said. Fracking has been occurring near Beaver Run Reservoir, source of water to about 130,000 people in northern Westmoreland County, since 2011. The seven CNX well pads on property owned by the Municipal Authority of Westmoreland County currently have 45 Marcellus wells and seven Utica wells, the company said. The municipal authority operates the George R. Sweeney Water Plant at Beaver Run Reservoir, which serves 23 communities in northern Westmoreland County and small portions of Armstrong and Indiana counties. Both CNX and the municipal authority have said there has been no impact to the reservoir and the situation is being closely monitored.
New Penna. Utica Well Being Plugged After Disturbing Other Wells – CNX Resources Corp. has spent the past week trying to get a Utica Shale well near the Beaver Run Reservoir in Westmoreland County under control after a problem there was followed by gas pressures spiking at nearby shallow wells. The Cecil-based oil and gas firm was fracking its Shaw 1G well in Washington Township on Jan. 26 when it detected a strong drop in pressure, the company told environmental regulators. It stopped fracking and found some type of obstruction in the well bore, said state Department of Environmental Protection spokeswoman Lauren Fraley. CNX also told the PA-DEP that four conventional – that is, shallower, vertical wells – nearby showed spikes in pressure, a sign of communication between the gas in the Utica well and the four other wells in the vicinity. Neighbors described a parade of trucks and hard-hatted workers dispatched to the Shaw pad and to properties with shallow wells, some of which are being flared to relieve the pressure. Residents were on guard about the activity – and what it might mean for conventional wells on their properties. A PA-DEP crew has been stationed at the site around the clock and will remain there until “we feel confident that the situation is under control,” Ms. Fraley said. A special well control team had been summoned from out of state to “kill” the well, a procedure that involves pumping heavy mud into the wellbore to stop the flow and keep it down. That had not yet happened by Saturday evening. Ms. Fraley said at this point, the agency is not aware of any pollution or impacts to environmental resources as a result of the situation. A statement from the Municipal Authority of Westmoreland County, which operates the Beaver Run Reservoir and supplies water to more than 120,000 customers, assured that water quality has not been compromised. The path of the well travels under the reservoir but it isn’t clear how far along that path the well had been fracked when the problem occurred.
Beaver Run Reservoir gas remediations successful – CNX Resources Corporation said Monday that efforts had been successful to remediate a gas well and arrest a subsurface flow of natural gas from the Utica shale well near Beaver Run Reservoir in Washington Township, Westmoreland County. “The remediation process was successful and the well has been contained,” the energy provider based in Canonsburg, Washington County, said in a news release. “There were no injuries and no impact to the environment.” The problem was determined to be “a pressure anomaly during hydraulic fracturing operations on the Shaw 1G well,” the CNX release said. “While we continue to evaluate the cause of the initial pressure anomaly, we believe it is isolated to this well.” Still, all hydraulic fracturing operations on the four-well Shaw pad remain suspended while CNX officials assess the incident. “As a precaution,” CNX officials said they will continue to monitor the well for the next several days, as well as “existing nearby gas wells,” managing any residual gas communication with those wells. That included any impact to drinking water supplies, as the 11-billion-gallon Beaver Run facility serves approximately 130,000 Municipal Authority of Westmoreland County customers in parts of Westmoreland, Armstrong and Indiana counties, including Saltsburg, Kiskiminetas Township and Loyalhanna Township.“During the fracking stage of the Utica well, CNX experienced a significant loss of pressure and communication with four other nearby conventional wells which were flared to relieve pressure,” Fraley said. “CNX reported to DEP (Monday) that it expanded flaring to a total of nine conventional wells in the vicinity of the Shaw 1G well.” Fraley said a contractor brought in by CNX was working to “kill” the well by “pumping a thick heavy mud into the well to stop any flow of gas.” She said this was accomplished in a six-hour period Monday night. .
Sunoco pipeline easements expiring in Chester County – – Sunoco’s temporary easements related to construction of the controversial Mariner East pipeline project are expiring at sites throughout Chester County, state Sen. Andy Dinniman said. In a lawsuit filed this afternoon in Chester County Common Pleas Court, attorneys for the Hankin Group, a Chester County-based residential, commercial and retail developer, asked a judge to force Sunoco off four of its properties where it is still constructing the pipeline. The four sites identified in the filing include one at Corner Park Apartments on Boot Road in West Whiteland, one at New Kent Apartments in East Goshen, and two on Stockton Drive and Sierra Drive at Eagleview in Upper Uwchlan. Residents have raised numerous concerns about pipeline construction at these locations, including environmental, air quality and quality-of-life impacts, given their close proximity to multi-family residential dwellings. The complaint contends that Sunoco is in breach of a temporary easement agreement that has elapsed on the Corner Park and New Kent Properties in November and on the Eagleview Properties in January. In turn, the four-count complaint calls for Sunoco to immediately cease all pipeline construction activities at the sites, remove all construction equipment, pipes, machinery and related materials there, and restore the affected areas to their prior condition. In addition, Hankin Group is suing Sunoco for trespassing, breach of agreement and damages. According to the lawsuit, Sunoco’ trespass and breach of easement agreements have caused “damage to the ground caused by excavation; damage from excessive runoff caused by removal of grass and foliage; harm to the value of properties; lost rents; loss of use; and diminution in value of properties.”
PUC seeks school evacuation drills on pipeline route – The Public Utility Commission has asked Sunoco to work with county emergency officials and some school districts to plan evacuation drills in case of a leak in the Mariner East pipelines, a senior PUC official said on Thursday. Paul Metro, Manager of Gas Safety at the PUC’s Bureau of Investigation and Enforcement, told a community meeting in Chester County that there was a “communication gap” between school districts and the emergency planners who are responsible for evacuation plans. Although the PUC isn’t responsible for evacuation plans, it facilitated talks with several state agencies, and agreed to ask Sunoco to set up the plans, Metro told the meeting. “Plans are being worked out for these drills,” he said. The school districts include West Chester, whose superintendent, Jim Scanlon, said he had been in talks about holding an evacuation drill but has no immediate plans to do so. “We have discussed that with our administrative team,” he said. “We will probably pick that back up in the summer.” The plans were discussed at the latest public meeting between state and federal pipeline safety officials and residents of Philadelphia’s western suburbs who continue to seek information that might help them feel safer about the multibillion-dollar pipeline project that is now carrying natural gas liquids through their communities. About 150 people gathered in a West Chester middle school auditorium on Thursday evening to hear 10 officials from the Public Utility Commission, the Department of Environmental Protection, and the federal Pipeline and Hazardous Materials Safety Administration defend their efforts to ensure the safety of the controversial pipelines. The officials said they were doing everything they can within their jurisdictions to ensure that the pipelines are built and operated safely, but they repeatedly emphasized the limits of their powers.
Delco moves to intervene in suit vs. Mariner East pipeline project – – Delaware County is jumping into the legal battle being waged over the controversial Mariner East pipeline project. Delaware County Council Wednesday voted 4-0 to intervene in a lawsuit against the owners of the Mariner East pipeline. Council authorized county solicitor Michael Maddren to draft a petition to intervene in the suit filed by seven residents of Delaware and Chester counties. County Council Chairman John McBlain abstained since the law firm where he works has done work for Sunoco although he himself has not. In November, several residents filed a complaint with the Pennsylvania Public Utility Commission against Sunoco/Energy Transfer Partners, citing the risk associated with the Mariner East pipeline. “It’s incumbent us to at least have a seat at the table in a proceeding that has clear impact on the safety of our residents,” county Councilman Kevin Madden said. “That’s what filing a motion to intervene would allow us to do.” When Delaware County Council intervenes, they will be joining the Rose Tree Media, Downingtown Area and Twin Valley school districts and East Goshen Township in doing so. The legal maneuver comes just days after a butane leak was reported at the Marcus Hook Industrial Complex Monday.. The 350-mile Mariner East 2 pipeline has been active since December and moves ethane, propane and butane from western Pennsylvania and Ohio to the Marcus Hook facility, where the natural gas liquids are stored for distribution to local, domestic and international customers. The Mariner East 1 pipeline was shut down last month after a sinkhole exposed the 8-inch portion of the line was exposed in a backyard in West Whiteland, Chester County. It’s the same neighborhood where sinkhole problems last winter caused the PUC to shut down Mariner East 1 and halt work on Mariner East 2. At the Jan. 23 Delaware County Council meeting, several residents asked council to consider intervening in the case.
Pipeline company, PUC no-shows at county meeting – Cumberland County Commissioners are scratching their heads, wondering why they had to cancel yet another public meeting with Energy Transfer Partners, the company that operates the Mariner East II pipeline with its subsidiary Sunoco. After the company canceled a July meeting to address concerns in Lower Frankford Township, commissioners asked the state’s Public Utility Commission to get involved. Energy Transfer Partners and PUC representatives were invited to a meeting Thursday, but the meeting was canceled after the other parties said they would not be in attendance. Commissioner Jim Hertzler says they don’t have an explanation why no one wanted to show. “The company just apparently refuses to meet with the public in various settings to discuss what it is they’re doing,” Hertzler said. Hertzler doesn’t personally have a problem with the pipeline but says it’s not right that the public can’t get their questions answered. Energy Transfer Partners did not reply to requests for comment.
Pa. suspends review of permit applications for pipeline company – – State environmental regulators on Friday suspended their review of permit applications and other approvals requested by Energy Transfer LP and its subsidiaries after the pipeline company failed to comply with agency orders following an explosion in Beaver County last fall. Texas-based Energy Transfer owns both the ruptured Revolution natural gas pipeline and the controversial cross-state Mariner East gas liquids pipelines in Pennsylvania. The Pennsylvania Department of Environmental Protection said the suspension will apply to all reviews of clean water permit applications for the company and will affect the in-service date for the Revolution pipeline, which has not started operating after the explosion. The action means that any new construction on company pipeline projects that require DEP approval are on hold for now. Energy Transfer can continue work at sites where it needs no new permits. The Mariner East 2 pipeline, operated by Energy Transfer subsidiary Sunoco Pipeline LP, is flowing partially through repurposed pipelines while construction of the full project’s twin pipelines is completed. It transfers ethane, propane, and butane across the state to a facility in Marcus Hook, Delaware County. DEP said it is currently reviewing 27 approvals for Mariner East 2, all of which are now on hold. DEP Secretary Patrick McDonnell said Energy Transfer, which operates the facility in Marcus Hook, failed to comply with the agency’s Oct. 29, 2018, order to stabilize the site of the Revolution pipeline explosion, which was caused by a landslide on the steep hillside in Center Township where the pipeline was buried. “In October, DEP cited for sediment-laden discharges into waterways, improperly maintained erosion controls, and failure to stabilize disturbed areas,” McDonnell said. “Disappointingly, many of these issues persist.”
EQT Reports A 3-Mile Lateral In Pennsylvania — February 7, 2019 – From Emergent Group today, look at this: EQT reported two completions on a multiple well pad in Washington county, Pennsylvania. Haywood Mon110H24 and Haywood Mon110H25 were completed on January 3 and tested January 7. The H24 produced 15,565 MMcf of gas on its 38 stage lateral with a vertical depth of 7,332 ft. The H25 was drilled to 7,304 ft with a 129 stage 18,450 ft lateral length. Both wells use frac material provided by FTSI International, perforations by GR Energy Services, and drill out services by Mountain State Pressure Services. The Cogar 592747, drilled on a separate pad in Washington, Pennsylvania, produced 15,341 MMcf of gas. Its 35 stage lateral was drilled to 5,935 ft with perforations from 8,471 ft to 13,299 ft. It has a vertical depth of 7,621 ft and a measured depth of 3,556 ft. Frac horsepower was provided by Keane and cementing by BJ Cement Services. Did you see that? A three-mile lateral? 129 stages and 18,450 feet lateral length. Actually, three miles is 15,840 feel, so this is well over three miles long.
Gas driller seeking to have man thrown in jail for contempt – A gas driller is escalating its campaign against Kemble, a Pennsylvania homeowner who’s long accused the company of polluting his water, demanding that he be thrown in jail over his failure to submit to questioning as part of the company’s $5 million lawsuit against him. (AP Photo/Michael Rubinkam, File)A gas driller is escalating its campaign against a Pennsylvania homeowner who’s long accused the company of polluting his water, demanding that he be thrown in jail over his failure to submit to questioning as part of the company’s $5 million lawsuit against him. Houston-based Cabot Oil & Gas Corp. sued Dimock resident Ray Kemble and his former lawyers in 2017, claiming they tried to extort the company through a frivolous federal lawsuit that recycled already-settled claims of environmental contamination. Cabot also claims Kemble violated a 2012 settlement agreement by repeatedly “spouting lies” about the company in public. In court papers filed this month, Cabot said Kemble had skipped two depositions in the case, and asked a judge to hold him in contempt and put him behind bars until he meets with the company’s lawyers. Kemble, who has said he has cancer, said he was unable to go the depositions because of his poor health. A hearing is scheduled for Monday. Kemble, who has traveled the country speaking about his experiences with the gas industry, didn’t return a phone call seeking comment. But an environmental group that has worked with him for years blasted Cabot’s aggressive posture. “To try to put a man like Ray Kemble in jail speaks volumes about the decency of this industry,” said Scott Edwards, an environmental lawyer at Food & Water Watch. “It’s an outrage.”
Decision Delayed in Cabot’s Suit against Man Fighting Natural Gas Drilling …— There will be no jail time–at least not yet–for a man being sued for being critical of a natural gas driller in Susquehanna County. It’s the latest chapter in the court battle between Cabot Oil & Gas and Ray Kemble. Kemble left the Susquehanna County Courthouse in Montrose using a walker on Monday. The man from Dimock is facing a lawsuit from the largest natural gas company in the county — Cabot Oil & Gas. “Well, I’ve fired my lawyer. I’m done with him, so he’s done. He’s gone. We’re going to get new counsel,” Kemble said. Related Story Attorneys Argue Cabot Lawsuit in Susquehanna County That buys Kemble more than a month before he’s agreed to a deposition with Cabot’s attorneys. The Texas-based company had asked the judge to jail Kemble because he missed two previous deposition dates. “We want to have him deposed, very simply. He’s quick to tell everybody else his plight. We want him to tell that plight through a deposition. You can’t avoid these things, can’t not show up,” said George Stark of Cabot Oil & Gas. This court battle between Cabot and Kemble has been going on for quite some time now. This decision by a judge in Susquehanna County means Ray Kemble has until late March to get another attorney and then have to answer questions for attorneys in this lawsuit. Kemble originally sued Cabot, claiming the company contaminated his and others’ drinking water in Dimock. Then the two parties settled. Now, Cabot is countersuing and claims Kemble is a paid activist and is in violation of the settlement agreement. “We’re talking about Ray Kemble? We’re talking about those folks, those type of actors. They’re getting paid, getting employed,” said Stark
Ban fracking waste anywhere in New Jersey: Romero – Gov, Phil Murphy’s call for a ban on fracking and the dumping of fracking waste in the Delaware River basin is a bold move to protect a clean drinking water source for millions. But if this toxic drilling waste is a danger to the Delaware, it’s a danger everywhere else. That’s why fracking waste should be banned across the Garden State. A waste ban bill passed the state Senate in November, but it remains stymied in the Assembly. It’s time for Speaker Craig Coughlin to bring this measure up for a vote. Her Millions of gallons of fluid mixture (water, sand and chemicals) are pumped underground per well. The chemical waste that flows up to the surface can combine with naturally occurring contaminants underground such as benzene, arsenic and lead. Oil and gas wells in Pennsylvania generate hundreds of millions of gallons of this leftover toxic slurry, and it has to go somewhere. And the petrochemical industry may have their sights set on New Jersey. This drilling waste creates an array of problems, from earthquakes linked to underground waste storage to the direct threat to waterways from waste spilled from trucks hauling it to treatment facilities. A recent study from Pennsylvania found evidence of chemical contamination in the shells of freshwater mussels even years after the industry had stopped dumping waste in nearby waterways. And the dangers that fracking waste pose to clean water and public health are likely more serious than we think. Fracking companies are allowed to keep the chemicals they pump into the ground a secret, which means that the toxic stew left over from drilling can wind up at conventional treatment facilities that are not equipped to treat radioactive material and other fracking-linked contaminants. This dirty business could be on its way to our state. A law passed last summer would make it easier for the Chemours/DuPont Chamber Works facility in Salem County to get permits to accept outside hazardous waste. This same facility received more than 1 million gallons of fracking wastewater between 2009 and 2010, discharging the treated water into the Delaware River. Other facilities that have accepted drilling waste in the past.
Bill to ban oil and gas drilling in New York’s coastal areas passes State Legislature — State lawmakers today passed legislation to prohibit oil and natural gas drilling in New York’s coastal areas. The measure would prohibit the use of state-owned underwater coastal lands for oil and natural gas drilling and would prevent the Department of Environmental Conservation and the Office of General Services from authorizing leases that would increase oil or natural gas production from federal waters. It would also prohibit the development of infrastructure associated with exploration, development or production of oil or natural gas from New York’s coastal waters. Assemblyman Steve Englebright (D-Setauket), who chairs the Assembly’s Environmental Conservation Committee, sponsored the bill in that chamber. “My colleagues and I held a hearing on Long Island last year and there was unanimous condemnation of the federal government’s proposal to open up our waters to drilling for oil and gas,” Englebright said. In 2017, President Donald Trump issued an “America-First Offshore Energy Strategy” as the first step toward opening previously protected parts of the Outer Continental Shelf to oil and gas exploration. Drilling off New York’s Atlantic Coast has been off limits for decades, and as a result some of the state’s laws regulating oil and natural gas drilling have not kept pace,
14,400+ call on Cuomo to Stop the Williams Fracked Gas Pipeline – – Today, dozens of members of the Stop the Williams Pipeline NY Coalition gathered in Albany for a press conference before delivering more than 14,400 petition signatures calling on Governor Andrew Cuomo walk the talk on climate action and stop the Williams fracked gas pipeline. “Stopping the Williams fracked gas pipeline is Governor Cuomo’s first major test of his commitment to a Green New Deal for New York,” said Laura Shindell of Food & Water Watch, an activist with the Stop Williams Pipeline NY Coalition. “That’s why we’re in Albany today, representing the thousands of people who’ve signed the petition to stop this pipeline.”This comes as reports reveal the Trump administration is considering taking action to limit states’ power to block dangerous fossil fuel projects, such as the Williams NESE fracked gas pipeline. The pipeline would be part of a Northeast Supply Enhancement (NESE) project attempting to transport fracked gas from Pennsylvania across New Jersey into New York City.“There’s no demand for this fracked gas. What we need is a just transition to 100% renewable energy. As Trump and fossil fuel cronies prop up big oil and gas interests ahead of public interest, real action on the climate crisis needs come from places like New York,” said Cata Romo of 350.org and the Stop the Williams Pipeline NY Coa lition. “After banning fracking, Cuomo needs to stop fracked gas projects like the Williams pipeline from wreaking havoc on our communities. There’s absolutely no room for fossil fuels in a Green New Deal.”
Federal court vacates NYSDEC’s pipeline certificate denial – A federal appeals court vacated the New York State Department of Environmental Conservation’s (NYSDEP) denial of a water-quality certificate to the proposed Northern Access natural gas pipeline project on Feb. 5. The US Court of Appeals for the Second Circuit remanded the matter back to the state agency with instructions to more clearly articulate its basis for denial. Sponsors National Fuel Gas Co. and Empire Pipeline Inc. applied for a NYSDEC certification under Section 401 of the federal Clean Water Act on Mar. 2, 2016. The agency denied the application on Apr. 7, 2017 after the US Federal Energy Regulatory Commission issued the project a certificate of public convenience and Pennsylvania’s Department of Environmental Protection issued it a state water quality certification. The sponsors sued in federal court to overturn the New York agency’s action. FERC later ruled that NYSDEC waived its authority to deny the permit because it did not act within a year of receiving the interstate natural gas pipeline sponsors’ application for it (OGJ Online, Aug. 7, 2017). “Today’s court decision continues the momentum for this project,” a National Fuel Gas spokeswoman said on Feb. 5. “As FERC stated in its Aug. 6 order, [NYSDEC] waived the ability to issue or deny a Clean Water Act Section 401 permit for the Northern Access project. The Second Circuit also has now made it clear that New York’s denial of the permit application failed to provide factual justification for their decision.”
National Grid presses state for new gas pipeline — National Grid may be forced to declare a moratorium on supplying natural gas to big new projects such as the Belmont Park redevelopment if the company’s plans for a $1 billion gas pipeline don’t receive a needed state permit by May 15, a top company official said. Growing demand, including record gas sales this month, and plans to supply gas for several big development projects necessitate the pipeline, which would provide up to 400 million cubic feet a day of new gas to the region, National Grid New York president John Bruckner said. The plan awaits a critical water quality permit from New York State. But Gov. Andrew M. Cuomo’s administration last year rejected the application and has hesitated to approve new fossil fuel infrastructure projects. National Grid is seeking state approval for a 24-mile gas pipeline, which includes about 18 miles under New York Bay and connects with existing infrastructure at sea beyond the Rockaways. Bruckner addressed his concerns about adequate supply for the region and the need for the project at a meeting with the Long Island Association on Friday morning. The LIA, a business lobbying group, supports the planned gas line, called the Northeast Supply Enhancement Project.
Columbia Gas Fined $75000 For 2016 Pipeline Pressure Spike Only After Recent Explosions – Two years before homes exploded in the Merrimack Valley, the pressure in Columbia Gas pipes rose dangerously high – a violation of federal safety regulations that only recently led to a $75,000 fine and orders from state regulators for the utility to clean up its act. The Department of Public Utilities issued five violations linked to the incident and levied the previously unreported fine on Columbia Gas two months after the September explosions that killed one person, injured dozens of others and left hundreds without gas in their homes for months. The incident that led to the DPU’s reprimand happened in February 2016 in Taunton. The pressure in Columbia Gas’ pipes hit alarming levels for almost a half hour, records show, violating federal pipeline safety regulations for failing to protect against accidental overpressurization or properly maintain its equipment. Gas companies are required to tell DPU when pressure in the pipes gets too high. WBUR discovered through public records Columbia Gas has a history of problems with overpressurization. The utility reported five separate incidents over a six-year period – from 2011 to 2016 – when pipeline pressure climbed beyond what’s considered safe. Any pressure that reaches over 10 percent of what the pipe is designed to handle is a violation of federal regulations. And years earlier, in 1999, Columbia Gas faced reprimands from DPU over pipeline safety standards. Pipeline experts say allowing the pressure to get that high even once is a cause for concern. Richard Kuprewicz was in the pipeline business for 40 years and now works as a consultant. He testified at the congressional hearing in Lawrence on the disaster. He’s stunned by Columbia Gas’ track record. “Well you can quote me on this but, are you crazy? You just don’t do that,” he said. “That would suggest a systemic issue within the company. … Exceeding 10 percent where it is required – even by a few percent – says a lot about the approach to prevent overpressure within a company culture.” During Columbia Gas’ most significant incident – the one that was the source of the fine – the pressure surged for 27 minutes after an equipment failure. Documents provided by Columbia Gas show the pressure reached more than 15 percent above what it was designed to handle. DPU didn’t explain why there was a two-year lag between the 27-minute spike in pressure and the fine over the incident.
Protesters block access where Vermont Gas line would go – Bearing banners and singing songs, several dozen protesters blocked an expected appraisal Thursday at Monkton resident Claire Broughton’s property, where Vermont Gas Systems is seeking to lay a natural gas pipeline over her objections. The protesters waited in a cold wind for about an hour before hearing via Broughton’s lawyer that state officials had called off the visit. He said officials deemed the situation too “menacing.” Protesters say they plan to ramp up activities as the pipeline moves forward, now that a recent Public Service Board ruling in its favor has cleared the way. Vermont Gas has built 11 miles of the 41-mile project already, traversing the distance from Colchester to Williston. When complete it will extend to Middlebury. The company says it has reached voluntary agreements with nearly everyone else whose property is in the path of the pipeline. An eminent domain hearing by the Public Service Board involving Broughton’s property was to be held in late December but was rescheduled after protesters became disruptive. Broughton’s attorney, Jim Dumont, said she welcomes the appraisal but opposes the eminent domain proceeding. “The protests going on outside are on a public road, and as far as Claire is concerned, these folks have a First Amendment right to their opinions, and that’s what they’re doing,” Dumont said Thursday. The protesters indicated they were focused on both Broughton’s situation and the wider threat from burning natural gas. “We believe climate warming is real, it’s human-caused, and it’s really a danger for the future of the world and the people on it, so saving the world is what it’s about,” The protests will continue, organizers say. “People are really mad, and it’s really easy to empathize with Claire in there,” said Alex Prolman, of Rising Tide Vermont, one of the groups involved in the protest. “There are opportunities to keep helping our neighbors and our friends during this process, and it’s not a difficult ask for a lot of people. They heard there was an eminent domain procedure happening, and they said, ‘When? Where? I’ll be there.’”
Senate panel gets look at bill that would ban new oil and gas pipelines – If Democratic and Progressive lawmakers have their way, Vermont could become the first state to ban new oil and natural gas pipelines.Sen. Alison Clarkson, D-Windsor, gave the Senate Natural Resources and Energy Committee Tuesday a run-through of S.66, a bill that would prohibit new fossil fuel infrastructure. “We feel fairly strongly that investing further in the infrastructure at this point in time … would be imprudent given that we hope, as Vermonters addressing climate change – one of the greatest challenges of our time – that we will move to more energy efficient and renewable sources,” she said to the five senators on the committee.The prohibition would not apply to gas stations, fuel trucks or repairs to existing pipelines, said Clarkson.The proposal comes as part of a spate of proposals from environmental advocates to address the state’s rising greenhouse gas emissions. Heating contributes just shy of 28 percent of total emissions, with heating oil and propane accounting for 75 percent of those emissions, natural gas contributing 22 percent and wood heat contributing 3 percent. Portland, Oregon, and King County, Washington have recently enacted similar bans.The bill does not single out natural gas pipelines, but Julie Macuga of 350Vermont – a climate change advocacy group that has been pushing for this ban – said she was not aware of any other major fossil fuel infrastructure being planned in Vermont. Environmentalists and Vermont Gas, the state’s lone natural gas utility, have squared off in recent years over the company’s plans to build a 41-mile pipeline from Colchester to Middlebury. Although the Addison County pipeline was completed in 2017, the project has been mired in an ongoing state investigation into its construction methods. Nearby residents and the state’s Department of Public Service asked Vermont’s utility regulator to look into concerns including pipeline depth and whether a professional engineer had signed off on the construction plans.
Appalachia’s approaching energy boom – – Economic “game changer” is not a phrase often used in Appalachia and rarely a phrase proclaimed in unison by politicians from both parties at the same time on any subject. Yet since 2016, when Shell Chemical announced it was building a $6 billion ethane cracker plant here, an economic revolution began that is far from reaching its potential. The cracker plant in Beaver County is all about a molecular “cracking,” in which extreme heat “cracks” ethane molecules to form new ones that will eventually produce more than a million metric tons of polyethylene, a type of plastic used in all kinds of common household products. The gas found here in the Appalachian region of Western Pennsylvania, Eastern Ohio, and West Virginia is low cost and “wet,” meaning it carries highly valued natural gas liquids, or NGLs. When separated and refined, it can become different fuels, such as fertilizer or propane. The project has already created 1,000 new jobs and is expected to top out at 6,000 during the construction and preparation phases over the next decade before the plant is fully operational. The plant itself is expected to employ more than 600 people permanently, a mix of labor, engineers, and chemists, with Shell analysts predicting it will provide work for two to three times that number in its supply chain. In his annual report to Congress late last year, Department of Energy Secretary Rick Perry recommended that a new ethane storage and distribution hub be built somewhere near this plant, something that could potentially renew prosperity in the tri-state region of Pennsylvania, Ohio, and West Virginia. The DOE’s recommendation was a response to a congressional inquiry about the feasibility of establishing an additional large ethane storage and distribution hub for NGLs somewhere in the United States. The Appalachian ethane hub would be similar to others run by private industries in Kansas, the Gulf Coast, and the Permian Basin. Perry argues that creating one in the middle of the country, surrounded by the region’s rich natural resources, would increase America’s global market share and solve long-term national security concerns about the impact of a major natural disaster by placing production at different locations around the country.
Petrochemical pros, cons: ‘Invasion’ forum counters pluses of industry in region – The 42-mile drive from Washington to Potter Township represents the proverbial scenic route as it winds through rural and wooded areas north into Beaver County. Eventually, the relative tranquility gives way to the panorama of a massive construction project: the Shell Chemical Appalachia Petrochemical Complex, taking shape on a 340-tract along the Ohio River and representing a $6 billion investment by one of giants of the oil and gas industry, Royal Dutch Shell. The purpose of the plant is to break up molecules of ethane – a byproduct of hydraulic fracturing, or fracking – into smaller molecules as a step in the creation of plastics. By industry parlance, the process involves molecules being “cracked,” hence the common reference to cracker plants. Those in favor cite job creation as a major plus: some 6,000 workers during construction and 600 full-time employees when the plant goes into operation in the early 2020s. Further employment opportunities could arise with the development of a regional pipeline system connecting natural gas suppliers with the Shell complex and other similar plants, if built. And according to Marcellus Drilling News, Asian companies PTT Global Chemical and Daelim Industrial Co. have been exploring the possibility of building a cracker plant in Belmont County, Ohio, also along the Ohio River. “Natural gas is the biggest game changer, and everybody in the tri-state should collaborate on this,” Robbie Matesic, executive director of the Greene County Department of Economic Development, said, “We need to be as responsive as we can, as collaborative as we can, as fast as we can and as fearless as we can,” she said. “This is a global market we’re in now.” Then there’s the flipside. “The Petrochemical Invasion of Western PA: Its Environmental Consequences and What Can Be Done About It” served as the theme for a recent forum at Unitarian Universalist Church of the South Hills in Mt. Lebanon, with a variety of panelists expressing reasons to oppose the prevalence of fossil-fuel-related industries in the region. “We still have a serious air-quality problem in Southwestern Pennsylvania, and adding to our airshed burden will only make things worse,” he told the forum’s audience. “We consistently get failing grades from the American Lung Association: three F’s several years in a row, the only place outside of California with that distinction.”
Mary Wildfire: One problem with petro storage hub everyone is missing — Area newspapers are full of editorials and op-eds lauding the proposed petrochemical storage hub as the salvation of the Ohio Valley. Others discuss the downside: the risks of air and water pollution, the degradation of a quiet, rural landscape into an industrial zone, and the increase in drilling and fracking it would spur, with all the associated harms in the nearby gasfields of the Marcellus and Utica shales. Health threats are also mentioned, as is climate change. But I see another risk nobody seems to be talking about. If proponents have their way, scores of billions of dollars will be sunk into this complex of storage caverns, crackers and plastic plants, plus the pipelines to connect all the components. What if the complex doesn’t operate long? We will be left with an enormous, ugly mess lining the Ohio River, and likely no money and other resources left either to clean it up or to build something more practical. I see two possible reasons why this might happen. One is the possibility that the resource is not nearly as extensive as claimed. David Hughes, a Canadian geologist, produced a report a few years ago called “Drilling Deeper” in which he examined the data, well by well, for shale oil and gas in the U.S. He found that estimations by the U.S. Energy Information Administration are highly optimistic in essentially all cases; the word he used for the Marcellus was “extremely” optimistic. The report notes that drillers here, in an effort to become profitable, are concentrating on “sweet spots” – when those are exhausted, they will have to turn to less promising sections. Aren’t they profitable now? Not according to a series by DeSmog Blog, which suggests that most of the gas companies are struggling to pay creditors. The other threat to the long-term viability of the petro complex is that it will ultimately be blocked or shut down by environmental concerns – either local ones such as those mentioned above, or the global ones of climate change and plastic pollution. Key to the complex, after all, is the production of plastic. Meanwhile, renewable energy and batteries keep getting cheaper. So between the possibility of economics causing a decline of the natural gas liquids source, and people being unwilling to accept the “externalities,” an enormously expensive petrochemical complex could become a stranded asset.
Columbia Gas’ Mountaineer XPress seeking to start up more facilities in West Virginia – TransCanada’s Columbia Gas Transmission asked US regulators on Thursday for approval to begin service on additional segments of its Mountaineer XPress pipeline that will allow the operator to provide another approximately 250 MMcf/d of firm capacity. The 2.7 Bcf/d natural gas pipeline in West Virginia is part of a wave of new infrastructure designed to boost the flow of shale supplies from the Appalachian Basin in the US Northeast to downstream markets. The latest request to the Federal Energy Regulatory Commission covers more than 20 miles of 36-inch pipeline in Marshall and Wetzel counties and related equipment. It follows previous approvals in October, November and January for other portions of the project, which encompasses about 165 miles of greenfield pipe in West Virginia along with three compressor stations, upgrades to three existing compressor stations and construction of smaller pipeline segment. “Columbia anticipates mechanical completion of the facilities that are the subject of this request as early as February 11,” the operator’s in-service request states. If approved, Columbia Gas will be able to provide additional firm contracted service to THQ Marketing as an anchor shipper on Mountaineer XPress, the request states. Columbia Gas is seeking approval by February 12. The project is designed to transport growing production from the Marcellus and Utica shale plays to Columbia’s TCO Pool and farther south to pooling points on Columbia Gulf Transmission. Along with Columbia Gulf’s 860 MMcf/d Gulf XPress project, the expansion is projected to provide incremental capacity between the US Northeast and the Gulf Coast. The company previously hoped to have the Mountaineer XPress in full service in late 2018. But it has faced some challenges, in part due to trouble with erosion controls and land slips that added to the need for restoration. On its Columbia Gas system, TransCanada started up in the fall its 1.3 Bcf/d WB XPress pipeline, which is aimed at expanding WB mainline capacity and, among other things, will help feed Appalachian Basin production to Dominion Energy ‘s Cove Point LNG export terminal in Maryland.
Oil and Gas Abandoned Well Plugging Fund –This week we saw some bills related to conventional oil wells, HB 2673 – Creating the Oil and Gas Abandoned Well Plugging Fund. The bill will cut the oil severance tax on applicable wells (producing less than 60,000 cu. Ft. per day) from 5% to 0% but introduce a rate of 2.5% that goes to the newly created Oil and Gas Abandoned Well Plugging Fund. The bill passed House Energy and is on its way to House Finance. While this bill does add to moneys to plug current wells, it does not address the growing issue of more abandoned and orphaned wells. Dave McMahon of West Virginia Surface Owners Rights Organization (SORO) is working on legislation to address the 4500 current orphaned wells, and the predicted 10,000 additional orphaned wells over the next few decades. Proposed legislation will require “plugging assurance” in the form of a bond or escrow for each well rather than a blanketed performance bond. We want this assurance on new wells, wells transferred between drillers, and wells that are no longer producing in paying quantities. We expect the industry to agree to some bills that will provide money to plug a few of the orphaned wells!
Appeals court allows quick-take of land for Mountain Valley Pipeline – An appeals court has upheld the “take first, pay later” approach to building the Mountain Valley Pipeline, in which the company condemned private property in the project’s path before paying opposing landowners for their losses. The ruling Tuesday by the 4th U.S. Circuit Court of Appeals was a blow to pipeline foes, who have long decried the use of eminent domain to take parts of family farms and rural homeplaces to make way for a 303-mile natural gas pipeline. In their appeal, the landowners did not contest the laws that allowed Mountain Valley to obtain forced easements through nearly 300 parcels in Southwest Virginia. But they challenged a ruling by U.S. District Court Judge Elizabeth Dillon, who granted Mountain Valley immediate possession of the disputed land before deciding how much each property owner should be compensated. Dillon’s decision was instrumental in allowing the company to move forward with tree-cutting in February 2018. At the time, Mountain Valley officials testified that they needed to start timbering as soon as possible to keep the project on schedule and to meet a March 31 deadline for the felling of trees before they became the warm-weather habitats of protected species of bats. The company would have suffered serious financial harm if it was forced to wait to begin tree-cutting until mid-November, after the bats had gone back into hibernation, Dillon ruled in allowing Mountain Valley to take first and pay later. Two other federal judges, who preside over districts in West Virginia through which the pipeline will pass, made similar calls. All three of the decisions were consolidated into one case, with a three-judge panel ruling unanimously in Mountain Valley’s favor.
Fire at pipeline construction site under arson investigation (AP) – Authorities say heavy equipment has been set on fire at a Mountain Valley Pipeline construction site in Virginia. News outlets cite a statement from the Pittsylvania County Sheriff’s Office as saying that a caller reported a vehicle on fire Saturday night in the Smith Mountain community. No one was injured. The statement says officers at the scene discovered the vehicle was a piece of earth-moving equipment located on the site of the pipeline construction right of way. There was about $500,000 in damage to the Caterpillar PL87 pipe layer. No other equipment was damaged by the fire. The sheriff’s office says fire marshals have concluded that the blaze was intentionally set and are investigating it as arson. The 300-mile (480-kilometer) natural gas pipeline is also being built in West Virginia.
Dominion delays U.S. Atlantic Coast natgas pipe, boosts costs (Reuters) – Dominion Energy Inc said on Friday the estimated cost of its Atlantic Coast natural gas pipeline from West Virginia to North Carolina has risen to $7.0 billion-$7.5 billion, adding that it has delayed the expected completion date to early 2021. The company said previously the project would cost an estimated $6.5 billion-$7.0 billion, excluding financing, and be completed in mid 2020 due to delays caused by numerous environmental lawsuits. “We remain highly confident in the successful and timely resolution of all outstanding permit issues as well as the ultimate completion of the entire project,” Dominion Chief Executive Thomas Farrell said in the company’s fourth-quarter earnings release. He noted the company was “actively pursuing multiple paths to resolve all outstanding permit issues including judicial, legislative and administrative avenues.” Earlier this week, the U.S. Fourth Circuit Court of Appeals stayed a previous court decision against U.S. Forest Service permits that allowed Dominion to build the Atlantic Coast pipeline across national forests and the Appalachian Trail. Dominion said it expects construction could recommence on the full 600-mile (966-kilometer) pipeline route during the third quarter of 2019, with partial in-service in late 2020. When the company started work on Atlantic Coast in the spring of 2018, Dominion said it expected the project would cost an estimated $6.0 billion-$6.5 billion and be completed in late 2019.
Bill to restrict Dominion pipeline costs – Legislation that could pose a serious threat to the bottom line of Dominion Energy’s planned Atlantic Coast Pipeline continues to advance in the Virginia General Assembly. The bill passed a key House committee Thursday with bipartisan support despite heavy lobbying by Dominion. The legislation would add new restrictions on Dominion’s ability to pass along costs of transporting gas from the ACP to its Virginia-based power stations. That could reduce the potential revenues of a project whose costs have already ballooned in the face of fierce opposition from environmentalists and land owners. Dominion said the legislation is unneeded and regulators can already protect customers from unreasonable costs. The energy company is among the most powerful forces at the General Assembly and rarely sees legislation it dislikes become law.
Union Hill residents see link between racist Northam photo, pipeline decisions — Democratic Gov. Ralph Northam’s racist yearbook photo speaks to a broader trend of racism and environmental injustice, members of the Union Hill community in Buckingham County said at a press conference Saturday. Held at the offices of Appalachian Voices in downtown Charlottesville, the press conference featured four members of the Union Hill community who sat quietly around a wooden table, reflecting on their efforts to combat environmental racism and Northam’s connection to it. Union Hill, a historically black neighborhood born out of the freedmen period, is the proposed site of Dominion Energy’s natural-gas compressor station, which would serve the proposed Atlantic Coast Pipeline. For four years, residents of Union Hill have been drawing attention to environmental racism and the dangers a compressor station could cause for the community. “We still have to remember that this is a Southern state and there are Southern values that are very deep-rooted,” said Paul Wilson, pastor of Union Grove Missionary Baptist Church and leader of the movement to stop the compressor station. Northam’s medical school yearbook spread, which features a photo of a man in blackface and another dressed in a Ku Klux Klan robe, is certainly shocking, said Wilson, but not to those who have been following Northam’s record. “When these things flare up, it’s hard to just move away from it because you have to look at the individual’s record,” Wilson said. “It really makes you wonder when you look over his record and his life how much of that kind of thinking was reflected in the decisions that he made.” Though he said he would not be the first to cast a stone, Wilson said it may be best for the commonwealth if Northam resigned. .
Public use and private profit: US landowners question forced purchases (Reuters – The Jones farm in Giles County, Virginia, has been in the family for 250 years. But a natural gas pipeline could soon cut a corridor through the property, despite the family’s attempts to thwart it. A pipeline company was able to take a strip of the Jones’ land with government deployment of a legal tool known as eminent domain, a constitutional mechanism reserved for use in the public good. The tool received public attention last month when President Donald Trump threatened to use “the military version of eminent domain” to build a wall along the U.S. border with Mexico. Meanwhile, the use of eminent domain for private projects that are said to fulfill some public good remains relatively new, but legal experts say it has resulted in a spate of legal battles such as the Joneses’. “Dad does not want to sell his family land at any price for any reason,” Donald Wayne Jones, the son of property owner George Lee Jones, told the Thomson Reuters Foundation. “He understands that eminent domain can sometimes be used to provide for the common good of the public.” “But he doesn’t understand how a profit-seeking, out-of-state company can be handed this privilege of taking privately owned land from U.S. citizens – an action he feels will only obtain profit for a private company and its shareholders.” The U.S. Constitution allows governments at all levels to take private property for “public use”, and eminent domain was a key mechanism to build, for instance, the railroad networks that crisscross the country. A 2005 Supreme Court decision, however, opened up a more complex legal area: the government’s ability to take private land and give it to another private entity, such as a corporation.
Bernstein analysts say Mountain Valley, Atlantic Coast pipeline projects may not get finished – Even with 10 Bcf/d of new pipeline capacity added in the past 15 months, Appalachia’s pipeline buildout may be finished, putting the completion of late comers such as the EQM Midstream Partners LP-led Mountain Valley Pipeline LLC project and the Dominion Energy Inc.-led Atlantic Coast Pipeline LLC project in doubt, analysts at the investment management company Sanford C. Bernstein & Co. LLC told clients Jan. 24.“We had anticipated that building through [North Carolina and Virginia] would be difficult,” Bernstein’s midstream analyst Jean Ann Salisbury said in a research note. “The perfect combo of no major recent new pipelines and no state upstream benefit usually leads to problems – just ask [Williams Cos. Inc.’s Constitution Pipeline Co. LLC].” The costs of the 2-Bcf/d Mountain Valley pipeline and the 1.5-Bcf/d Atlantic Coast pipeline have grown to $4.6 billion and $7 billion, respectively, Bernstein said. These increases may force the operators to charge too high a tariff and make them uncompetitive, according to the firm. “This translates to $1.30-$2.60/MMBtu, almost certainly more than the cost differential to source from another basin,” Bernstein said. “To us this suggests that we are nearing the end of the buildout period, and even that possibly only one of these projects will ultimately get done.” Bernstein said that while producers in the dry gas portion of the Marcellus and Utica shales in northeast Pennsylvania will begin to bump up against a cap on takeaway capacity sometime this year, producers in the southwest portions of Appalachia have lots of running room. With capacity currently available out of both Appalachian regions, producers can look forward to better price realizations, Bernstein said, which is good for companies such as Cabot Oil & Gas Corp., Range Resources Corp. and Southwestern Energy Co. However, Bernstein said, there is a danger that the more Marcellus gas is on the national market, the further national prices will fall.
Atlantic Coast Pipeline delayed amid $2 billion – $3 billion price increase – The completion of the Atlantic Coast Pipeline has been delayed amid a projected cost increase to more than $7 billion, about $2 billion to $3 billion more than initial projections. In a separate development, two research organizations released a report questioning the viability of the project. The report released Jan. 29 by the Institute for Energy Economics and Financial Analysis and Oil Change International said lower consumer demand for natural gas and the availability of affordable renewable options were casting doubt on the overall feasibility and potential profitability of the pipeline.The pipeline project has been delayed until late next year with the pipeline not expected to be in full service until 2021, according to a statement released Friday by the company working on the pipeline. Atlantic Coast Pipeline LLC, which was formed by Dominion Energy, Duke Energy and Southern Company Gas, is building the pipeline.The 600-mile pipeline is expected to run from West Virginia, through Virginia and into North Carolina, where it would end near Pembroke. The proposed route of the 36-inch pipeline runs through the northwest corner of Sampson County and near Godwin, Wade, Eastover, Cedar Creek and Gray’s Creek in Cumberland County, and St. Pauls in Robeson County.
Exaggerated Claims for ACP Pipeline Called Into Question – Rebecca McPhail of the West Virginia Manufacturers Association, (DP-Jan.17) makes so many false and deceptive claims about the Atlantic Coast Pipeline (ACP), manufacturing in West Virginia and environmentalists, it is hard to know what to correct first.She claims West Virginia “is sitting on a gold mine of energy and economic prosperity,” but environmental activists threaten this prosperity by blocking “construction of the ACP.” She goes on to claim these activists threaten manufacturing jobs in West Virginia and that 4,500 construction jobs will be lost, if the pipeline is not completed.First, the ACP was not designed to support manufacturers in West Virginia; it was designed to move Marcellus shale gas out of West Virginia to supply already saturated markets on the Atlantic seaboard and for export. In fact, the Obama administration granted Dominion Energy, one of ACP’s stakeholders, the right to export natural gas to markets such as Japan and India in 2013.Second, McPhail’s claims about construction jobs are clearly inflated and misleading. ACP provided these numbers, and they are based on a cumulative jobs methodology that counts construction jobs as the average yearly workforce multiplied by the number of project years, in this case six, to complete the work. So, the real number is closer to 750 jobs. Many of these jobs would go to outof-state workers, and in fact the major pipeline construction companies hired by ACP are from Texas, Wisconsin and Oregon. Third, there is a broad coalition of concerned West Virginians opposed to the pipeline for legitimate reasons. Many landowners in the path of the pipeline contest ACP’s use of eminent domain for private gain, as it takes land from its rightful owners for so-called “public infrastructure.” It is clear that the ACP and its supporters make false and deceptive claims to distract from the true cost of pipeline development. Let’s do an honest and impartial assessment of those costs.
Prices Fall Despite Bitter Cold As Temperatures Are Forecasted To Rise – Highlights of the Natural Gas Summary and Outlook for the week ending February 1, 2019 follow. The full report is available at the link below.
- Price Action: The now prompt March contract fell 33.8 cents (11.0%) to $2.734 on a 19.39 cent range ($2.923/$2.730).
- Price Outlook: Although temperatures were bitter cold across portions of the country, temperatures in the south were not extreme and the bitter cold abated at the end of the week with temperatures projected to rise well above normal next week. While winter is not over yet, there is little possibility of any real storage issue and price increases will likely be muted for the remainder of the winter. CFTC data indicated a (28,399) contract reduction in the managed money net long position as longs liquidated and shorts added. Total open interest fell (11,501) to 3.681 million as of December 25. Aggregated CME futures open interest rose to 1.365 million as of February 01. The current weather forecast is now warmer than 4 of the last 10 years. Pipeline data indicates total flows to Cheniere’s Sabine Pass export facility were at 3.2 bcf. Cove Point is net exporting 0.8 bcf. Corpus Christi is exporting 0.050 bcf. Cameron is exporting 0.000 bcf.
- Weekly Storage: US working gas storage for the week ending January 25 indicated a withdrawal of (173) bcf. Working gas inventories fell to 2,197 bcf. Current inventories rise 0 bcf (0.0%) above last year and fall (347) bcf (-13.6%) below the 5-year average.
- Supply Trends: Total supply fell (0.2)bcf/d to 83.6 bcf/d. US production fell. Canadian imports fell. LNG imports rose. LNG exports fell. Mexican exports rose. The US Baker Hughes rig count fell (14). Oil activity decreased (15). Natural gas activity increased +1. The total US rig count now stands at 1,045 .The Canadian rig count rose +11 to 243. Thus, the total North American rig count fell (3) to 1,288 and now exceeds last year by +0. The higher efficiency US horizontal rig count fell (7) to 925 and rises +117 above last year.
- Demand Trends: Total demand rose +4.5 bcf/d to +110.9 bcf/d. Power demand rose. Industrial demand rose. Res/Comm demand rose. Electricity demand rose +4,062 gigawatt-hrs to 83,273 which exceeds last year by +7,339 (9.7%) and exceeds the 5-year average by 4,977 (6.4%%).
- Nuclear Generation: Nuclear generation rose 138 MW in the reference week to 94,854 MW. This is (1,250) MW lower than last year and +752 MW higher than the 5-year average. Recent output was at 93,615 MW.
The heating season has begun. With a forecast through February 15 the 2018/19 total cooling index is at (2,135) compared to (1,909) for 2017/18, (1,739) for 2016/17, (1,761) for 2015/16, (2,053) for 2014/15, (2,332) for 2013/14, (1,990) for 2012/13 and (1,968) for 2011/12.
Natural Gas Still Can’t Find A Floor -The March natural gas contract continued its march lower today, settling down almost 3% as weather forecasts warmed and cash prices were even weaker today. It was the fourth straight trading session where the March natural gas contract settled lower and the fifth in the last six sessions. Weak cash prices definitely played a role in this move lower. Lingering concerns following a very loose EIA print last week did too. As we noted in our Morning Update, forecasts warmed decently from Friday afternoon, with much of the warming actually coming overnight last night after only a very small gap down last evening. Climate Prediction Center forecasts this afternoon again showed cold risks struggling to roll forward, with key regions in the South and Southeast likely staying warmer through Week 2. This selling comes as traders shake off what should be a very large storage withdrawal to be announced by the EIA on Thursday. Severe cold swept through the Midwest pulling GWDDs significantly above average for the week. We broke down our expectations for the draw in our Natural Gas Weekly Update today, which outlines all fundamental aspects of the natural gas market. In it we also looked at the current state of each individual storage region relative to the 5-year average.
Weather Models Keep Gas Bouncing Around – The March natural gas contract had a range of almost 7 cents today yet settled only two ticks higher as prices rallied then sold off on disagreeing weather models. The March contract was actually the weakest on the day, as later contracts exhibited more strength and warmer early afternoon weather models took their toll at the front of the futures strip the most. The result was a move lower in the J/V April/October spread even as prices rose. Prices initially rallied this morning in line with our expectations, as we warned clients in our Morning Update that modest overnight GWDD additions would allow prices to bounce. However, we also warned that weak cash prices could drag down the March contract after any initial bounce, which played out well. Then after a second bounce the GEFS weather model guidance trended warmer in the long-range, hitting the March contract hardest (image courtesy of Tropical Tidbits). For clients today we released our weekly Seasonal Trader Report, running through our latest gas expectations through the next few months and providing an updated seasonal forecast. In it we ran through our latest end of draw season storage number as well as other market expectations and what weather-independent modeling showed as well.
Analysts expect largest draw of US natural gas from storage of season – The EIA is expected to report on Thursday the largest natural gas draw from inventories of the season so far, but prices remained subdued across most of the US except for areas in the Pacific storage region where prices spiked on demand. The EIA is expected to report a 249 Bcf withdrawal for the week ended February 1, according to a survey of analysts by S&P Global Platts. Responses to the survey ranged for a draw of 238 Bcf to 260 Bcf.A 249 Bcf draw would be the largest draw of the season and much more than the 116 Bcf withdrawal in the corresponding week last year and the five-year average pull of 150 Bcf. A withdrawal within expectations of 249 Bcf would decrease stocks to 1.948 Tcf. The deficit against the five-year average would expand to 427 Bcf and the deficit against last year would expand to 147 Bcf.The draw looks to be stronger than the 173 Bcf draw reported last week. It shrunk inventories to 2.197 Tcf, which was 0.6% below the year-ago inventory of 2.211 Tcf, and 13% less than the five-year average of 2.525 Tcf.The mild start to the year closed some of the historic deficit to the five-year average, but frigid weather in the Midwest has pushed recent withdrawals well above normal. Incremental gains in Texas and Southeast production were a drop in the bucket compared to the jump in heating demand for the week, according to S&P Global Platts Analytics.However, NYMEX Henry Hub March futures remained low at $2.66/MMBtu Wednesday as demand has dropped precipitously for the week in progress. An early forecast for the week ending February 8 calls for a draw of only 70 Bcf, which would be 90 Bcf below the five-year average draw. While inventory in the East, Midwest and South Central regions have edged closer to the five-year average over the past month, EIA data shows the Pacific region standing more than 26% below the five-year average. Higher demand combined with curtailments have strengthened prices in the region.
US natural gas in storage falls by 237 Bcf to 1.96 Tcf: EIA – US natural gas in storage fell by 237 Bcf last week, the largest draw of the season and in history for the corresponding week, but Henry Hub futures hit year-low prices following the release as it was still below market expectations. Only a double-digit draw is forecast for the week in progress. US natural gas in storage decreased 237 Bcf to 1.96 Tcf for the week ended February 1, the US Energy Information Administration reported Thursday. The withdrawal was below an S&P Global Platts’ survey of analysts calling for a 249 Bcf pull. Similar to last week, the draw was outside the range of survey responses. The lowest response expected a 238 Bcf withdrawal. The withdrawal was still much more than the 116 Bcf pull reported during the corresponding week in 2018 as well as the five-year average draw of 150 Bcf, according to EIA data. As a result, stocks were 135 Bcf, or 6.4%, below the year-ago level of 2.095 Tcf and 415 Bcf, or 17.5%, below the five-year average of 2.375 Tcf. The NYMEX Henry Hub March contract slid 7.7 cents to $2.585/MMBtu following the 10:30 am EST announcement. Demand losses in LNG feedgas and dramatically reduced heating loads weighed on both cash and futures prices this week, according to S&P Global Platts Analytics. Since last week’s report, the March futures contract price has ground lower, with narrow daily trading ranges and consecutive lower settlements. On Wednesday, the March gas futures settlement was 19 cents lower than the February 27 settlement. The Henry Hub cash price, averaging $2.56/MMBtu, has fallen to levels not seen since February last year. While growing LNG exports at the end of the year may lend some support back to Henry Hub prices, the surge of availability and potential start-up of Nordstream II are likely to put EU Gas Prices and LNG prices under further pressure in the second half of the year, according to Platts Analytics. Frigid temperatures in the US upper Midwest have been unable to push Henry Hub back above $3/MMBtu after steady production growth and mild weather helped stocks build over the last month. This was the largest draw of the current heating season and was the largest pull ever reported for the corresponding week. During the polar vortex of 2014, 231 Bcf was drawn during the same week. But a Platts Analytics forecast only expects a draw of 72 Bcf for the week that will end February 8, 88 Bcf below than the five-year average.
EIA’s Reported 237 Bcf Draw Delivers TKO to Natural Gas; Widow-Maker Flips Negative – The Energy Information Administration (EIA) reported a 237 Bcf withdrawal from storage inventories for the week ending Feb. 1. The reported build fell about 10 Bcf shy of market expectations for a week that featured the coldest temperatures of the winter in key demand regions. Nymex natural gas futures prices, which were already about a nickel lower ahead of the report, fell another penny or so as the print hit the screen. By 11 a.m. ET, the March contract was trading 7.7 cents lower at $2.585, and April was trading 6 cents lower at $2.597. The flip in the March/April spread reflects no concerns about a supply crunch, and the smaller-than-expected withdrawal fueled that sentiment. “This came in bearish to market expectations and reflects a market that did not really tighten at all last week, despite severe cold across the Midwest. Modeling indicated bearish risks with the number today, though after a very surprising bearish miss last week, we were looking for an implicit revision,” Bespoke Weather Services chief meteorologist Jacob Meisel said. Instead, the gas market remains quite loose and will struggle to bounce without clear evidence of tightening in daily supply/demand balances and more bullish weather. March gas at under $2.60 “still seems cheap given lingering cold risks and plummeting imports this week, but this is certainly a bearish EIA number that will limit upside at the front of the gas strip moving forward,” Meisel said. Broken down by region, the Midwest reported an 84 Bcf withdrawal, the second largest pull ever for that region. A 79 Bcf draw was reported in the South Central and a 59 Bcf draw was reported in the East. Both the Mountain and Pacific regions reported pulls of less than 10 Bcf, according to EIA. Total working gas in storage as of Feb. 1 stood at 1,960 Bcf, 135 Bcf below last year and 415 Bcf below the five-year average. Ahead of the EIA report, most market participants had called for a withdrawal in the 240-250 Bcf range. Last year, the EIA reported a withdrawal of 116 Bcf for the same week, and the five-year average draw stands at 150 Bcf.
Another Bearish EIA Print Pushes Gas Lower – There was widespread selling of natural gas futures again today as overnight weather model guidance trended solidly warmer and the weekly EIA natural gas storage update yielded a smaller-than-expected storage withdrawal last week. At the end of the day the March contract settled down a bit more than 4%. Losses were by far most pronounced at the front of the strip yet again, with bearish weather changes and cash prices not particularly strong in the face of cold weather tomorrow and this weekend. The result was that the March/April H/J spread finally flipped into contango for the first time. Much of this move was driven by the morning’s EIA Natural Gas Weekly Storage Report, when the EIA announced that 237 bcf of gas was withdrawn from storage versus our expectation of 253 bcf. This was another very loose print that confirmed we have ample production and gas headed into the tail end of winter and the spring shoulder season. Though not as loose as last week’s storage number, it provided little reason to rally. Immediately following the number we sent out our EIA Rapid Release, which outlined that we saw the number as “Moderately Bearish” for natural gas prices moving forward. Gas prices then continued lower from there, with afternoon model guidance doing little to help stabilize prices (though European ensemble guidance did add several GWDDs). Climate Prediction Center forecasts showed more warm risks Week 2 over yesterday, which we had covered in our Morning Update. Now traders will be attempting to position ahead of the weekend, as we’ve been seeing significant weather model changes each of the last few weekends that have whipped prices around.
Are Investors Finally Waking up to North America’s Fracked Gas Crisis? – The fracked gas industry’s long borrowing binge may finally be hitting a hard reality: paying back investors.Enabled by rising debt, shale companies have been achieving record fracked oil and gas production, while promising investors a big future payoff. But over a decade into the “fracking miracle,” investors are showing signs they’re worried that payoff will never come – and as a result, loans are drying up. Growth is apparently no longer the answer for the U.S. natural gas industry, as Matthew Portillo, director of exploration and production research at the investment bank Tudor, Pickering, Holt & Co., recently told The Wall Street Journal. “Growth is a disease that has plagued the space,” Portillo said. “And it needs to be cured before the [natural gas] sector can garner long-term investor interest.”Hints that gas investors are no longer happy with growth-at-any-cost abound. For starters, several major natural gas producers have announced spending cuts for 2019. After announcing layoffs this January, EQT, the largest natural gas producer in the U.S., also promised to decrease spending by 20 percent in 2019. Such pledges of newfound fiscal restraint are most likely the result of natural gas producers’ inability to borrow more money at low rates.
ExxonMobil says it expects to ‘sanction’ Golden Pass LNG export project with Qatar Petroleum – ExxonMobil expects to advance its long-dormant Golden Pass LNG export project with Qatar Petroleum in Texas and will make a formal announcement in the near future, CEO Darren Woods said Friday. The redevelopment and conversion of the Golden Pass receiving terminal would be a significant addition to US Gulf Coast LNG export capacity, as it sits directly across the water from Cheniere Energy’s Sabine Pass export facility in Cameron Parish Louisiana. US Department of Energy data shows it has not imported any gas since June 2011. At the World Gas Conference in Washington in June, a senior executive said the company was working toward a final investment decision and felt good about the project moving forward. Since then, several North American export projects have announced positive FIDs, expansions of existing facilities or have suggested that they were close to making decisions. During a conference call to discuss fourth-quarter financial results, Woods said ExxonMobil now expects to “sanction” Golden Pass. “We’ve also been working very closely with QP, our partner in Golden Pass, to advance that investment and look forward to announcing something here in the very near term,” Woods said. He did not specify a time frame for the announcement.
Exxon Mobil and Qatar green light $10 billion project to export natural gas from Texas – Exxon Mobil and Qatar Petroleum on Tuesday announced a final decision to finance a $10 billion-plus project to export liquefied natural gas from the Texas Gulf Coast. The decision moves forward the latest export terminal fueling growing shipments of U.S. LNG, or natural gas cooled to liquid form, for overseas travel. The Department of Energy last month forecast that LNG will play a major role in the U.S. exporting more energy than it imports by 2020, a feat the nation has not achieved in nearly 70 years. The plan to export LNG from Exxon’s Golden Pass terminal speaks to the renaissance in U.S. energy production. The facility was originally built to import LNG, but the surge in U.S. natural gas production over the last decade means American drillers are now looking overseas for buyers. Exxon says work to retool the terminal near Port Arthur, Texas, along the Louisiana border will begin this quarter. The oil giant expects the facility to start up in 2024 and says it will ultimately be able to produce roughly 16 million tons of LNG each year.Total U.S. LNG exports were 14.3 million tons in 2017 and climbed to 15 million tons through the first three quarters of 2018, according to Reuters. Trade in LNG reached nearly 300 million tons in 2017 and is growing, particularly in Asia, where China is switching from coal to cleaner-burning natural gas to improve air quality. The shipping channel that straddles the Texas-Louisiana border is already home to the Sabine Pass LNG terminal operated by Cheniere, the first mover in the emerging Gulf Coast export hub. Exxon’s partner in the Golden Pass project, state energy company Qatar Petroleum, holds a 70 percent stake in the development. Qatar, the world’s top LNG producer, recently left the oil producer group OPEC, saying it would focus on expanding its natural gas business. Exxon holds the remaining 30 percent stake in the project, part of its plan to invest $50 billion in U.S. manufacturing facilities over the next five years, with a focus on the Gulf Coast. The company expects the terminal to support 200 permanent jobs and 9,000 positions while it’s under construction.
Will anything slow down the U.S. LNG juggernaut? – It is no surprise that U.S. natural gas producers have been seeking relief from domestic prices that have generally hovered between $2 and $4 per thousand cubic feet for most of this decade.Qatar Petroleum and Exxon Mobil Corp announced last week that they would be adding to investment in Texas in liquefied natural gas capacity for export from the United States, a move that was described as a response the immense volumes of gas coming from American shale deposits. With so many LNG projects being built and on the drawing board, will anything slow down the U.S. LNG juggernaut? The fight over U.S. exports of natural gas is long since over. U.S. producers now have the right – like almost all other U.S. producers of commodities or manufactured products – to sell their products to the highest bidder wherever that bidder may be in the world. U.S.-based industrial consumers of natural gas howled a bit when the federal government lifted restrictions on natural gas exports. But since then gas prices have maintained their ground-hugging trajectory.This is in part because gas associated with the production of oil produced from similar shale deposits has continued to flood the U.S. market. But with the price of oil slumping and a reduction in the pace of drilling expected, that associated gas may not be so plentiful. The irony is that falling oil prices may ultimately lead to a spike in U.S. natural gas prices. But if the pure natural gas shale plays are so productive, how can this be? The answer is quite simply that they aren’t. And, that is the secret behind the next bull market in U.S. natural gas. It likely won’t come as a result of demand for U.S. LNG so much as a surprise shortage of domestic gas. It turns out that just two of the six big shale gas plays in the United States are not yet past their peak production. It’s a puzzle how this translates into abundance in the long run for America. For context, for 2018 through November (the latest month for which statistics are available) total net natural gas exports amounted to 588 billion cubic feet. That’s a tiny fraction of the 29.8 trillion cubic feet of U.S. marketed production during the same period. The great American export boom seems to be a ways in the future if it ever materializes. We’re still using almost all of what we produce at home.
Overseas Demand Expansions Key To U.S. Ethane Export Growth — The U.S. started exporting ethane by ship less than three years ago, first out of Energy Transfer’s Marcus Hook terminal near Philadelphia and then from Enterprise Products Partners’ Morgan’s Point facility along the Houston Ship Channel. Good news for NGL producers, right? Well yes, sort of. Because while waterborne export volumes rose through 2016, 2017 and the first seven months of last year, they’ve been flat-to-declining ever since, with further ethane-export growth hampered primarily by a lack of international demand. That demand may soon be ratcheting up – mostly in China, but also in Europe – but it won’t happen overnight. Today, we discuss ethane export trends, the Morgan’s Point and Marcus Hook marine facilities, and plans for new ethane export capacity tied directly to new overseas ethane crackers. U.S. NGL production, NGL fractionation, and the market for NGL purity products (ethane, propane, normal butane, isobutane and natural gasoline) have been frequent topics in the RBN blogosphere the past few months. Back in September, in Hotel Fractionation, we discussed how, with the production of mixed NGLs (aka y-grade) soaring, fractionators at the NGL hub in Mont Belvieu, TX – and elsewhere in Texas and in Louisiana – are running at or near capacity, and that a scramble is on to build new fractionation capacity. Then, in Seasons Change (in December), we looked at what caused most purity-product prices to dive in October and November (one factor was the sharp decline in crude oil prices). And, in our four-part series, Between Mont Belvieu and the Deep Blue Sea, we examined rising U.S. exports of propane and normal butane – the two purity products generally referred to as LPG – and the LPG export facilities in place and being planned to handle those rising volumes.
Trump Touts US as Net Energy Exporter — President Donald Trump used his State of the Union address Tuesday night to tout “a revolution in American energy” that has made the U.S. “a net exporter” — but some of his celebration might be premature. Although the U.S. briefly became a net petroleum exporter during one week last November, government analysts say it will be at least September 2020 before it claims that title on a steady basis, by shipping out more energy than it imports on an annual basis. The nation is already a net exporter of coal and natural gas. Trump’s brief salute to U.S. fossil fuel dominance — one passing mention in a speech expected that lasted more than hour — also invoked a milestone that was partially achieved before he won the White House, under former President Barack Obama. “The United States is now the No. 1 producer of oil and natural gas anywhere in the world,” he said, provoking steady applause in the U.S. House chamber. The U.S. has been the world’s top natural gas producer since at least 2009, according to the Energy Information Administration. And it surpassed Russia as the world’s largest crude oil producer last year (though the U.S. has led the world when it comes to a wider array of petroleum hydrocarbons since 2013). Trump’s decision to hail fossil fuels isn’t unique in this forum. Obama touted natural gas production in his 2012 State of the Union speech, back when many environmentalists welcomed it as a cleaner-burning coal alternative that could be a bridge to a lower-carbon future. But Trump’s fossil push stands in stark contrast to the priorities of many environmentalists today — as well as a campaign by progressive Democrats to ratchet down U.S. reliance on oil, gas and coal. A draft of the so-called Green New Deal framework developed by Democratic Representative Alexandria Ocasio-Cortez of New York and Democratic Senator Ed Markey of Massachusetts calls for drawing 100 percent of U.S. power from “clean, renewable and zero-emission energy sources.’’
‘Fracking’ ban bills to be heard in House, Senate –– With Gov. Ron DeSantis supporting the idea, proposals to ban the controversial oil- and gas-drilling technique known as “fracking” could start moving in the House and Senate. The House Agriculture & Natural Resources Subcommittee and the Senate Environment and Natural Resources Committee are scheduled Wednesday to take up bills (PCB ANRS 19-01 and SB 314) that would prohibit fracking in the state. Florida has long had oil drilling in parts of the Panhandle and Southwest Florida, but the possibility of fracking has led to repeated debates. Critics of the technique contend it could lead to water contamination. Past attempts to ban the practice have died in the Legislature, but DeSantis, who took office Jan. 8, has called for a prohibition. The bills are filed for consideration during the legislative session that starts March 5.
A School Board Says No to Big Oil, and Alarms Sound in Business-Friendly Louisiana – It was a squabble over $2.9 million in property-tax breaks – small change for Exxon Mobil, a company that measures its earnings by the billions. But when the East Baton Rouge Parish school board rejected the energy giant’s rather routine request last month, the “no” vote went off like a bomb in a state where obeisance to the oil, gas and chemical industries is the norm. The local chamber of commerce took out a full-page newspaper ad, warning of a rise of “radicalism.” The head of the Louisiana Association of Business and Industry wrote that “the anti-business crowd has had their fun,” but needed to “cool their jets.” And now, somewhat surprisingly, business-friendly Louisiana finds that it is the latest flash point in a roiling, community-by-community debate that pits liberals and local activists against defenders of the lavish tax incentives offered to woo big business. It has been a David vs. Goliath story in the Louisiana capital, where a grass-roots coalition of black and white churches, activists and ordinary citizens have successfully clamored to democratize a system that used to dole out billions in property-tax breaks without giving the local school boards, city councils and other government entities that depend on those taxes any say in the matter. The vote has also revived a vexing, and defining, Louisiana question about the deference a perennially impoverished state must show to big business. “We’ve allowed the oil and gas industry to hijack our democracy,” said Russel L. Honoré, a retired Army lieutenant general who earned acclaim for leading the military response to Hurricane Katrina, and who had urged the East Baton Rouge Parish school board to reject the exemptions. “The industry will brag about it all the time, how well we’re doing in terms of business development. Well, if we’re doing so well, why are we the second-poorest state?”
Armada of tankers with Venezuelan oil forms in U.S. Gulf: sources, data (Reuters) – A flotilla loaded with about 7 million barrels of Venezuelan oil has formed in the Gulf of Mexico, some holding cargoes bought ahead of the latest U.S. sanctions on Venezuela and others whose buyers are weighing who to pay, according to traders, shippers and Refinitiv Eikon data. The Trump administration’s move to impose sanctions last week was meant to undercut support for Venezuelan President Nicolas Maduro by targeting the Latin American nation’s oil exports to the United States, the source of most of its foreign revenue. The sanctions aim to block U.S. refiners from paying into PDVSA accounts controlled by Maduro – one reason numerous tankers are waiting in limbo off Venezuela with payments unclear. The United States buys 500,000 barrels of Venezuelan crude per day. U.S. customers of Venezuela’s state-run PDVSA are required by sanctions to deposit payments into escrow accounts that have not yet been set up. The funds will be controlled by Venezuelan congress head Juan Guaido, whom the United States, the European Union and much of Latin America recognize as the country’s leader. Neither the U.S. Treasury Department nor White House responded to requests for comment. There were over a dozen tankers this week anchored in Gulf of Mexico or outside of Venezuelan waters, according to the Refinitiv Eikon data, as shippers await payment and delivery directions from buyers. Traders said some of the cargoes were used as floating storage by buyers who took advantage of PDVSA’s open market sales ahead of sanctions. Others were held by trading firms struggling to find refiners willing to take the oil due to payment difficulties related to sanctions.
Why tapping America’s oil reserve is a bad idea – President Donald Trump’s crackdown on Venezuela threatens to create a shortage of heavy crude, which American refineries need to churn out gasoline, jet fuel and diesel. If prices climb in response to the administration’s sanctions on Venezuela and its state-run oil company, PDVSA, the Energy Department might try to cushion the blow by releasing crude that’s stored in the Strategic Petroleum Reserve (SPR). But analysts caution that tapping the SPR won’t do much to ease a shortage, especially not in the long run. The problem is that not all crude is created equal. Different regions produce different grades of crude. Some of it, like what comes out of Venezuela, is so thick and heavy that it can’t be put into pipelines. Other crude, like what gets pumped in Texas, is a very light and clear like gasoline. The emergency oil reserve contains crude that is mostly lighter than the 500,000 barrels per day that Venezuela had been shipping to the United States. The reserve includes some medium crude, too. The Gulf Coast refineries are not configured to use what’s in the rainy-day fund. The crackdown on Venezuela is a fresh reminder that the United States, which has morphed into an energy super power lately, remains reliant on foreign oil. In the late 1990s, US oil production was believed to be in decline. Refiners could no longer count on light, sweet crude from Texas, and other US states, to churn out gasoline, diesel, and jet fuel.Refiners went through a transformation that enabled them to take in heavy, sour crudes from overseas. Flash forward to today, US refineries regularly mix light crude from shale hotspots like the Permian Basin in West Texas with heavy crude from Saudi Arabia, Canada, Mexico, and of course Venezuela. Refiners can’t just turn on a dime when the heavy crude gets sidelined. Some refiners short on heavy crude could take medium barrels from the SPR. However, they would probably not be able to operate at maximum capacity.
EIA: Venezuela Oil Sanctions Unlikely To Significantly Impact U.S. Refiners – The U.S. sanctions on Venezuela’s oil industry and state oil firm PDVSA are unlikely to have a significant impact on the refinery runs of the U.S. refiners, the Energy Information Administration (EIA) said in an analysis this week. U.S. imports of crude oil from Venezuela have been falling in recent years, and U.S. refiners have been replacing heavy crude from Venezuela from heavy crude grades from other sources, the EIA said.Last week, the U.S. imposed sanctions on PDVSA to “help prevent further diverting of Venezuela’s assets by Maduro and preserve these assets for the people of Venezuela,” Secretary of the Treasury Steven T. Mnuchin said.Those sanctions will essentially eliminate U.S. imports of Venezuelan crude oil as the full effects of the sanctions emerge, the EIA said, but noted that it doesn’t expect “any significant decrease in U.S. refinery runs as a result of these sanctions.”Imports of crude oil from Venezuela are still a significant portion of the U.S. Gulf Coast imports, but they have been falling in recent years due to the collapsing Venezuelan oil production. Gulf Coast imports of Venezuelan crude oil fell to an average of 498,000 bpd between January and November 2018 from an average of 618,000 bpd in the first 11 months of 2017, the EIA said.Out of the 14 U.S. refineries that imported crude from Venezuela last year – 12 of which in the Gulf Coast – imports in January-November declined by 129,000 bpd compared with the same period in 2017. While imports from Venezuela declined, imports from Canada and Mexico to these refineries rose by 113,000 bpd and 48,000 bpd, respectively, from 2017 levels, the EIA has estimated.“Moving forward, refineries may also choose to run lighter crude oils because transportation constraints may limit the availability of heavy crude oils,” according to the EIA.Refiners with large c apacity to process asphalt and road oils, for which Venezuela’s heavy crude is well-suited, may find it harder to procure adequate replacement, but these refiners have also cut imports from Venezuela recently, the EIA noted.
Activists Call For Smaller-Scale Fracking Transparency – Illinois began regulating high-volume fracking in 2013, but most wells in the state aren’t large enough to fit that definition. Organizers from Illinois People’s Action and Fair Economy Illinois at a press conference Wednesday said low-volume fracking is more common, and can be kept covert. “A horizontal well could go right under your property and you wouldn’t know about it,” said William Rau of People’s Action. “There are no defensive actions you could take like, for example, getting a test on your water well.” Low-volume fracking is governed by the Oil and Gas Act of 1951. According to People’s Action, a confidentiality clause allows fracking companies to pay a few hundred dollars for a permit and then frack in secret for two years. More than 1,000 such permits were filed in 2014, Rau said, with the number dropping to around 250 the following two years. Since high-volume regulation began in 2013, the Illinois Department of Natural Resources issued just one permit, but the company never used it. The groups support legislation requiring the same oversight for all fracking. It would make two sets of information public: where fracking is happening, and what chemicals are being pumped into the ground. Two other pieces of legislation were discussed at the news conference. One would cap the amount large businesses collect from consumer sales tax through the “retailers’ discount.” Another is aimed at ending so-called offshore tax sheltering. The Illinois Chamber of Commerce issued a statement opposing the latter legislation, claiming it “attempts to fix a problem that doesn’t exist.”
Two Pipelines Shut Down After 43 Barrels of Crude Leak into Missouri Soil – Parts of two pipelines owned by controversial Canadian pipeline companies remained shut down Thursday following the discovery of a leak near St. Louis, Missouri on Wednesday, CBC News reported.Both TransCanada‘s Keystone pipeline and Enbridge‘s Platte pipeline run parallel to each other through the area. The Keystone pipeline, which carries 590,000 barrels of crude oil a day from Alberta, has faced opposition from environmental activists in the area because it transports from Alberta’s tar sands.”[Leaks] are one more reason on top of climate change to show that tar sands are dangerous and should not be running through our state,” Missouri Sierra Club Director John Hickey told St. Louis Public Radio. Residents are also worried the poor quality of the pipeline’s steel makes leaks more likely, Hickey said.The leak was discovered by a TransCanada technician 7:14 a.m. Wednesday. The technician found crude oil covering some 4,000 square feet around the pipeline in St. Charles County, Missouri. TransCanada said it was not sure how much oil had leaked, but thought it was around 43 barrels. The company said it was not yet possible to tell if the leak came from the Keystone or neighboring Enbridge pipeline. “Until you can excavate and see the top of the pipes, you can’t really determine which pipeline the release occurred from,” TransCanada Public Information Officer Matthew John told St. Louis Public Radio.
Two pipelines, including Keystone, shut after oil leak in St. Charles County – Two national oil pipelines have at least been partially shut down as a result of leakage discovered Wednesday in St. Charles County, near the Mississippi River. Questions far outnumbered answers nearly 36 hours after the crude oil leak was first reported to authorities, as crews continued to work around the clock to identify which of two pipelines in the area may be the source of the spill: TransCanada Corp.’s 30-inch-wide Keystone pipeline, or another, 20 inches wide, from Enbridge Inc., called the Platte pipeline. “The release is stopped,” a Missouri Department of Natural Resources official said Wednesday night, adding that the crude oil spill occurred north of the city of St. Charles. DNR officials said Thursday that the leak was about 1,700 feet south of the river and did not threaten it. Both pipelines are buried about 8 feet below ground. Beyond trying to identify which one might have the leak, officials said they also had yet to determine when and why a rupture occurred. “There’s a lot of unknowns at this point,” said Brad Harris, chief of the DNR’s environmental emergency response section. “They’re working their way down to expose that pipeline,” he said of the vacuum trucks on the site. “As you can imagine, it’s very, very sloppy.” He said the spill was estimated to be at least “43 barrels,” or about 1,800 gallons, according to an early report to the department about what was visible at the surface. It was unclear if that estimate would change. “It’s contained in this low area,” Harris said. “I think we’ve gotten lucky. Four thousand square feet is the estimated impacted area.” A survey to determine how many wells are in the area will be done by the DNR and the company found responsible for the leak, Harris said, and samples will be taken to check for water safety. Once a responsible company is identified, he said, a proper cleanup will ensue to remove contaminated soil and water. A TransCanada spokesman said that the leak was discovered by a company technician doing a routine check at the site and that the line was shut down immediately Wednesday. The Keystone pipeline typically moves about 600,000 barrels per day through the area, while the Platte pipeline transports about 150,000 barrels per day. Enbridge’s Platte pipeline was also shut down, Harris said. That line runs 933 miles from Wyoming to Wood River, Ill.
Keystone pipeline likely source of Missouri crude spill, says TransCanada – no restart date yet – An oil leak near St. Louis, Missouri likely originated from TransCanada Corp’s Keystone pipeline, the company said on Friday, with no projected restart timetable for the portion of the line that remains shut. The leak volume is estimated at 43 barrels of crude oil on land, according to Missouri’s Department of Natural Resources. The spill and subsequent shutdown of portions of Enbridge’s Platte pipeline and the bigger Keystone line raised fresh concerns about pipeline safety, and about the already constricted flow of Canadian oil to U.S. refineries. Crews were excavating a segment of the underground pipeline on Friday, TransCanada spokesman Terry Cunha said. He said there was no threat to public safety or the environment. The 590,000 barrels-per-day Keystone pipeline is a critical artery taking Canadian crude from northern Alberta to U.S. refineries. The spill in rural St. Charles County, Missouri, on Wednesday led TransCanada to shut an arm of Keystone running between Steele City, Nebraska, and Patoka, Illinois. Brian Quinn, a spokesman for Missouri’s Natural Resources Department, said in an email that if Keystone is confirmed to be the leak’s source, it will remain closed until repairs are made. The exact quantity of oil released cannot be determined until excavation is complete and it’s unclear how long the release lasted, Quinn said. TransCanada told Keystone shippers on Thursday that it was declaring force majeure on shipments affected by the shutdown, according to a notice seen by Reuters. Force majeure is a declaration that unforeseeable circumstances prevented a party from fulfilling a contract. Canadian pipelines are congested because of expanding production in recent years, forcing the Alberta provincial government to order production cuts starting last month. Canadian heavy oil has attracted greater demand following U.S. sanctions against Venezuela’s state oil company.
Sunoco Pipeline and Mid-Valley Pipeline settle oil spill violations – In the latest joint federal-state Clean Water Act enforcement action, Sunoco Pipeline L.P. has agreed to pay civil penalties and state enforcement costs and to implement corrective measures to resolve alleged violations of the Clean Water Act and state environmental laws by Sunoco and Mid-Valley Pipeline Company stemming from three crude oil spills in 2013, 2014 and 2015, in Texas, Louisiana, and Oklahoma. The Department of Justice, the US Environmental Protection Agency (EPA), and the Louisiana Department of Environmental Quality (LDEQ) jointly announced the settlement. Under a proposed consent decree lodged in the US District Court for the Western District of Louisiana, Sunoco will pay the United States US$5 million in federal civil penalties for the Clean Water Act violations and pay LDEQ US$436 274.20 for civil penalties and response costs to resolve claims asserted in a complaint filed this week. Additionally, Sunoco agreed to take actions to prevent future spills by identifying and remediating the types of problems that caused the prior spills. This includes performing pipeline inspections and repairing pipeline defects that could lead to future spills. Sunoco is also required to take steps to prevent and detect corrosion in pipeline segments that Sunoco is no longer using. Mid-Valley, the owner of the pipeline that spilled oil in Louisiana, is responsible, along with Sunoco, for payment of the civil penalties and state costs relating to the Louisiana spill. “This settlement holds Sunoco and Mid-Valley accountable for the harms to the environment caused by their oil spills and requires Sunoco to improve its environmental safety compliance for the oil pipelines that it operates in Texas, Louisiana, and Oklahoma,” said Assistant Attorney General Jeffrey Bossert Clark for the Justice Department’s Environment and Natural Resources Division. “This excellent result shows how a strong federal and state partnership can bring about effective environmental enforcement to protect local communities in these states.”
Plains keeps open possibility of further Permian oil pipeline consolidation – As concerns loom about a Permian oil pipeline overbuild, Plains All American did not rule out the possibility Tuesday of teaming up with another competing project for its recently confirmed 1 million b/d pipeline to the Texas Gulf Coast. Plains is the latest midstream company to report fourth-quarter earnings in a cycle where the big question is whether the Permian is about to swing from having too little pipeline space to having a glut of it. The Wink to Webster Pipeline joint venture announced last week by Plains, ExxonMobil and Lotus Midstream will carry batched crude and condensate from West Texas to Houston starting in the first half of 2021. Plains owns a 20% stake and will be constructing the line. Asked if too many Permian pipelines were in the works, Plains CEO Willie Chiang said during a conference call on fourth-quarter earnings that the company wanted to get to the point of ordering pipe for Wink to Webster and be in a position to move forward. “What that says is we certainly haven’t eliminated an opportunity to make the project stronger, and conversations continue,” he said. “At the base core of it, we’ve got pipe ordered, and we’re ready to go.” The JV has ordered some 650 miles of domestically sourced 36-inch-diameter line pipe. Plains’ 585,000 b/d Cactus II crude pipeline from the Permian to Corpus Christi is on schedule for partial service in late Q3 and full service by April 2020, Chiang said. Asked about the wave of crude export capacity planned for the Texas and Louisiana coasts, Chiang said Plains’ strategy is to diversify options for shippers. He said the company initially looked at an integrated pipe and dock system during the open season for Cactus II a few years ago.
Frac Sand Accumulates as Demand Weakens — Just a year after rushing into America’s busiest oil field with new mines, frac-sand producers may have overdone it. West Texas sand used in the hydraulic fracturing process will drop 19 percent this year to about $30 a ton compared to 2018, according to industry consultant Rystad Energy AS. Sand pricing is a key financial input for oil explorers because fracking is the most expensive phase in drilling an oil well. A slew of new West Texas mines close to Permian Basin drilling sites is elbowing Midwest mines that formerly dominated the frac-sand trade. Miners in and around Wisconsin that controlled 75 percent of the market in 2014 will see that diminish to 34 percent in 2020, Ryan Carbrey, Rystad’s senior vice president of shale research, told Petroleum Connection’s Frac Sand Industry Update conference in Houston on Wednesday. “We do think that things continue to be rather sloppy from a pricing standpoint in 2019,” Chase Mulvehill, an analyst at Bank of America Merrill Lynch, said in a presentation during the conference. “We’ll see if people renegotiate contracts. What we’ve heard so far is people are actually starting to do that for some in-basin contracts.” The sand oversupply has developed just as demand for fracking is taking a hit from the late-2018 slump in crude prices and more modest exploration programs by oil producers, Mulvehill said. Fracking demand is set to drop 3 percent in 2019, he said.
Exxon Streamlines Upstream to Support Growth – ExxonMobil Corporation (Exxon) has revealed it will “streamline” its upstream organization and “centralize project delivery across the company” to support previously announced plans to double operating cash flow and earnings by 2025. The reorganization will be effective April 1 and will involve the creation of three new upstream companies; ExxonMobil Upstream Oil & Gas Company, ExxonMobil Upstream Business Development Company and ExxonMobil Upstream Integrated Solutions Company. ExxonMobil Upstream Oil & Gas Company will focus on end-to-end value chain management in five global businesses – comprising unconventional, liquefied natural gas, deepwater, heavy oil and conventional – Exxon revealed. “We’re simplifying and integrating our upstream organization to better capitalize on the industry-leading portfolio we’ve assembled through acquisitions and exploration success in the U.S. Permian Basin, Guyana, Mozambique, Papua New Guinea and Brazil,” Neil Chapman, Exxon senior vice president, said in a company statement. “Our focus is on increasing overall value by strengthening our upstream business and further integrating it with the downstream and chemical segments to take advantage of our unique capabilities across the value chain. A clear example is what we’re doing in the Permian, which includes upstream, midstream and downstream investments, enabling us to maximize value unlike any of our competitors,” he added.
Chevron ties executive pay to methane and flaring reduction targets (Reuters) – Chevron Corp plans to set greenhouse gas emissions targets and tie executive compensation and rank-and-file bonuses to the reductions, the oil major said in its latest climate report released on Thursday. The move is a first for a U.S. oil major and focuses on the company’s oil fields. More investors have been pressuring San Ramon, Calif.-based Chevron and other big oil companies to reduce emissions that contribute to climate change. Chevron said that by 2023, it will reduce its methane and flaring intensity by 25 percent to 30 percent from 2016 levels, and said the goal would be added to the scorecard that determines incentive pay for around 45,000 employees. “It’s about the mindset and the culture of the company,” said Chevron Vice President Mark Nelson, noting that including most of its global workforce would “harness” ideas from all employees. Chevron, though, does not address reducing the company’s full carbon footprint, said Danielle Fugere, president of investor group As You Sow, and so “will not achieve the reductions needed to stabilize the climate and reduce growing economy wide and thus portfolio wide risk to investors.” Among other oil companies, London-based BP and France’s Total have set short-term targets on reducing carbon dioxide emissions from their own operations. Royal Dutch Shell in December announced it would link executive compensation to reducing carbon dioxide emissions starting in 2020, including Scope 3 emissions from fuels sold to customers around the world. Chevron said it does not support establishing Scope 3 targets. Exxon’s climate report, published on Tuesday, includes a goal of reducing methane emissions from operations by 15 percent and flaring by 25 percent by 2020 compared with 2016 levels. Chevron’s target aims to reduce emissions and flaring as a percentage of production, but does not set a total emissions goal – a measure activist investors prefer. The targets will apply to Chevron’s operations as well as assets it has a stake in but does not operate itself, the company said.
Rystad Energy: Large-scale projects a factor for profitable shale drilling –As US crude oil production is set to rise substantially over the next decade, analysts still debate whether shale drilling is an actual profitable endeavor. Some skeptics claim operators overstate their well production profiles, while others say operational cash flow from shale wells will never be enough to cover corporate costs and old debt. Analysts and investors are now waiting to see fourth quarter earnings as an acid test on profitable growth in the Permian basin at lower oil prices. Quarterly results have already been published by ExxonMobil Corp., Chevron Corp., and Anadarko Petroleum Corp., of which only Chevron appeared to generate positive cash flow from operations in the Permian. ExxonMobil and Anadarko, meanwhile, seemed to still be in investment mode in the play. Rystad Energy believes net cash is now likely in the red for many smaller oil companies that focus entirely or predominantly on the Permian. A number of factors can constrict the internal diameter of wellbore casing and threaten the completion of a well. This article discusses tools and approaches to bypass restrictions and restore well viability. Having taken a closer look at the detailed economics of the most recent 1,000 wells drilled in the most popular shale hotspot – the Wolfcamp A zone of the Permian Delaware basin – Rystad Energy can see a clear pattern emerging that favors large players.“Our conclusion is that the average well completed during 2017 and 2018, which mirrors the most likely production profile and costs, appears very profitable even at local oil prices of $45/bbl,” said Per Magnus Nysveen, Rystad Energy senior partner.“However, there are also many wells that will not be profitable at this price level, and drilling needs to be conducted on a large scale in order to secure robust cash flows even in the hottest play. Betting on a low number of wells could give more uncertain returns than rolling the dice at the nearest casino.” Operators with scaled operations and large acreage positions exposed to Wolfcamp A in the Permian Delaware should see average returns of 20%, and 3 years’ payback from new wells, even with West Texas Intermediate Midland oil prices at $45/bbl. Smaller operators, meanwhile, would face higher costs for drilling, completion, operation, and transport, and also lower realized oil prices.“These operators might struggle in the current price environment, and their best opportunity to monetize their investment could be to sell their acreage to larger operators with more efficient logistics, better infrastructure, and more negotiating power through the value chain,” Nysveen said. “Size matters, even more so when drilling for shale oil in the Permian basin.”
Hess Needs Higher Oil Prices – Hess Corporation just recently reported its fourth quarter and full-year results for 2018. Readers should note that the financial performance of Hess Corporation is consolidated with Hess Midstream Partners LP its midstream master limited partnership. After reviewing Hess Corporation’s financial statements for 2018, it’s clear that the firm needs higher oil prices to generate positive net income. Let’s dig in. In 2018, Hess reported $6.5 billion in revenue on a consolidated basis, up 20% year over year. Hess reported an enormous $4.2 billion impairment charge in 2017. When factoring that out, its operating loss came in at a whopping $1.3 billion that year, which improved to an operating profit of $0.6 billion in 2018 ($0.7 billion when excluding $0.1 billion in debt extinguishment expenses). However, Hess still reported a net loss of $0.3 billion in 2018. That is much better than its $4.1 billion net loss in 2017, but indicates a lot of work still needs to be done to fundamentally change Hess’ cost structure if it wants to perform better. Hess notes that when including the impact of its hedging program, the firm’s average sales price for a barrel of crude oil, a barrel of natural gas liquids, and a thousand cubic feet of natural gas during 2018 came in at $60.77, $21.81, and $4.18, respectively. If Hess can’t turn a profit in a $60 WTI/$70 Brent world, that’s a problem. Its international natural gas realizations are influenced by Brent.
Analysis: SCOOP/STACK natural gas production hits record high – As natural gas production volumes in the SCOOP/STACK struck a record high this week, operators in the Oklahoma play are indicating plans to continue accelerating growth throughout 2019 despite uncertainty surrounding commodity prices. Production in the SCOOP/STACK set a new daily record of 3.53 Bcf/d on Monday, according to S&P Global Platts Analytics. Despite the Polar Vortex striking the region last week, production volumes were hardly phased by freeze-offs at wellheads. And any decline which may have occurred from the frigid weather was quickly reversed. Platts Analytics models show production dropping late last week as population-weighted temps fell as low as 8 degrees. However, it only dropped by 65 MMcf/d from the previous two-week average to 3.41 Bcf/d, which is within the bounds of normal volatility. The cold weather had much less of an impact on production in the region than in the past. For example, last January, when population-weighted temperatures in Oklahoma dipped to an average of 3 degrees, production plummeted by more than 500 MMcf/d before recovering once average temps rose to 30 degrees. A primary driver of the most recent growth in the region has been in Grady County, located over what is referred to as the SCOOP. Sample production is averaging 610 MMcf/d this month to date, which would be a new record if it continues, surpassing last month’s record of 587 MMcf/d, according to Platts Analytics. Total SCOOP/STACK production is forecast to grow about 300 MMcf/d from current levels by this time next year. However, WTI’s recent price decline could jeopardize this. For instance, Grady County has averaged just 23 active rigs over the past month, down from 29 over the previous six months. Across the entire SCOOP/STACK, the active rig count has averaged 104 over the past month, down slightly from the 107 rig average throughout the back half of 2018. However, producers have been able to produce more with less due to perpetual improvements in drilling and completion techniques. Also, just over a year ago, the state of Oklahoma passed a new law allowing for operators to drill longer laterals in all geologic formations. Private oil and gas producer Chaparral Energy, which operators solely in the Anadarko Basin, increased its production in the STACK during the fourth quarter of 2018 by 60% compared to the fourth quarter of 2017 while only adding one additional rig, according to its latest operational update.
US oil and gas rig count rises by one to 1114 on week – The US oil and natural gas rig count inched up by one rig week on week to 1,114, rising for the second week in a row after a relatively lengthy prior period of declines, according to S&P Global Platts Analytics data released Thursday. The basins where gas rigs rose on a net basis appeared to be largely, or somewhat largely, gas-prone — the Marcellus Shale in Pennsylvania and surrounding states, and the DJ Basin in Colorado, which has a large cache of oil as well as gas.Most likely the small rig gains are simply the result of new budgets and activity programs, Platts Analytics analyst Taylor Cavey said.”Crude prices have rallied slightly, which could justify drilling, but I would think it has more to do with producers starting to implement 2019 plans,” Cavey said.WTI crude prices, which had dipped below $50/b in late December and early January, have floated above that level for several weeks. Oil, gas and total rigs are all sizably down from recent highs in mid-November. This week, oil rigs rose by eight on the week to 875, although fully 10% below that category’s recent high of 976, while gas rigs declined by six to 217, in contrast to a recent high of 235.The total rig count is also nearly 10% off its recent high of 1,233, Platts data showed.A two-rig decline to 17 also was posted this week for rigs not specified for oil or gas. Regions where rigs rose included the giant gas-prone Marcellus Shale, up by two rigs this week to a net 63 and the DJ Basin, up one rig to 30, Platts data showed. Other basins showed mostly net rig losses. The Eagle Ford Shale of South Texas and SCOOP/STACK play in Oklahoma each fell by three rigs, to 91 and 100, respectively. Down two rigs each were the Permian Basin in West Texas and New Mexico, where the count fell to 472, the Williston Basin of North Dakota and Montana, which fell to 59 rigs and the Haynesville Shale in Northwest Louisiana and East Texas, to 66. Rigs in the gas-prone Utica Shale of Ohio remained unchanged at 17. While this week’s rig count rose slightly, so did the number of permits approved — just barely. The number of permits issued was just one higher than last week at 1,227 for the week that ended Wednesday. The DJ Basin, down 78 from last week to 122, showed the most variation, while the Permian fell 29 week on week to 194. Also, 15 fewer permits were issued in the Marcellus this week – at 53. But Eagle Ford permits were up 23 from last week to 65, Utica Shale permits also were up by 23 at 24, while Haynesville permits were up by 19 to 26.
‘Valve turners’ target oil pipeline equipment in Itasca County — Itasca County sheriff’s deputies apparently took four activists into custody Monday afternoon after they used bolt cutters to break into an Enbridge pipeline facility. The activists, who call themselves the “Four Necessity Valve Turners,” are part of the Catholic Worker Movement from Texas, Wisconsin and Minnesota. They posted Facebook Live video of the incident, in which they try for several minutes to close an emergency shut-off valve on an Enbridge pipeline using a variety of tools and other objects, such as a rosary. The video ends as they are loaded into sheriff’s vehicles. “This was an action to address the imminent damage and destruction that’s already being done to the climate, and the fact that government and regulatory agencies have not adequately addressed that imminent and irreversible danger,” said Diane Leutgeb Munson, a spokesperson for the Catholic Workers. She added the valve turners felt compelled to trespass and attempt to shut down the pipeline, and they acted “in the spirit of nonviolence” to address the danger posed by climate change. The activists said that Enbridge remotely shut off the flow of oil through its Line 4 oil pipeline after they called the company. An Enbridge spokesperson declined to elaborate on the safety precautions the company took, but said no oil was spilled because of the incident. “The actions taken to trespass on our facility and tamper with energy infrastructure were reckless and dangerous,” the company said in a statement. “The people involved claimed to be protecting the environment, but they did the opposite. Their actions put themselves, first responders, neighboring communities and landowners at risk.”
4 Activists Arrested After Prompting Shutdown of Enbridge Pipeline –Four activists were arrested Monday after attempting to shut down an Enbridge pipeline near Grand Rapids, Minnesota, The Associated Press reported. The activists, who call themselves the Four Necessity Valve Turners and are affiliated with the Catholic Worker movement, said their actions were needed to address the urgent threat posed by climate change.”The recent scientific study on climate change presented to the UN indicates that the threat of irreversible damage and destruction to our planet is imminent,” the activists wrote on their website. “Therefore, having exhausted all legal and political avenues, and having found those avenues lethally inadequate either to curb our dependency on fossil fuels or to stop its expansion, we find it necessary to take this direct action of turning off the flow of this poisonous tar sands oil.” Michele Naar Obed, of Duluth, Minnesota; Allyson Polman, of Denton, Texas and Brenna Cussen Anglada and Daniel Yildirim of Cuba City, Wisconsin broke into a fenced-off area around noon on Monday that held shut-off valves for three Enbridge pipelines, their spokesperson Diane Leutgeb Monson told The Associated Press. After a period of prayer, they called Enbridge to inform them they would be turning off the company’s line 4 pipeline, prompting Enbridge to shut it off remotely. The activists were taken into custody by Itasca County sheriff’s deputies around 1:30 p.m.”The actions taken to trespass on our facility and tamper with energy infrastructure were reckless and dangerous,” Enbridge spokesperson Juli Kellner said in an email reported by The Associated Press. “The people involved claimed to be protecting the environment, but they did the opposite. Their actions put themselves, first responders, neighboring communities and landowners at risk.”The Enbridge pipelines targeted by the protesters carry crude oil from Alberta’s tar sands through Minnesota to Superior, Wisconsin. Their action also follows the controversial approval by the Minnesota Public Utilities Commission of a plan by Enbridge to replace its aging Line 3 pipeline. In addition to concerns over the need for more fossil fuel infrastructure, environmental and indigenous groups are worried about the risk of an oil spill close to land sacred to the Ojibwe. This is a concern taken up by the valve turners as well. “This act is step towards reparations for the damage that colonization has done both to the indigenous peoples of this continent and the land,” Cussen Anglada said in a press release.
Trump to nominate David Bernhardt, a former lobbyist, as the next Interior secretary – President Trump tweeted Monday that he will nominate David Bernhardt, a veteran lobbyist who has helped orchestrate the push to expand oil and gas drilling at the Interior Department, to serve as its next secretary.If confirmed, Bernhardt, a 49-year-old Colorado native known for his unrelenting work habits, would be well positioned to roll back even more of the Obama-era conservation policies he has worked to unravel since rejoining Interior a year and a half ago. He has helmed the department as acting secretary since Jan. 2, when Ryan Zinke resigned amid multiple ethics probes.“David has done a fantastic job from the day he arrived, and we look forward to having his nomination officially confirmed!,” Trump tweeted.While Zinke reveled in public displays of his affinity for the outdoors – riding horseback while on the job and touting his enthusiasm for hunting – Bernhardt is the ultimate insider. A former Capitol Hill staffer who served as Interior’s top lawyer under George W. Bush, Bernhardt has made it his mission to master legal and policy arcana to advance conservative policy goals.“It’s a humbling privilege to be nominated to lead a Department whose mission I love, to accomplish the balanced, common sense vision of our president,” Bernhardt said in a statement Monday. A former partner at Brownstein Hyatt Farber Schreck, he walked into the No. 2 job at Interior with so many potential conflicts of interest he has to carry a small card listing them all. He initially had to recuse himself from “particular matters” directly affecting 26 former clients to conform with the Trump administration’s ethics pledge.
Promoting ‘Another Puppet for Corporate Polluters,’ Trump Picks Former Oil Lobbyist to Head Interior Department – After President Donald Trump announced via tweet on Monday that he is nominating former oil lobbyist David Bernhardt to replace scandal-plagued Ryan Zinke as head of the Interior Department, environmental groups described Bernhardt as yet “another puppet for corporate polluters” and urged the Senate to block his confirmation. “Trump has once again nominated a corrupt industry hack to lead a critical federal agency,” Nicole Ghio, senior fossil fuels program manager for Friends of the Earth, said in a statement. “The Senate must reject Bernhardt because he will undoubtedly put his fossil fuel industry friends before the American people and our environment.” “Rather than give Bernhardt a promotion, Congress should be working on exposing his numerous conflicts of interest and ethics violations, as a fossil fuel lobbyist and now as a government official,” Ghio added. Bernhardt has been serving as acting Interior secretary since Zinke officially resigned from his post last month. As Public Citizen pointed out on Twitter, Bernhardt’s nomination fits with a long-standing pattern the Trump White House has followed after high-profile cabinet departures: As the New York Times reports, while Zinke was “the public face of some of the largest rollbacks of public-land protections in the nation’s history, Mr. Bernhardt was the one quietly pulling the levers to carry them out, opening millions of acres of public land and water to oil, gas, and coal companies.”
Trump Nominates ‘Walking Conflict of Interest’ David Bernhardt to Permanently Replace Zinke as Interior Secretary – President Donald Trump officially nominated David Bernhardt – a former energy lobbyist environmental groups have described as a “walking conflict of interest” – to officially take over as interior secretary afterRyan Zinke stepped down in December 2018 following various scandals. “It’s a humbling privilege to be nominated to lead a Department whose mission I love, to accomplish the balanced, common sense vision of our President,” Bernhardt wrote in a tweet responding to the president’s announcement, also made on Twitter Monday.As deputy secretary, Bernhardt played an active role in the Trump administration’s push to open public lands to fossil fuel and mining interests, and he is expected to continue this work if he is confirmed to permanently take over the department he has been running as acting secretary following Zinke’s departure, Reuters reported. In 2017, around 150 environmental groups wrote a letter to the Senate urging it to block his nomination to the position of deputy secretary, arguing that his work as a lawyer and lobbyist for oil and water interests at Brownstein Hyatt Farber Schreck gave him too much past history with entities that could stand to benefit from Interior Department decisions. Despite this, he was confirmed 53 to 43, and now famously carries around a list of all his potential conflicts of interest, as The Washington Post reported in November of 2018.”David Bernhardt is a walking conflict of interest who has no business overseeing America’s public lands,”Sierra Club Executive Director Michael Brune said in a statement opposing his permanent installation. “The Secretary of the Interior should be someone who respects the mission of the department and sees the value in our public lands and waters beyond their capacity to be drilled, mined, or fracked.”
Weld County oil and gas spill report for Feb. 3 – 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.
- • HIGHPOINT OPERATING CORP., reported Jan. 26 a tank battery spill about 7 1/2 miles northeast of Roggen, near U.S. 34 and Weld County Road 386. Between one and five barrels of oil spilled. An LACT unit valve was left partially open.
- • KERR MCGEE OIL & GAS ONSHORE LP, reported Jan. 24 a historical spill about 2 1/2 miles northeast of Platteville, near Weld roads 36 and 29. Less than five barrels of condensate spilled. Waters of the state were impacted or threatened. Crews found impacts while abandoning a gas sales line. About 190 cubic yards of impacted soil was removed and taken to the Kerr-McGee Land Treatment Facility. Groundwater was found in the excavation about 4.5 feet below ground surface.
- • NOBLE ENERGY INC, reported Jan. 24 a historical tank battery spill about 4 miles southeast of Evans, near Weld roads 50 and 49. Between one and five barrels of oil, condensate and produced water spilled. Crews found impacts while decommissioning the tank battery.
- • NOBLE ENERGY INC, reported Jan. 24 a historical tank battery spill about 1 1/2 miles northeast of Milliken, near Weld roads 48 and 25. Between one and five barrels each of oil, condensate and produced water spilled. Impacts were found during reclamation. Crews removed 100 cubic yards of impacted soil and took it to the Buffalo Ridge landfill.
- • WHITING OIL & GAS CORP., reported Jan. 23 a tank battery spill about 5 miles northeast of Keota, near Weld roads 106 and 111. About nine barrels of produced water spilled. Crews are not certain of the exact release point, but believe it came from the produced water tank and spilled inside containment. About three barrels were recovered.
- • NOBLE ENERGY INC, reported Jan. 22 a historical tank battery spill about 4 miles south of Kersey, near Weld roads 44 and 53. Less than a barrel each of oil, condensate and produced water spilled. Waters of the state were impacted or threatened. Crews found impacts while dismantling the tank battery.
- • NOBLE ENERGY INC., reported Jan. 22 a historical tank battery spill about 6 miles northwest of Keenesburg, near Weld roads 30 and 49. Between one and five barrels of oil, condensate and produced water spilled. Waters of the state were impacted or threatened. Crews found impacts while dismantling the tank battery.
- • KERR MCGEE GATHERING LLC, reported Jan. 21 a historical spill in Firestone, near Colorado River Drive and Sunset Drive. Less than five barrels of oil, condensate and produced water spilled. Crews found impacts while removing a meter run and the associated piping.
- • KP KAUFFMAN COMPANY INC, reported Jan. 20 a historical flowline spill in Frederick, near Little Bell Drive and Copper Drive. More than five barrels of oil and produced water spilled. As part of a relocate agreement with the land developer, the contractor is removing an abandoned flowline and identified impacts.
Commerce City considers proposal to install 160 wells on fracking sites – Battle lines are being drawn again in Colorado over fracking. Extraction Oil & Gas is proposing expansion into Commerce City amid criticism from protestors concerned about the environment, health and safety. Protestors gathered in the lobby of Commerce City’s city hall Monday as city decision makers headed to a closed-door executive session meeting concerning fracking. “I don’t think you can put a price on the safety of our neighborhood,” resident Sean Cuevo said. Commerce City says Extraction Oil & Gas – a company well known in Broomfield – has proposed 160 wells on 6 pads across the northern suburb. Fears of soil and water contamination, fires and cancer have residents insisting their city council members find a way to say “no” to the development. But legally, it’s not so easy, officials warn. The city says it is still weeks away from any potential operating agreement. Council members are, for now, gaining legal advice from city attorneys. The city is attempting to create a focus group for resident feedback and is determining a negotiation strategy on fracking. “There is always room for that public comment period as this process continues to move forward,” said city spokeswoman Jodi Hardee. Organizations advocating for responsible energy development argue stopping development all together is the wrong way to go. Instead, finding a compromise of what works best is the answer. But, Commerce City residents like Cuevo say wells simply don’t belong within city boundaries. The city says, if an agreement does move forward, there will be a 21-day public comment period.
Investors question Anadarko on political risk to Colorado drilling – Executives from Anadarko Petroleum on Wednesday fielded a persistent line of questioning from institutional investors and analysts about the company’s oil and gas assets in Colorado’s DJ Basin, where community activists continue to pressure the state government for tougher regulations on the industry. On the company’s fourth-quarter earnings call, questioners pushed President and CEO Al Walker for his view on the risks that potential state regulations could pose to Anadarko’s Colorado assets. Although only a fraction of Anadarko’s production portfolio is located in Colorado, a regulatory change there could jeopardize nearly 4.1 Bcf/d in natural gas production and over 450,000 b/d in crude oil output that comes from the state’s Denver-Julesburg, Piceance, San Juan and Anadarko Basins. Walker was somewhat dismissive of investor and analyst concerns, saying that he sees Colorado as having a “constructive environment” relative to the company’s position there, and the industry would have to adopt a wait-and-see approach for now. Questions remain, though, about how the investment community might adjust their portfolio allocations with respect producers that operate in states with higher perceived political risk, like Colorado, with one investor even asking if Anadarko had any “big thoughts about restructuring.” In the November 2018 election, the resounding defeat of Proposition 112, which would have required that new drilling permits observe a 2,500-foot setback from occupied structures and vulnerable areas, was a notable victory for Colorado’s oil and gas industry. The November ballot measure, though, hasn’t marked an end to the nearly decade-long battle over the state’s oil and gas industry. In the battle over drilling along Colorado’s Front Range, which sits at the heart of the highly productive DJ Basin, that last salvo from community activists has come in the form of proposed regulation that could effectively ban drilling in the state. In December, a group of homeowners in Broomfield sued the state to end forced pooling–a practice that’s become essential to hydraulic fracturing, especially in locations with multiple mineral rights owners, like the DJ Basin. The case challenges the state constitutionality of pooling, which allows producers to organize multiple mineral rights holders into a single pool. As long as a certain percentage of the people in the pool agree to the terms of the lease, the project can move forward, even without unanimous consent.
Crew injured, diesel fuel spilled into river when train derails in remote Wyoming canyon — A coal train collision on Monday sent two locomotives partially into the North Platte River, potentially contaminating the waterway with thousands of gallons of diesel in a remote canyon north of the Guernsey Reservoir, according to state officials. Two of the company’s employees, an engineer and a conductor, suffered non-life threatening injuries from the incident, which involved one loaded coal train rear-ending another north of Wendover near Little Cottonwood Creek. The collision resulted in three derailed locomotives and four derailed cars, said Amy McBeth, a company spokeswoman. None of the spilled coal reached the river, but two of the derailed, diesel-fueled locomotives did. From engines that were flipped on their sides, as much as 6,000 gallons of diesel could have spilled, according to Joe Hunter, emergency response coordinator for the Wyoming Department of Environmental Quality. That’s a worst-case scenario,” Hunter said. “ I don’t have a good idea of how much went into the river, but it is a significant amount.” The collision happened in a remote area where the tracks skirt the southern edge of the North Platte as it passes through steep terrain. County officials headed to the scene Monday afternoon were unable to reach the actual derailment site because of the narrow canyon, said Terry Stevenson, emergency management coordinator for Platte County. BNSF transported the two injured employees out of the canyon via a company vehicle that can drive on train rails. Cleanup of the diesel in the river could be completed by the end of the week, according to Hunter, who said the agency and the company were exploring multiple remediation options. That work is currently being hampered by the location of the crash. The tracks and overturned locomotives lie at the base of a 300- to 400-foot cliff face, Hunter said.
Dakota Access criminal cases wrapping up in North Dakota (AP) – Hundreds of state-level criminal cases stemming from the prolonged protest in North Dakota against the Dakota Access oil pipeline are mostly wrapped up, and an organization of volunteer attorneys that formed to aid protesters is shifting its focus to other potential battles, including the Keystone XL pipeline and President Donald Trump’s southern border wall. “Whenever the next struggle heats up and takes off, then we will swell our ranks to meet the demand,” said Frances Madeson, spokeswoman for the Water Protector Legal Collective . “Water protector” is what many pipeline opponents called themselves because they fear a spill could contaminate water supplies. Thousands of Native Americans and others who feared environmental harm from the $3.8 billion pipeline built by Texas-based Energy Transfer Partners came to southern North Dakota in 2016 and 2017 to protest, resulting in hundreds of arrests over a six-month span and nearly 850 criminal cases in state court. The pipeline that ETP maintains is safe has been moving North Dakota oil to Illinois since June 2017. The nonprofit legal team, which formed in a tent at a protest camp, grew to 31 attorneys from around the country who donated tens of thousands of hours over the past 2 ½ years to help defendants in those cases, most of which have been dismissed or resolved through plea agreements.
Produced water spilled in Stark County – A produced water spill resulting from a tank overflow in Stark County has been reported to the North Dakota Department of Health. The tank is located on an oil pad owned by Scout Energy Management LLC. The incident occurred about 2 miles west of Dickinson on Sunday, and it was reported the next day. Initial estimates indicate about 450 barrels of produced water were released and impacted agricultural land. Health department personnel have inspected the site and will continue to monitor the investigation and remediation.
Leak spills 10,300 gallons of brine at Williams County well – A valve or piping connection leak is being blamed for a spill of nearly 10,300 gallons of saltwater at a well in Williams County. The state Oil and Gas Division says Oasis Petroleum North American LLC on Wednesday reported the spill of 245 barrels of brine at the well about 7 miles southeast of Williston. Brine, or saltwater, is a byproduct of oil production. The spill was contained on-site and was being cleaned up. A state inspector visited the site and is monitoring cleanup.
Company gets water permit for refinery near national park (AP) – A company facing opposition from environmentalists and landowners as it works to build an $800 million oil refinery near Theodore Roosevelt National Park in western North Dakota has cleared another hurdle by obtaining a state water permit, though the matter could still end up in state court.State Engineer Garland Erbele on Thursday followed the recent recommendation of an administrative law judge and issued a permit to Meridian Energy Group allowing the company to draw water from an underwater aquifer for the Davis Refinery, State Water Commission spokeswoman Jessie Wald said Monday.The agency was prepared to issue the permit last summer but three landowners challenged it, citing concerns over how they might be affected and how much of the water would be wasted. Landowner attorney JJ England also argued that Meridian’s plans for treating and using the water were vague and at times conflicting.Administrative Law Judge Tim Dawson held a hearing in November and issued his recommendation Jan. 8, concluding “there is no realistic harm to the public interest” should the permit be issued.England did not immediately respond to requests for comment on whether his clients will appeal. They have about a month to decide under state law.A separate challenge in state court by three environmental groups of the refinery’s state air quality permit recently failed. A state judge ruled in late January that the Health Department had effectively supported its position that the refinery will not be a major source of pollution that will negatively impact the park just 3 miles (5 kilometers) away.
SoCalGas asks customers to curb nat gas use during California cold snap – Sempra Energy’s (NYSE:SRE) SoCalGas urges customers to use less natural gas until further notice to avoid straining its system as colder weather covers its service area. Overnight temperatures in Los Angeles are expected to drop as low as 39 degrees F during Monday-Wednesday, ~10 degrees below normal at this time of year, before rising to near normal levels later in the week. Gas supplies have been tight in Southern California this winter because of limitations on several SoCalGas pipelines and reduced availability of the Aliso Canyon storage field following a massive leak three years ago. The utility says it has been pulling gas from Aliso to avoid removing too much fuel form its other storage facilities.
Oil Pipeline Firm Tells Investors Spills Happen – A federal judge in Houston was correct to call pipeline spills unremarkable and investors should take them as no surprise either, an attorney for a pipeline company told a Fifth Circuit panel Wednesday. “It is not an industry that you’re not going to have spills, or leaks in, and in fact, Plains makes that very clear in their filings,” attorney Michael Holmes, a partner in shareholder litigation and enforcement at Vinson & Elkins in Dallas, told the three-judge panel. A class of retirement funds led by IAM National Pension Fund appealed a Houston federal judge’s dismissal of the securities portion of their lawsuit against Plains All American Pipeline LP after a California jury last year found the company guilty of criminally negligent conduct for a May 2015 pipeline rupture that sent tens of thousands of gallons of oil into the Pacific Ocean. The securities lawsuit alleged the pipeline company “falsely claimed to have a comprehensive, effective environmental and regulatory compliance program to prevent oil spills” and said the company “repeatedly violated regulatory mandates” all the while having a compliance program that “was close to non-existent.” U.S. Circuit Leslie H. Southwick, an appointee of George W. Bush, appeared skeptical Wednesday during Holmes’ arguments about the inevitability of spills. “I don’t think that’s what Judge Rosenthal had in mind,” Southwick said, referring to U.S. District Judge Lee Rosenthal’s dismissal of the securities violations claims. “There is no recklessness here,” Holmes said. “I think that’s how Judge Rosenthal was looking at it.” Holmes went on to say that in looking at a shareholder contract with a pipeline, the investor can’t simply interpret the terms as they wish because the statements in such contracts are actually for underwriters. Judge Southwick still appeared unconvinced. Holmes continued, “It isn’t that there aren’t any regulatory violations” made by Plains All American, but “there are no regulatory violations that could be reasonably expected to lead to a material adverse effect.”
Pipeline work destroyed salmon habitat, puts orcas at risk, scientists say – Shoddy work on a section of the Trans Mountain pipeline in Chilliwack, British Columbia has “degraded” a local coho and chum salmon habitat, says a BC-based biologist with more than 30 years’ experience. The biologist, Mike Pearson, says the work is a warning sign of what might happen with future pipeline developments, and could have greater downstream impacts on other wildlife, such as orcas, if Trans Mountain adopts similar methods for other stream systems. Pearson undertook an assessment of Stewart Creek in December 2018 and filed it to the National Energy Board (NEB) later that month. The report found that the fix (placing concrete blocks and crushed gravel on top of a exposed pipe) made the stream unsuitable for salmon. The smooth concrete blocks meant most of the gravel was washed away just months after it was added, leaving no places for salmon to hide or bury their eggs, or for the salmon’s food source (aquatic invertebrates) to grow. “No consideration is given to restoring or mitigating impacts on habitat,” Pearson told me over the phone, adding that he’s seen a lack of consideration for wildlife habitats at other Trans Mountain project sites as well. He says the site is highly visible to the public and logistically simple compared to other stream systems, so there was no excuse for not getting it right. “If under those circumstances sufficient care isn’t going to be taken…then I’m concerned,” Pearson told Motherboard. Pearson says that salmon populations, and the orcas that rely on them as as a food source, could be at risk in the future if other streams receive the same treatment if the pipeline expansion gets the go-ahead.
US Military Fuel Tanks Threaten Aquifer In Hawaii – The North Korean missile scare in Hawaii a year ago was alarming. But that fear has abated. Once again the greatest perceived threat to the island of Oahu comes from our own U.S. military. A massive complex of 20 U.S. military storage tanks is buried in a bluff called Red Hill that overlooks Honolulu’s primary drinking water supply, 100 feet below. The walls on the 75-year-old jet fuel tanks are now so thin that the edge of a dime is thicker. Each of the underground tanks holds 12.5 million gallons of jet fuel; 225,000,000 gallons in total. In 2014, 27,000 gallons of jet fuel leaked through a weak spot on a tank that had been repaired with a welded patch. The welding gave way and the fuel entered the the water supply. An Ohau beach. Drinking water is currently safe to drink, but traces of petroleum chemicals are being detected in the groundwater near the tanks. Leaks have been going on for years. Studies have documented them since 1947. The continued corrosion of the tank liners constantly risks a catastrophic fuel release. Concerned citizens on the island have for decades been trying to get the U.S. Navy to remove the tanks. The military’s position is that the fuel tanks are of strategic importance to U.S. national security and are being maintained as well as 75-year old tanks can be.
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