Written by rjs, MarketWatch 666
Here are some selected news articles from the week ended 12 May 2019.
This article is a feature every Monday evening on GEI.
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Unprecedented natural gas restocking continues; US gasoline imports at a 6 year high; rig count at a 14 month low
Oil prices ended lower for the third week in a row, as a resumption of the trade war between the US and China cast a pall over the markets and overshadowed the impact of tightening global supplies stemming from US sanctions on Iranian and Venezuelan oil exports…after falling 2.2% to $61.94 a barrel on a big build in US oil supplies last week, contract prices of US crude for June delivery initially crashed to a one month low of $60.04 a barrel on Monday morning, after Trump reignited the trade war by tweeting that tariffs on $200 billion of Chinese goods would jump from 10 to 25 percent on Friday, but rebounded later in the day and settled 31 cents higher at $62.25 per barrel after the US deployed an aircraft carrier strike group and a bomber task force to the Middle East to confront Iran…however, oil prices tumbled again on Tuesday, as the US-China trade war intensified and stoked concerns over global growth, with crude prices falling 85 cents or 1.4% to a 5-week low of $61.40….nonetheless, oil prices popped right back up on Wednesday after the EIA reported a surprise draw from US supplies and went on to finish 1.2% higher at $62.12, even as escalating U.S.-Chinese trade tensions limited oil’s gains…however, oil prices fell on the trade dispute again on Thursday, despite falling inventories, tumbling to as low as $60.92 a barrel before steadying near the close to end down 41 cents at $61.70 a barrel…oil prices were then little changed on Friday, closing down 4 cents at $61.66 a barrel, even as Trump ‘s tariff hike on Chinese goods took effect and kept tensions high between the world’s two largest economies…hence, for the week oil prices ended down just 28 cents, or less than half a percent, as tight supply factors offset the impact of the renewed US-China trade dispute..
Natural gas prices, meanwhile, trended somewhat higher, with the contract for June delivery of natural gas rising 5.2 cents over the week to finish at $2.619 per mmBTU, as both the 6 to 10 day outlook and the 8 to 14 day outlook from the Climate Prediction Center continued to indicate building warmth in the Southeast and colder than normal in the Intermountain West and northern tier, which would suggest greater air conditioning demand in the former and more heating demand in the later…however, despite just such a temperature setup over the prior week, which you can see on the map of temperature anomalies for week ending May 2nd below, the injection of surplus natural gas into storage was still well above normal for this time of year…
(source)
The natural gas storage report for the week ending May 3rd from the EIA indicated that the quantity of natural gas held in storage in the US increased 85 billion cubic feet to 1,547 billion cubic feet by the end of the week, which meant our gas supplies were 128 billion cubic feet, or 9.0% more than the 1,419 billion cubic feet that were in storage on May 4th of last year, while still 303 billion cubic feet, or 16.4% below the five-year average of 1,850 billion cubic feet of natural gas that have typically been in storage as of the first weekend in May in recent years….this week’s 85 billion cubic feet injection into US natural gas storage was close to the median estimate of a 87 billion cubic foot increase indicated by a Bloomberg survey of analysts, while it was somewhat more than the 72 billion cubic feet of natural gas that are normally added to gas storage during the same week of spring….this was the eighth week in a row that we’ve either seen injections above normal or withdrawals below normal, and concludes a 4 week period where the injections into storage have averaged just under one hundred billion cubic feet per week, unprecedented for this time, or really for any time of year…moreover, the early June weather outlook appears to show it will be a colder than normal period nationally, delaying the onset of air conditioning electric consumption, suggesting that the 100 billion cubic foot injection pace might continue well into the next month…
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 May 3rd, showed that due to a drop in our oil imports and a major shift from unaccounted for crude supply to unaccounted for demand, we had to withdraw oil from our commercial supplies of crude for the second time in seven weeks…our imports of crude oil fell by an average of 721,000 barrels per day to an average of 6,693,000 barrels per day, after rising by an average of 1,325,000 barrels per day over the prior two weeks, while our exports of crude oil fell by an average of 289,000 barrels per day to 2,322,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 4,371,000 barrels of per day during the week ending May 3rd, 432,000 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 reported to be down by 100,000 barrels per day to 12,200,000 barrels per day, so our daily supply of oil from the net of our trade in oil and from well production totaled an average of 16,571,000 barrels per day during this reporting week…
Meanwhile, US oil refineries were using 16,405,000 barrels of crude per day during the week ending May 3rd, 41,000 fewer barrels per day than the amount of oil they used during the prior week, while over the same period the EIA reported that 690,000 barrels of oil per day were being withdrawn from oil storage in the US….therefore, this week’s crude oil figures from the EIA would seem to indicate that our total working supply of oil from net imports, from oilfield production, and from storage was 856,000 barrels per day more than what the oil 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 (-856,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a fudge factor that is labeled in their footnotes as “unaccounted for crude oil”….with a switch in the unaccounted oil figure from +685,000 last week to -856,000 this week, we have to figure that both weeks’ crude oil metrics are in error by statistically significant amounts, and that week over week comparisons are essentially meaningless… (for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….
Further details from the weekly Petroleum Status Report (pdf) indicated that the 4 week average of our oil imports still rose to an average of 6,812,000 barrels per day last week, 15.6% less than the 8,068,000 barrel per day average that we were importing over the same four-week period last year…the 690,000 barrel per day decrease in our total crude inventories included 566,000 barrels per day that were withdrawn from our commercially available stocks of crude oil, and a 124,000 barrel per day withdrawal from the oil stored in our Strategic Petroleum Reserve, part of a release from the reserves intended to blunt the Gulf crude shortage resulting from the Venezuelan oil export sanctions…this week’s crude oil production was reported to be 100,000 barrels per day lower at 12,200,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was 100,000 barrels per day lower at 11,700,000 barrels per day, while a 1,000 barrel per day decrease to 476,000 barrels per day in Alaska’s oil production was not enough to impact the final rounded national total…last year’s US crude oil production for the week ending May 4th was at 10,703,000 barrels per day, so this reporting week’s rounded oil production figure was 14.0% above that of a year ago, and 44.8% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016…
Meanwhile, US oil refineries were operating at 88.9% of their capacity in using 16,405,000 barrels of crude per day during the week ending May 3rd, down from 89.2% of capacity the prior week, and below the historical refinery utilization rate for this time of year….similarly, the 16,405,000 barrels per day of oil that were refined this week were still a bit less than the 16,486,000 barrels of crude per day that were being processed during the week ending May 4th, 2018, when US refineries were operating at 90.4% of capacity…
Even with the decrease in the amount of oil being refined, gasoline output from our refineries was still somewhat higher, increasing by 202,000 barrels per day to 10,129,000 barrels per day during the week ending May 3rd, after our refineries’ gasoline output had increased by 146,000 barrels per day the prior week….with that increase in gasoline output, this week’s gasoline production was finally 1.5% more than the 9,974,000 barrels of gasoline that were being produced daily during the same week last year….at the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) fell by 39,000 barrels per day to 5,089,000 barrels per day, after that distillates output had increased by 64,000 barrels per day the prior week…but even after this week’s decrease, the week’s distillates production was 1.9% more than the 4,993,000 barrels of distillates per day that were being produced during the week ending May 4th, 2018….
Even with the increase in our gasoline production, the supply of gasoline in storage at the end of the week fell for the eleventh time in 12 weeks, decreasing by 596,000 barrels to 226,147,000 barrels over the week to May 3rd, after gasoline supplies had fallen by 917,000 barrels over the prior week….our gasoline supplies fell because the amount of gasoline supplied to US markets increased by 643,000 barrels per day to 9,871,000 barrels per day, after decreasing by 181,000 barrels per day the prior week, while our imports of gasoline rose by 344,000 barrels per day to a 70 month high of 1,114,000 barrels per day, and while our exports of gasoline fell by 197,000 barrels per day to 491,000 barrels per day….after having reached an all time record high fifteen weeks ago, our gasoline supplies are now 4.1% lower than last May 4th’s inventory level of 235,804,000 barrels, and remain roughly 2% below the five year average of our gasoline supplies at this time of the year…
With the decrease in our distillates production, our supplies of distillate fuels fell for the 25th time in thirty-two weeks, decreasing by 159,000 barrels to 125,563,000 barrels during the week ending May 3rd, after our distillates supplies had decreased by 1,307,000 barrels over the prior week…the draw on our distillates supplies was much smaller this week because the amount of distillates supplied to US markets, a proxy for our domestic demand, fell by 319,000 barrels per day to 3,896,000 barrels per day, and because our imports of distillates rose by 48,000 barrels per day to 111,000 barrels per day, while our exports of distillates rose by 164,000 barrels per day to 1,327,000 barrels per day…but even after this week’s inventory decrease, our distillate supplies were still 9.1% higher than the 115,038,000 barrels of distillate that we had stored on May 4th, 2018, even as they remain roughly 5% below the five year average of distillates stocks for this time of the year…
Finally, with lower oil production and falling oil imports, our commercial supplies of crude oil in storage decreased for the fifth time in 16 weeks, falling by 3,963,000 barrels over the week, from 470,567,000 barrels on April 26th to 466,604,000 barrels on May 3rd….that still left our crude oil inventories near the recent five-year average of crude oil supplies for this time of year, while they also remained about a third higher than the prior 5 year (2009 – 2013) average of crude oil stocks as of the first weekend in May, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first rose above 400 million barrels…since our crude oil inventories have generally been rising since this past Fall, after generally falling until then through most of the prior year and a half, our oil supplies as of May 3rd were 7.6% above the 433,758,000 barrels of oil we had stored on May 4th of 2018, but at the same time still 10.7% below the 522,525,000 barrels of oil that we had in storage on May 5th of 2017, and 8.2% below the 508,487,000 barrels of oil we had stored on May 6th of 2016…
This Week’s Rig Count
The US rig count was down again this past week and hence fell to a 14 month low in continuing the recent slide that has seen drilling rig activity decrease eleven out of the last 12 weeks…..Baker Hughes reported that the total count of rotary rigs running in the US fell by 2 rigs to 988 rigs over the week ending May 10th, which was also down by 57 rigs from the 1045 rigs that were in use as of the May 11th report of 2018, and quite a bit below the shale era high of 1929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC announced their attempt to flood the global oil market…
The count of rigs drilling for oil fell by 2 rigs to 805 rigs this week, which was also 39 fewer oil rigs than were running a year ago, and barely half of 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 was unchanged at 183 natural gas rigs, which was still down by 16 rigs from the 199 natural gas rigs that were drilling a year ago, and way down from the modern era high of 1,606 natural gas targeting rigs that were deployed on August 29th, 2008…
Drilling activity offshore in the Gulf of Mexico was unchanged at 20 rigs this week, which was the same number of rigs that were active in the Gulf a year ago…the number of active horizontal drilling rigs was down by 1 to 872 horizontal rigs this week, which was also 46 fewer horizontal rigs than the 918 horizontal rigs that were in use in the US on May 11th of last year, and well down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014…..in addition, the vertical rig count was also down by 1 rig to 45 vertical rigs this week, which was also down from the 55 vertical rigs that were in use during the same week of last year….meanwhile, the directional rig count was unchanged at 71 directional rigs this week, which was still down by 1 from the 72 directional rigs that were operating on May 11th 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 oil & gas 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 May 10th, the second column shows the change in the number of working rigs between last week’s count (May 3rd) and this week’s (May 10th) count, the third column shows last week’s May 3rd active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running before the equivalent weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 11th of May, 2018…
This week’s major oil rig decrease was in New Mexico, and it appear that 3 of the 4 rigs that were shut down in the state had been operating in the Permian, because two Permian rigs were added in Texas, one each in Texas Oil District 7C, or the southern Permian Midland basin, and in Texas Oil District 8A, or the northern Permian Midland basin…the three rigs that were added in California were also likely targeting oil, since the natural gas rig count elsewhere balances, although we can’t be sure without digging through the North America Rotary Rig Count Pivot Table (xls), which lists the details on each rig deployment individually…for rigs targeting natural gas, two were added in Pennsylvania’s Marcellus, while Pennsylvania saw a natural gas rig pulled out of the Utica shale at the same time….the national natural gas rig count remained unchanged, however, because the Denver-Julesburg Niobrara chalk had a natural gas rig that had been operating in Wyoming pulled out at the same time, and all rigs remaining in the Niobrara are now drilling for oil…we should also note that in addition to the rig changes for major producing states shown above, Alabama drillers added a rig and are now operating two, also an increase from the single rig they had deployed a year ago, while Mississippi saw two rigs shut down and has two still drilling, which is down from the 3 rigs that were running in Mississippi a year ago…
Closing nuclear plants will spike pollution, regulator says | Toledo Blade — The new chairman of the Public Utilities Commission of Ohio on Tuesday told lawmakers there’s little doubt carbon pollution in the state will spike if the state’s two nuclear power plants are decommissioned. “You would have most likely a flare-up of natural gas generation technology, because that’s technology that can be built quickly,” Chairman Sam Randazzo said. “It’s the most nimble.” A former lobbyist who represented major industrial users on utility issues, Mr. Randazzo stressed he wasn’t speaking on behalf of the commission, which decides what costs utilities can pass on to their customers. The House Energy and Natural Resources Committee is considering House Bill 6, which, when fully implemented, would create an annual pot of more than $300 million, fueled by surcharges on customers’ bills. The proceeds would be used to reward the generation of electricity that emits no or less carbon dioxide into the atmosphere. The state’s two nuclear plants on the shore of Lake Erie – Davis-Besse about 30 miles east of Toledo and Perry about 40 miles east of Cleveland – are expected to qualify for at least half of that pot. At the same time, the bill would do away with existing mandates that utilities find increasingly more of their power from renewable sources like wind and solar and reduce energy consumption overall. Critics characterize it as a consumer bailout for the nuclear plants, which have been unable to compete with cheaper and abundant natural gas. Their owner, FirstEnergy Solutions, is in bankruptcy proceedings and has said it will close both if they don’t find a buyer or some market for their more expensive power. Davis-Besse, the largest employer in Ottawa County, would stop generating power no later than May 31, 2020.
Conservatives criticize FirstEnergy nuclear bailout bill as ‘corporate welfare’ – Ohio Republicans pushing a bill to subsidize two nuclear plants are finding themselves at odds with conservative groups in the state. Substitute House Bill 6, which was advanced out of a subcommittee on May 2, would add more than $300 million to customer bills across the state once all its provisions kick in, with the lion’s share going to subsidize FirstEnergy Solutions’ Davis-Besse and Perry nuclear power plants. Other energy suppliers could also get some of those funds, including certain coal plants. A committee hearing is scheduled for 9 a.m. Tuesday, May 7. Both the Buckeye Institute and Americans for Prosperity’s Ohio chapter were among dozens of parties who offered testimony to the committee late last month along with clean energy groups, consumer advocates and other opponents. “[I]n the plain-spoken language most Ohioans prefer to use, HB 6 is corporate welfare,” said Micah Derry, Ohio state director of Americans for Prosperity. “It is cronyism on full display; in other words, a bailout.” Likewise, research fellow Greg Lawson of the Buckeye Institute called HB 6’s provisions “classic examples of government subsidies being used to prop up declining businesses – the Davis-Besse and Perry nuclear power plants operated by FirstEnergy Solutions.” And while there would be some funds that could be drawn upon by other entities, those monies risk “becoming a glorified slush fund with the real incentive being for companies to find new and creative ways to tap into that fund,” rather than risking their own capital, he added. Lawson told the Energy News Network that his organization’s opposition differs from that of environmental groups, clean energy companies or other competitors, saying that other organizations have largely focused on how the bill would affect them. “The Buckeye Institute opposes the idea of taxpayer subsidies irrespective of who benefits from being handed taxpayer dollars to support their business, and we are consistent on this point,” Lawson said.
EQT fined $330K for erosion violations in Allegheny County | StateImpact Pennsylvania – Natural gas driller EQT was fined $330,000 by the Pennsylvania Department of Environmental Protection for erosion violations at two natural gas sites in Allegheny County.The agency said sediment from two well pads in Forward Township was eroding into a tributary to Kelly Run, which flows into the Monongahela River.The problems were first spotted by a DEP inspection in February 2018, when inspectors found “sediment laden waters” were flowing over erosion control barriers at the Fetchen and Prentice well pad sites. The agency found the company built a road at the Prentice site without first getting a state permit to do so. The company was also cited for not informing the DEP of its erosion problems, which it is required to do by the conditions of its state-issued erosion control permits. The erosion problems continued until EQT corrected them in May 2018 at the Prentice site and November 2018 at the Fetchen site.“DEP expects all permittees – particularly large, longtime operators – to construct facilities and report problems in accordance with state regulations and permit conditions, but these failures demonstrate the importance of verifying compliance and enforcing the regulations,” said DEP Deputy Secretary for Oil and Gas Management Scott Perry, in a statement. EQT spokeswoman Linda Robertson said in a statement the company “takes environmental compliance seriously” but blamed abnormally wet weather on some of the companies erosion problems. Despite the company’s efforts, “EQT did not keep up with the continually changing weather and precipitation. In fact, Pennsylvania experienced unprecedented rainfall in February 2018, which resulted in challenging (erosion) conditions.” Last year was the wettest on record in the Pittsburgh region.
State conducting criminal investigation of shale gas production – State Attorney General Josh Shapiro is pursuing criminal investigations of “environmental crimes” committed by the oil and gas industry in Washington County and possibly throughout the state.In an Aug. 16, 2018, letter to attorneys in a civil case before the Washington County Court of Common Pleas, Mr. Shapiro and his office said they already had accepted a referral and “assumed jurisdiction over several criminal investigations involving environmental crimes in Washington County.”By that time Washington County District Attorney Eugene Vittone already had discussed with and referred claims of environmental problems in shale gas development to the attorney general’s office. Three Washington County residents told the Post-Gazette that they have spoken with AG investigators and were told they could be called to testify, with a Washington County woman saying that she already presented testimony before an investigative state grand jury in Pittsburgh. Joe Grace, spokesman for Mr. Shapiro and the state Office of Attorney General, said, “We cannot confirm or deny the existence of an investigation.”The AG’s letter was introduced as an exhibit during an August court hearing on the civil case brought by Stacey Haney in 2012 against Range Resources Appalachia LLC, and specially referenced as the “Stacey Haney/Range Resources Investigation.”“It has come to our attention that one of the potential criminal investigations involves your respective clients,” said the two-paragraph letter signed by Courtney Butterfield, deputy attorney general and obtained recently by the Pittsburgh Post-Gazette from someone not involved in the case. The letter noted that a significant record of documents, statements, depositions, scientific tests and physical evidence had been compiled for the civil case. It requested that attorneys preserve that record, under penalty of law if they failed to do so.
DEP approves Adelphia compressor station in West Rockhill – At least one local environmental says the April 19 approval seemed to come out of nowhere, leaving little time for it and others to appeal.A proposed natural gas compressor station in West Rockhill might be moving forward after state approval last month, a decision that seemingly came out of nowhere for at least one local group.The state Department of Environmental Protection approved plans for a controversial compressor station on April 19 as part of a proposed Adelphia Gateway LLC pipeline through the area, a legal notice in the Pennsylvania Bulletin states.Bucks County Concerned Citizens Against the Pipeline organizer Arianne Elinich said neither her group nor area residents knew the approval was coming, giving little time to prepare an appeal.Adelphia is currently seeking Federal Energy Regulatory Commission approval for a natural gas pipeline through Northampton, Bucks, Montgomery, Chester and Delaware counties in Pennsylvania and New Castle County in Delaware. Commonly known as the Quakertown Compressor station, Adelphia proposes a 5,625-horsepower compressor station in an 8,000- to 10,000-square-foot building at a 1.5-acre site on Rich Hill Road, near the border of West Rockhill and Richland.
Chester county state representative faces backlash for bringing Nazis into pipeline debate – A Southeastern Pennsylvania lawmaker who opposes the Mariner East 2 pipeline is being criticized by unions that represent pipeline workers, and others, for a tweet one fellow House member called a “poor choice of words.”At the center of the discord was a freshmen Democratic representative and a tweet about Nazis.On Saturday, Chester County Democrat Danielle Friel Otten got in a Twitter exchange with a pro-pipeline group.She’d been supporting protesters who were using cars to block pipeline work – a reaction to Sunoco, the pipeline developer, buying nearby homes that have been affected by construction-induced sinkholes over the last few years.Friel Otten lives near those homes and was elected, in large part, based on apledge to oppose the Mariner East 2. She said she didn’t organize the protest, but that once she found out it was happening near her house, it was “really important to me to have the backs of my constituents and my neighbors, and to welcome them to sit on my patio.” During the protest, the Pennsylvania Energy Infrastructure Alliance tweeted that protesters were preventing workers from doing their jobs. In a now-deleted tweet, Friel Otten responded that “The Nazis were just doing their jobs too,” and linkeda PBS article on coercion by people in power. “What I meant by that, is that this excuse of people just doing their jobs to validate harming people is not an acceptable argument,” she said. Backlash was quick. Fellow Southeastern Democrat David heads the region’s Teamsters Union. He said he has received a lot of calls from members upset with his colleague. “It’s a poor choice of words,” the Delaware County Representative said. “It’s not a fair comparison. I mean these are working folk, these are salt-of-the-earth people.” “The word that was used is a highly offensive word, and the fact that she is a state legislator, a Democrat no less, to use that kind of language so flippantly and to not even issue some type of an apology just blows my mind.”
Dominion CEO says will take Atlantic Coast Pipeline fight to Supreme Court — Dominion Energy, fighting to resume construction on the $7.8B Atlantic Coast Pipeline, plans to take its case all the way to the U.S. Supreme Court, CEO Tom Farrell says.The regulatory process has been “very frustrating” but the company will not back down from the project as planned, which would pump fracked natural gas from West Virginia through Virginia and into North Carolina, Farrell says.But environmentalists – represented in court by the Southern Environmental Law Center – also say they will not back down, but SELC attorney Greg Buppert notes the Supreme Court takes less than 1% of cases presented to it and typically hears cases involving constitutional issues or conflicts between lower courts.”Neither of those issues are present here… So I think Dominion has a very steep hill to climb,” Buppert says. “From a reasonableness standpoint, it never made sense to build an interstate gas pipeline through two national forests, a national park and some of the steepest mountains in Virginia and West Virginia,” Buppert says. “The company has stubbornly stuck to that route,” adding that its problems “are entirely self-inflicted.”
Atlantic Coast Pipeline defends U.S. Fish and Wildlife permit under scrutiny – The U.S. Fish and Wildlife Service defended a permit issued to allow work on the Atlantic Coast Pipeline. The Charleston Gazette-Mail said that environmental lawyers argued that the building of the pipeline could endanger the Rusty Patched Bumble Bee, an endangered mussel known as the Clubshell, the Indiana Bat and a threatened crustacean called the Madison Cave Isopod. D.J. Gerken, attorney at the Southern Environmental Law Center, told judges on the 4th Circuit Court of Appeals in Richmond on Thursday that Fish and Wildlife had ignored information indicating that there was a threat to these species. An Incidental Take Statement from Fish and Wildlife was vacated by judges in May of 2018, ruling that the permit was too vague. A permit from the National Park Service was also vacated, and a stop-work order was put in place by the Federal Energy Regulatory Commission, The Charleston Gazette-Mail reports. The Incidental Take Statement that is being contested now is the second issued by Fish and Wildlife, and was released in a revised Biological Opinion in September of 2018. The most recent Biological Opinion from Fish and Wildlife, which included an Incidental Take Statement, along with a new permit from the National Park Service, led to FERC lifting the stop-work order, The Charleston Gazette-Mail reports. The Charleston Gazette-Mail reports that Virginia Department of Conservation and Recreation informed Fish and Wildlife that there were Rusty Patched Bumble Bee populations near the project, and the SELC has argued that the appropriate amount of research has not been done to understand what could happen to the bee population if the project goes through the area. Fish and Wildlife consulted an expert concerning the bees, but Judge Stephanie Thacker disputed the opinion, because the expert had said that all she had was a “wild guess.”
Feds warn companies on landslide hazards – Federal regulators are reminding pipeline companies of the dangers posed by erosion and landslides. The Pipeline and Hazardous Materials Safety Administration (PHMSA) has issued an “advisory bulletin” about the hazards, which have been dogging pipeline builders and operators as they try to move natural gas and other products through the mountainous Appalachian region. Landslides, subsidence, floods and other geological hazards can bend pipelines beyond the breaking point, causing ruptures, spills and explosions. “Owners and operators of gas and hazardous liquid pipelines are reminded that earth movement, particularly in variable, steep, and rugged terrain and with varied geological subsurface conditions, can pose a threat to the integrity of a pipeline if those threats are not mitigated,” Among other measures, the bulletin suggests monitoring lines with strain gauges, which measure movement of the pipes. PHMSA could use the bulletin to strengthen its case in future enforcement actions if geologic hazards such as landslides cause explosions or other accidents. The bulletin could make such an action less vulnerable to appeal by establishing that pipeline operators should be aware of the hazards and rules. Pipeline industry representatives say they already have detailed, established methods to avoid damage to their lines from landslides and other movement. Pipelines in Appalachia have been plagued in the past year by landslides and other problems resulting from land movement. The landslides have often been linked to unusually heavy rains. Heavy rains have also caused problems for construction of the Atlantic Coast and Mountain Valley pipelines through Virginia and West Virginia (E&E News PM, Dec. 7, 2018). The notice cited seven explosions and spills as “notable.” Most were in Appalachia, such as a Jan. 29 rupture near Lumberport, W.Va., caused when a landslide moved an Equitrans Midstream Corp. pipeline about 10 feet. But it also cited a 2016 spill in North Dakota caused by a landslide and a 2016 explosion on a 22-inch gas transmission line in Montecito, Calif., as the region battled flooding and mudslides. It does not mention a January explosion in southeastern Ohio linked to land movement. The explosion on the 30-inch Texas Eastern Transmission pipeline injured two people and damaged two homes (Energywire, April 3). But it does refer to another explosion a year earlier 5 miles away on a different pipeline, the Rockies Express.
Crews clean up roughly 75-125 gallons of fuel from spill – (WWBT) – The Virginia Department of Environmental Quality (DEQ) estimates 75-125 gallons of number 2 fuel oil spilled throughout a Lakeside neighborhood Sunday. Henrico County Fire crews responded to Cedar Croft Street just before noon Sunday for a report of oil in the waterway. Hazmat crews were able to contain the spill that had already traveled 0.8 miles along the ditch into a nearby creek. “We received a statewide alert regarding the fuel spill,” said Steve Tubman with Virginia DEQ. More than 24 hours after the spill there was still a faint odor in the air, but crews with First Call Environmental were there all day Monday cleaning up the mess. “It started where the new fence is, and it runs the length of the ditch,” Tubman said. “It then goes underground for several feet and comes back out into a spring fed creek.” At this point how the spill happened remains under investigation, however, originally fire officials said a contractor accidentally leaked fuel in a ditch. “At this point we don’t have that information,” Tubman said. The roughly 75-125 gallons of fuel spilled is a type of fuel used to heat homes. Neighbors said many of the houses in the area have these oil tanks in their basement, but most aren’t used anymore. In an effort to clean up the spill, crews excavated the ditch; removing any soil that may have soaked up the fuel. Booms were also used and will remain in the neighborhood.
Potential gas pipeline expansion to run adjacent to Haw River – Residents of Alamance County have been working hard to fight against a potential pipeline extension that would run through much of their land and propose a threat to the environment around them. The extension of Mountain Valley Pipeline “Southgate” is set to be decided by 2020. Until then, community activism is set to continue.MVP proposed its “Southgate” project in May 2018, an extension of the preexistingMVP pipeline that currently spans 73 miles from southern Virginia to central North Carolina.The 73-mile extension would expand into southern Virginia and cross into central North Carolina in Rockingham County and end in Alamance County.The pipeline will transport vast amounts of natural gas supply from the Marcellus and Utica shale production (located in New York, Pennsylvania, Ohio and West Virginia) to markets in the mid- and south-Atlantic regions of the United States, according to MVP. Much of community concern derives from the notion that the pipeline extension would be a gas-fracking system. Caroline Hansley, an organizer for the Sierra Club – the largest environmental organization in the country with more than 3.5 million members – said the pipeline “is a high-pressure fracked-gas pipeline.” But, MVP Southgate does not mention anything about a gas-fracking system. “This is an interstate natural gas transmission line, and it does not involve any natural gas production in Virginia or North Carolina,” said Shawn Day, MVP’s media representative. The 24-by-16-inch pipeline is designed to transport 375 million cubic feet of natural gas per day to the Public Service Company of North Carolina Energy (PSNC) now known as Dominion Energy to customers as well as to new and existing markets in southern Virginia and central North Carolina. Before any construction begins, MVP must obtain necessary regulatory authorizations from the Federal Energy Regulatory Commission (FERC). The MVP Southgate team will also seek review from other federal, state and local agencies.
Williams Receives FERC Certificate Authorizing Northeast Supply Enhancement Project – Williams today reported that the Federal Energy Regulatory Commission (FERC) has issued a certificate of public convenience and necessity authorizing the Northeast Supply Enhancement project – an expansion of the existing Transco natural gas pipeline designed to serve New York markets in time for the 2020/2021 winter heating season. The Northeast Supply Enhancement project will provide 400,000 dekatherms per day of additional natural gas supply to National Grid – the largest distributor of natural gas in the northeastern United States. National Grid is converting about 8,000 customers per year from heating oil to natural gas in New York City and Long Island. The Northeast Supply Enhancement Project is critical to make these conversions possible, as well as keep up with new development in the area. “NESE will provide access to critical supply to serve our customers in New York City and on Long Island, ensuring there is enough natural gas for them to heat their homes and run their businesses,” said National Grid New York President John Bruckner. “This project aligns with our 80×50 pathway to reduce greenhouse gas emissions and supports City and State clean energy goals, while improving safety, reliability, resiliency and maintaining affordability and customer choice.” The Order issued by the Commission concludes a nearly three-year regulatory review process, ultimately determining that the Northeast Supply Enhancement project will serve the public interest and that environmental impacts would be minimized with the implementation of mitigation measures proposed by the company and FERC. Following the receipt of all necessary regulatory approvals, Williams anticipates beginning construction on the Northeast Supply Enhancement project facilities in the fall of 2019.
Landmark FERC pipeline challenge fails — An appellate court today tossed a lawsuit targeting a federal plan to significantly narrow climate analyses for natural gas infrastructure. During oral arguments last month, judges for the U.S. Court of Appeals for the District of Columbia Circuit seemed skeptical of the Federal Energy Regulatory Commission’s defense of its drastic climate policy shift (Energywire, April 12). But the case failed on the question of whether the plaintiff in the case, the small New York environmental nonprofit Otsego 2000, had standing to bring the challenge. “Otsego’s affidavits do not identify any injury other than the organization’s expenditure of time and money related to this litigation,” the court wrote in a short order today. The lawsuit was born from FERC’s refusal last year to rehear a challenge to Dominion Energy Transmission Inc.’s New Market Project, a set of gas infrastructure upgrades in upstate New York. FERC’s Republican majority used the procedural document to announce a seismic shift in its approach to analyzing and disclosing upstream and downstream greenhouse gas emissions from the projects the agency authorizes. Democratic Commissioners Cheryl LaFleur and Richard Glick penned pointed dissents, and Glick made a rare appearance at oral arguments in the case. During the hearing, the judges – Clinton appointees Merrick Garland and David Tatel and Obama pick Robert Wilkins – asked counsel for Otsego 2000 to defend the group’s standing. Legal experts who attended arguments noted FERC’s placement of its policy change inside proceedings for a low-profile project was likely a strategic move.
Reps Overseeing Pipeline Safety are Profiting From Pipeline Companies — Fossil fuel pipeline safety standards are set by the Pipeline and Hazardous Materials Safety Administration (PHMSA), which states that its mission is to “protect people and the environment by advancing the safe transportation of energy.” Since 2011, PHSMA has left open several rulemaking procedures to establish safety standards for natural gas pipelines, but it has so far failed to conclude any of them. While these rules sit in limbo, there have been several fatal gas pipeline incidents, including at least three in 2018 – the Columbia Gas explosion in Massachusetts, an explosion in Texas that was caused by a leaking gas gathering pipeline, and an explosion of an Atmos pipeline, also in Texas.. It is estimated that there are now at least 439,000 miles of unregulated natural gas pipeline in the U.S. The lack of regulation means that pipeline companies are rarely penalized when their lines explode and cause property damage, injuries, or deaths. “[PHMSA uses] a figure of about $9-10 million as the benefit of a human life,” Weimer said. “So if you have a tragedy like San Bruno that kills 8 people and you go through a cost-benefit to look at installing new valves on pipelines, and you say that over the course of 10 years you’re going to prevent 10 lives from being lost, that would be worth about $100 million. At the same time if you look at what the cost would be for the industry to put a valve on every mile of pipeline that might be required…the cost of implementing automated valves way outweighs the benefit of the human lives you’re going to save.” The laws regulating the pipeline industry, including the cost-benefit analysis requirement, fall under the jurisdiction of the U.S. House Railroads, Pipelines, and Hazardous Materials Subcommittee. The subcommittee, part of the Transportation & Infrastructure Committee, is responsible for legislation reauthorizing the PHMSA every few years and establishing laws governing its operation and rulemaking process. So far the subcommittee has not passed legislation to address the agency’s stalled rulemaking process. According to a Sludge analysis of financial disclosures, the members of the Railroads, Pipelines, and Hazardous Materials Subcommittee have as much as $2.8 million invested in fossil fuel companies that own and operate oil and gas pipelines, presenting significant conflicts of interest. Many of the companies in which the representatives, both Democrats and Republicans, are personally invested are members of trade groups that oppose the PHSMA’s proposals to regulate natural gas gathering pipelines. The American Petroleum Institute and the GPA Midstream Association filed a joint position paper with the Department of Transportation in December 2018 opposing much of the PHSMA’s proposal for regulating gas gathering pipelines, stating that the new regulations would cost the industry $28 billion over a 15-year period.
Weekly Natural Gas Storage Report- Early June Outlook Is Bearish – EIA reported a storage build of 85 Bcf for the week ending May 3. This compares to the +89 Bcf we projected and consensus average of +87 Bcf. The +85 Bcf was higher than the five-year average of +70 Bcf but lower than last year’s +89 Bcf. For the week ending May 10, we have a storage build of 100 Bcf. November EOS is forecasted to be 3.70 Tcf. We remain long our 1/4 sized UGAZ position. TDDs are projected to be higher than normal for the next 15 days. Even though we are long at the moment, the latest ECMWF-EPS long-range outlook was not supportive of the bull case. For the time being, the June weather outlook appears to show a colder than normal set-up, which would keep CDDs at bay. You also can see this explanation from the Commodity Wx Group: We estimate that if June is indeed colder than normal, then storage builds will be very sizable. We would see consecutive 100+ Bcf builds as low natural gas prices won’t help offset the lower CDDs. In addition, another bullish point – production – was recently eliminated as the drop we observed earlier in the week was corrected. Temporary outages impacted production, so we are seeing lower 48 production regain ~89 Bcf/d. With production higher and demand projected to be lower, this spells the bear case for natural gas. But readers must remember that during the summer gas trading period, prices tend to oscillate around a price band. Even though the storage builds will be large in June, we think the downside is capped by the higher power burn switching demand. But if Mother Nature is not supportive, we see summer gas prices capped at $2.7/MMBtu for the time being. For the natural gas bulls, a hotter than normal summer is needed to boost demand and help eliminate the surplus we see in the market. The focus will quickly shift back to weather outlooks by the end of May.
No Surprises in EIA Natural Gas Report; OPEC Crude Production Inches Higher – Natural gas futures are trading lower, showing limited response to today’s U.S. Energy Information Administration (EIA) weekly storage report. The market is holding inside yesterday’s move, but lingering near the top of its one-week range. The chart pattern suggests investor indecision and impending volatility. Earlier in the session, the EIA reported that domestic supplies of natural gas rose by 85 billion cubic feet for the week-ended May 3. Traders were looking for a larger-than-average double-digit build. At 17:41 GMT, June Natural gas is trading $2.593, down $0.017 or -0.85%. A Bloomberg survey showed analysts were looking for a range of 79 Bcf to 108 Bcf, with a median 87 Bcf injection. International Exchange (ICE) EIA Financial Weekly Index futures settled Tuesday at a build of 86 Bcf. Natural Gas Intelligence’s (NGI) model predicted an 89 Bcf injection. Reuters predicted a build of 88 Bcf, down from last week’s 123 Bcf build. Last year, the EIA recorded an 85 Bcf build for the period, and the five-year average is an injection of 72 Bcf. Total stocks now stand at 1.547 trillion cubic feet, up 128 billion cubic feet from a year ago, but 303 billion below the 303 billion below the five-year average, the government said. U.S. West Texas Intermediate and international-benchmark Brent crude oil are trading lower, but up from their intraday lows. Some of the strength at the mid-session was fueled by a strong recovery in the stock market after President Trump said a trade deal with China was still a possibility. Also helping to underpin prices was a report that showed crude oil production in OPEC edged higher by a modest 30,000 barrels per day (bpd) to 30.26 million bpd last month. The S&P Global Platts survey showed the first increase after four months of steady declines. The report also showed production in Iran and Angola declined, but increased in Nigeria, Iraq and Libya. The S&P Platts survey also revealed surprisingly that production in Venezuela stabilized last month. Platts also said that the organization’s largest producer, Saudi Arabia, kept its production rate stable in April, at an average 9.82 million bpd. The Platts survey also showed that Iran saw an estimated 120,000 bpd drop in its production last month, to 2.57 million bpd. The reason was that many importers of Iranian crude stopped buying it in anticipation of the May 1 expiration of U.S. sanction waivers that Washington granted to eight large importers. At 17:55 GMT, June WTI crude oil is at $61.66, down $0.46 or -0.74% and July Brent crude oil is at $70.22, down $0.15 or -0.21%.
Collins, King back bipartisan effort to bar New England offshore drilling — U.S. Sens. Susan Collins, R-Maine, and Angus King, I-Maine, are backing bipartisan legislation to prohibit offshore oil and gas drilling in New England, they announced on Monday.The bill, known as the New England Coastal Protection Act, was first introduced last year and has been reintroduced into the Senate by a group of New England lawmakers.Before the legislation was first introduced last year, Collins and King laid out some of their concerns in a letter then-U.S. Interior Secretary Ryan Zinke.Among other things they argued that even minor spills could cause serious harm to the lobster industry, which contributes an estimated $1.7 billion to the state’s economy, in addition to hurting other fisheries, aquaculture, and coastal tourism.On Monday, they elaborated on those concerns in a joint statement.“The waters off Maine’s coast provide a healthy ecosystem for our state’s fisheries and support a vigorous tourism industry, both of which sustain thousands of jobs and generate billions of dollars in revenue for Maine each year,” they said. They added: “With our environment so closely tied to the vitality of Maine’s economy, we cannot risk the health of our ocean on a shortsighted proposal that could impact our state for generations. We are proud to join our colleagues from New England to underscore the necessity of protecting our waters from offshore drilling.” While the Trump Administration has signaled that plans to open new coastline to offshore drilling were tentatively sidelined, the U.S. Bureau of Ocean Energy Management continues to review applications for permits to conduct seismic testing in the Atlantic Ocean, a precursor to oil and gas drilling, according to Monday’s news release.
Amid Line 5 talks, who would share tunnel real estate? – Since its introduction in October, the proposed Straits of Mackinac utility tunnel has been touted for its potential to benefit multiple entities that own assets in the Straits. According to the agreement reached under Gov. Rick Snyder’s administration, the concrete structure at the bottom of the Straits of Mackinac would house replacement piping for Enbridge’s Line 5 petroleum pipeline, but could also be used to hold a number of phone, natural gas and electrical lines that currently run between Michigan’s upper and lower peninsulas. Last week, a letter from the American Transmission Company (ATC) cast some doubts on those promises. In that letter, addressed to the Chippewa Ottawa Resource Authority, Tim Finco, vice president for internal affairs at ATC, said “a tunnel is not an acceptable solution for ATC” for timing, safety and practicality reasons. “ATC does not believe that installing high-voltage electric lines in close proximity to high pressure oil or gas lines is a good idea,” Finco said. “Moreover, a utility tunnel carrying oil, gas and electric lines would dramatically increase costs. It is likely those costs would be passed on to U.P. electric users who already pay Michigan’s highest utility costs.” In a phone interview with the News-Review, a representative for ATC said it wasn’t the first time those concerns have been brought up. “ATC has been working closely with representatives from the governor’s office on such matters since the prior administration, and going forward to new administration, we will working with them for a plan,” said ATC spokeswoman Allisa Braatz. When asked if representatives of the company specifically raised their concerns during those early discussions with the governor’s office, she said they had.
Environmental groups push for ‘fracking transparency’ in Illinois – Republican state lawmakers from Southern Illinois pushed back last week against a bill that would require more public disclosure from oil and gas drilling companies whenever they use hydraulic fracturing, or “fracking” in their operations in the state. Their comments came during a hearing Tuesday in the House Energy and Environment Committee. It is considering House Bill 282, dubbed a “fracking transparency bill,” sponsored by Rep. Robyn Gabel (D-Evanston) and supported by environmental groups including Illinois People’s Action and Southern Illinoisans Against Fracturing Our Environment. “Property and health concerns clearly give the public the right to know where the wells are going and what frack chemicals are being used,” Bill Rau of Illinois People’s Action told the committee. “Some horizontal wells are drilled only 500 to 800 feet below the surface, which can be within or just below strata containing groundwater.” In 2013, Illinois passed a law requiring full public disclosure of large-scale fracking operations, but that law applied only to wells that inject more than 80,000 gallons of pressurized fluids. No such wells have been drilled in Illinois since that time, largely because there is little left of the underground oil and gas reserves in the state. The bill now being considered would extend those same public disclosure requirements to even the smallest fracking operations. Among other things, it would require the Illinois Department of Natural Resources to make public the location of every fracking permit it issues as well as the chemicals that are to be used in the fracking operation.
Shell, Energy Transfer Seek Louisiana Project Bids – Shell US LNG, LLC and Energy Transfer LP have issued an invitation to tender (ITT) to U.S. and international consortia for the engineering, procurement and construction (EPC) contract for their Lake Charles LNG project in southwestern Louisiana. In a written statement Friday, the companies reported that the project calls for converting their existing LNG import facility in Lake Charles, La., to a large-scale export facility. In March of this year, the companies – 50/50 partners in the joint venture – reported that they had signed a project framework agreement.. That deal set the commercial terms and pathway to advance the 16.45-million-tonne-per-annum potential development toward final investment decision (FID), the companies stated. According to Shell and Energy Transfer, the Lake Charles LNG project is already fully permitted and uses existing infrastructure. Moreover, they stated the liquefaction facility would benefit from “abundant natural gas supply” as well as proximity to Energy Transfer’s pipeline network as well as other pipeline infrastructure.
Most US Offshore Resources Not Up for Grabs – Ninety-four percent of the United States’ offshore resources are not available for investment. That’s what Eric Oswald, vice president for the Americas at ExxonMobil, revealed during a presentation at the Offshore Technology Conference in Houston, Texas, on Wednesday. “You guys know how much of the U.S. offshore is available for investment? … Six percent. Ninety-four percent of our nation’s resources offshore … are not available for us to invest in,” Oswald told delegates attending the presentation. “Who’s losing there? I mean it’s the country, right? It’s a huge amount of potential lost there … That’s an astonishing number,” he added. According to a Bureau of Ocean Energy Management fact sheet (BOEM), U.S. Outer Continental Shelf (OCS) production accounts for about 18 percent of domestic crude oil and four percent of domestic natural gas supply. In fiscal year 2016, federal leasing revenues for the OCS were approximately $2.8 billion, the fact sheet highlighted. The mission of the BOEM is to manage development of U.S. OCS energy and mineral resources in an environmentally and economically responsible way, according to the organization’s website.
BP Approves Thunder Horse Expansion in GOM – BP has approved the Thunder Horse Expansion Phase 2 project in the deepwater Gulf of Mexico, the company announced Monday. At its peak, the project is expected to add about 50,000 gross barrels of oil equivalent per day (boepd), with first oil expected in 2021. BP’s Thunder Horse expansion will add two new subsea production units with two new production wells. Plans include six additional wells to be drilled in the future as part of the overall development. The Thunder Horse expansion signifies the most recent major investment in the U.S. offshore region and follows other expansion projects at the platform in recent years. “This latest expansion at Thunder Horse is another example of how the Gulf of Mexico is leading the way in advantaged oil growth for BP, unlocking significant value and safely growing a high-margin business,” Starlee Sykes, BP’s regional president for the Gulf of Mexico and Canada, said in a company statement. “It also highlights our continued growth and momentum in a region that will remain a key part of BP’s global portfolio for years to come.” In October 2018, the company announced the Thunder Horse Northwest Expansion offshore Gulf of Mexico began four months ahead of schedule and would boost production at the platform by 30,000 boepd..
GOM Decommissioning Scene is Changing – Hardly an easy proposition to begin with, dismantling an offshore oil and gas platform in the Gulf of Mexico (GOM) is becoming even more challenging as the complexity of decommissioning and abandonment (D&A) projects intensifies.“The oil price declines that hit us in 2015-2016 caused many GOM production assets to become uneconomical,” Tom McNulty, Houston-based managing director of Great American Group, told Rigzone. “As such, low-hanging fruit – in shallow waters – was the recent focus and that aspect of D&A is less capital-intensive to do.” The D&A scene in GOM is changing, said McNulty. He explained that assets located in deeper water depths are increasingly reaching the end-of-life stage, translating into D&A projects that are much more challenging to complete.“The farther out you go, and the deeper the water, the more difficult the work,” said McNulty. “We are seeing that oftentimes the very same companies that built and installed GOM assets years ago are the very same companies that are hired to decommission them.”Citing government and market sources, McNulty highlighted the growing magnitude of D&A operations. Key data points include:
- Global D&A spending should reach $13 billion per year by 2040
- Worldwide, D&A expenditures will increase by 540 percent through 2040
- From 2021 to 2040, there will be an estimated 2,000 offshore D&A projects
- In just the GOM, decommissioning liabilities amount to roughly $40 billion.
Besides the logistical challenges associated with decommissioning remote offshore structures, the profit potential associated with the time-consuming process is minimal to nonexistent for the operator. As a project manager with Worley’s INTECSEA consultancy told Rigzone in 2018, an operator’s ultimate goal in the approximately five- to six-year D&A process is “to reduce overhead.”“The environmental and regulatory issues are multifold, particularly in this post-Macondo era,” said McNulty, adding that weather-related impacts, the need for specialized heavy equipment and cyclical shortages of skilled personnel represent other D&A challenges. “Litigation risk is massive, so a great deal of planning goes into each D&A project.”
Is Deepwater In Permanent Decline? No. At least according to a recent poll conducted during a presentation at the 2019 Offshore Technology Conference in Houston, Texas. The majority of poll participants attending the presentation, which focused on offshore deepwater, answered no when asked if they considered the segment to be in permanent decline. In a separate poll during the presentation, attendees were asked what they thought was the most promising technology innovation for deepwater in the next decade. Almost half of the participants for this poll answered “machine learning”, with 38 percent of participants siding with advances in mechanical, materials and electronics (MME). Nine percent answered “drones” and six percent answered “other”. Earlier this year, Rystad Energy revealed that it expects global deepwater liquid production to surpass 10 million barrels per day (MMbpd) this year, before rising further in 2020. The company confirmed to Rigzone back in February that global deepwater liquid production had never surpassed 10 MMbpd before. “With new fields starting up in Brazil and Gulf of Mexico, we expect the total deepwater liquid production to reach 10.3 MMbpd in 2019. This is an increase of 700,000 bpd compared to 2018,” Rystad said in a statement posted on its website in February. Angola, Norway, Nigeria, Brazil and the United States are the largest deepwater producers, Rystad Energy highlighted earlier this year.
Ship collides with barges, causing massive gas product spill – An outbound tanker collided with two barges in the Houston Ship Channel, releasing an unknown amount of gasoline product into the water, according to authorities. The crash happened around 3:15 p.m. Friday, just east of Barbours Cut. One barge capsized. The other was damaged and leaked the product into the water. Both were carrying about 25,000 barrels of reformate. The Houston Ship Channel was closed from Light 61 to Light 75.Officials initially said about 25,000 barrels of reformate entered the water, but later said they were not sure how much was released. Reformate is a refined product that is blended with gasoline to boost octane to achieve levels needed for commercial sales. It is an extremely flammable liquid and vapor and can be fatal if it is swallowed. Reformate is toxic to marine life. The name of the 755-foot tanker that struck the barges was Genesis River and it was headed to Bayport Container Dock No. 5, officials said. Friendswood dispatch reported receiving several calls related to a smell of gasoline within the city. Officials said the smell is directly related to the crash in the Ship Channel. Galveston County officials said the Port of Houston and Center for Toxicology and Environmental Health are currently monitoring the air quality in and around the accident. County officials said the monitoring reports are not showing any detectable levels of concern in air quality in Kemah and Clear Lake Shores. Friendswood officials said tests were completed for Friendswood and League City, and said the results were “good with no detections of actionable levels of chemicals found.” The city said there is no danger to the public. Officials said people should turn off air conditioners to limit the smell within homes. Via Sky 2 video, one of the barges could be seen with a significant amount of damage. No injuries have been reported.
Permian Oil Storage Facility Project Goes to KBR – KBR, Inc. has won a reimbursable front-end engineering design (FEED) and engineering, procurement and construction (EPC) contract for improvements to a Permian Basin oil gathering and storage terminal in West Texas, the company reported Thursday. KBR did not specify who awarded the contract, only stating that it is a “Tier 1 International Oil Company.” Under the contract, KBR will provide reimbursable cost FEED and EPC services to support the installation and construction of terminal facilities excluding storage tanks. The company noted that the facilities will handle Permian crude oil and condensate for transport to the Gulf Coast.
Shale producer Pioneer Natural Resources to cut executive ranks (Reuters) – Pioneer Natural Resources said on Tuesday it has asked nearly a third of its executives to leave their jobs as the U.S. shale producer continues to trim costs and considers selling more assets. The company expects to save $100 million annually with the job cuts and a new organizational structure, Chief Executive Scott Sheffield said during an earnings call. The Irving, Texas-based oil and gas producer expects to shed the employees on a voluntary and involuntary basis by June 1. Shale firms have pushed U.S. oil output to record levels. But years of heavy spending led to investor pressure to reduce spending and use the cash to pay dividends and repurchase shares. “The big change is to treat capital just as important as production,” Sheffield said. Pioneer’s stock was trading 6.8 percent lower at $145.71 around midday on Tuesday after Sheffield said he did not expect a wave of consolidation in the industry. The stocks of producers focused on the Permian Basin bounced in April when Chevron Corp revealed it had agreed to pay $33 billion for Anadarko Petroleum Corp. Occidental Petroleum Corp then made a $38 billion hostile bid for Anadarko. Pioneer shares traded at $150.92 the day before the Chevron-Anadarko deal, but closed at $168.32 the day it was announced. “I didn’t come back to sell the company,” said Sheffield the company’s founder, who returned as CEO after veteran executive Tim Dove abruptly retired in February. “I personally don’t think that there’s going to be a lot of (mergers and acquisitions) over the next one to two years.” On Monday, Pioneer reported its first-quarter profit jumped to $350 million, or $2.06 per share, from $178 million, or $1.04 per share, a year ago. The company did not say how many executives will leave and did not respond to a request for comment.
Report: Air quality harmed as Texas oil production booms (AP) – The production of oil and natural gas in West Texas is booming but it’s coming at a cost to residents who are regularly exposed to unhealthy levels of air pollution, according to a report issued by an environmental group. The Environmental Integrity Project noted in a report released Thursday that the Permian Basin, which extends into New Mexico , is one of the most productive hydrocarbon regions in the world. But a consequence of that production is dangerous levels of sulfur dioxide in the air around Odessa and other locations, according to the report, which adds that pollution levels in much of Ector County, where Odessa is located, exceed standards set by the federal Environmental Protection Agency. “Controlling air pollution in West Texas has not been a priority for the state, as evidenced by the scarcity of air pollution monitoring stations in the Permian Basin,” the report said. “And yet, the type of air pollution in the Permian Basin – dominated by excessive emissions of sulfur dioxide and hydrogen sulfide – is known to have serious environmental and public health consequences.” Ilan Levin, associate director of The Environmental Integrity Project, said regulators such as the Texas Commission on Environmental Quality need to have stricter oversight of air pollution permits while penalizing polluters who violate the terms of those permits. “It’s like they’re speeding and the cops out on the beat are not issuing any speeding tickets,” Levin said Wednesday. A spokesman for TCEQ declined to comment, saying the agency hadn’t seen the report. The report asserts that oil and gas facilities are releasing large amounts of unpermitted pollution during equipment breakdowns, maintenance and other so-called “emission events.” The unauthorized release of air pollution occurs mainly from flaring, which is a way to burn gas that’s released, according to the report, but Levin adds that flaring was meant to be a last resort that instead has “become a business model to get rid of gas that they don’t know what to do with.” There’s only one functioning air monitoring station measuring sulfur dioxide in the Permian Basin, the report said, and more are needed to better police the release of emissions. Exposure can make breathing difficult and harm a person’s respiratory system. There were at least 30 occasions from December 2016 to April of this year that sulfur dioxide levels measured at one location exceeded federal health standards, according to the report, adding that oil and gas operators in and around Ector County self-reported 2,564 unauthorized releases of air pollution from 2014 to 2017.
Electric Fracking Could Take Over The Permian – Shale production in West Texas continues to boom – so much so that shale oil and gas producers in the Permian Basin have more than they know what to do with. As production continues to outpace the expansion of sorely needed pipeline infrastructure, local operators in the Permian are letting approximately 104 billion cubic feet of natural gas go to waste each year by flaring, what is essentially just burning the gas away, instead of putting it on market. For many producers in the Permian, this has led to diminishing profits. One such company is Houston-based oilfield service company Baker Hughes. The company’s first quarter profit also took a nosedive, clocking in at $32 million–less than half of its profits for the same period a year earlier, when Baker Hughes reported a profit of $70 million. However, despite these dismal numbers, things are looking up for Baker Hughes. The company is debuting a new, cutting-edge technology that will harness this otherwise wasted gas to power their hydraulic fracturing equipment in the Permian Basin in West Texas. Simonelli announced to investors this week that his company will be forging a new path in fracking by introducing a revolutionary fleet of “electric frack” turbines that will “use excess natural gas from a drilling site to power hydraulic fracturing equipment – reducing flaring, carbon dioxide emissions, people and equipment in remote locations” according to reporting by the Houston Chronicle. During a Tuesday call with investors Simonelli characterized the new strategy as an across-the-board win for their customer base, saying, “We’re solving some of our customers’ toughest challenges such as logistics, power and reducing flare gas emissions with products from our portfolio.” One of these logistical sticking points concerns the high volumes of diesel required to power hydraulic fracking rigs. These new “electric frack” turbines are a good start. The approximately 500 traditional diesel-powered hydraulic fracking fleets scattered across the U.S. and Canada consume about 20 million horsepower of energy altogether according to calculations by Baker Hughes. This means that there is a massive market–about 15 gigawatts–for electricity generated by using the new gas-fired turbines. Instead of adding new carbon emissions these turbines will be powered with gas that is currently being burned off anyway instead of adding diesel emissions on top of the carbon dioxide from those flares. To date, eight of these groundbreaking “electric frack” fleets have been deployed in the Permian Basin, but if they are as successful as Baker Hughes seems to think they will be, we can expect a lot more in a hurry.
US oil and gas rig count falls 13 on the week to 1071: Platts Analytics – US oil and gas rigs fell 13 to 1,071 the week ended May 8, S&P Global Platts Analytics said Thursday, resuming what has generally been a six-month downward trend despite domestic oil prices continuing firmly above $60/b. The rig count drop has fluctuated up and down in recent weeks as upstream operators – many of whom have heavy early-2019 activity programs planned for the year – released a rig after finishing a program or prepared to drill new wells. Last week the rig count gained 18, landing at 1,084 after spending much of April slipping each week. The US rig count peaked in mid-November 2018 at 1,233 and has gradually decreased since then. It dropped below 1,100 in mid-February and since then has generally stayed around the high 1,100s.This week’s rig count decrease was for both oil and gas. Oil-directed rigs were down by five to 852, while rigs chasing gas fell by six to 218.In addition, a two-rig decline was posted for rigs not specified for either oil or gas.For specific domestic plays, the biggest weekly drop of nine rigs, to 211, came from the geographic classification “Other” – a category for rigs not listed in any of the other eight large named basins.For named basins, the Utica Shale, sited mostly in Ohio, gained four rigs this week for a total 19. The Denver-Julesburg Basin mostly in Colorado gained two rigs for a total 32, while the Williston Basin of North Dakota and Montana added a rig for a total 62.Two areas lost three rigs apiece: the Haynesville Shale of East Texas and Northwest Louisiana, and the Dry Marcellus Shale, mostly in Pennsylvania. That left the Haynesville with 58 rigs and the Dry Marcellus with 35.The Wet Marcellus, also mostly in Pennsylvania, and also the Permian Basin of West Texas and New Mexico, each lost two rigs. That left the Permian with 462 rigs and the Wet Marcellus with 23 rigs.The SCOOP-STACK play in Oklahoma lost one rig, leaving 86, while the Eagle Ford Shale in South Texas stayed steady at 83 rigs.Also, the number of US permits approved this week fell by 439 compared with a week ago, for a total 549. The biggest single drop came in the “Other” category, down by 501 for a total 166 permits approved. For named plays, the Permian Basin gained the most, up 43 from last week to 204. The Dry Marcellus was up by 24 to 41 while the Wet Marcellus was up 12 to 20.
Buffett says Occidental Petroleum investment is a bet on oil prices over the long term – Billionaire investor Warren Buffett said Monday that Berkshire Hathaway’s $10 billion investment in Occidental Petroleum is a bet on oil prices over the long term. “It’s also a bet on the fact that the Permian Basin is what it is cracked up to be,” the chairman and CEO Berkshire told CNBC’s Becky Quick. But “oil prices will determine whether almost any oil stock is a good investment over time.” “If [oil] goes way up, you make a lot of money,” he added. Occidental revealed on Tuesday that Berkshire had committed to invest $10 billion in the company to help fund its proposed acquisition of Anadarko Petroleum. Berkshire would make the investment by purchasing 100,000 shares of preferred stock, which pays out an 8% annual dividend. Buffett was willing to invest $20 billion to help Occidental seal the deal, sources told CNBC’s David Faber. Occidental revised its bid to purchase Anadarko after the international oil and gas driller agreed to sell its business to Chevron last month for $65 a share in a 75% stock and 25% cash deal worth $50 billion including debt. Asked why Berkshire wouldn’t just buy Anadarko itself, Buffett said, “That might have happened if Anadarko came to us, but we wouldn’t jump into some other deal that we heard about from somebody else coming to us seeking financing.” Later in the interview, longtime investing partner and vice chairman Charlie Munger responded to the question as well, saying, “Nobody asked us to.”
Occidental inks $8.8 billion deal to sell Anadarko’s African oil and gas assets to Total – Occidental Petroleum has reached a deal to sell Anadarko Petroleum’s oil and gas assets in Africa to French oil major Total for $8.8 billion. The agreement is contingent on Occidental first reaching an agreement to buy Anadarko and closing the deal. Occidental is competing with Chevron to acquire Anadarko. The announcement on Sunday offers some clarity on how Occidental would fund its cash-and-stock purchase of Anadarko. Occidental had said it would seek to sell $10 billion to $15 billion worth of assets to underwrite the $38 billion proposed takeover. Occidental said the sale of the Anadarko’s assets in Algeria, Ghana, Mozambique and South Africa to Total would also reduce the challenges of integrating the two drillers. The deal with Total is a binding agreement, and the divestment of the African assets would happen at the same time Occidental closes a deal to purchase Anadarko or shortly after. “Given our long history of working together productively, I am confident we can execute this sale quickly and efficiently,” Occidental CEO Vicki Hollub said in a statement. “Total has extensive experience working in Africa and is well positioned to maximize value from these assets.” The divestment would leave Occidental with Anadarko’s holdings in U.S. shale basins, the Gulf of Mexico and South America, as well as Western Midstream Partners, a fossil fuel transportation and processing company. Occidental is primarily interested in Anadarko’s acreage in the Permian Basin, the top U.S. shale field stretching from western Texas to southeastern New Mexico. Chevron reached a deal to buy Anadarko for $33 billion last month, but Occidental later put in a higher offer. Anadarko’s board of directors is currently considering Occidental’s bid.
Occidental revises bid for Anadarko in buyout battle with Chevron, offers mostly cash – Occidental Petroleum on Sunday put a revised buyout offer in front of Anadarko Petroleum, offering to pay shareholders in mostly cash as it seeks to derail Chevron’s acquisition of the international oil and gas driller. Occidental is still offering to buy Anadarko for $76 a share but would now pay 78% in cash and 22% in stock. The $57 billion transaction was initially structured as a 50-50 cash-and-stock deal when Occidental first made its public bid for Anadarko nearly two weeks ago. Anadarko agreed to sell its business to Chevron last month for $65 a share in a 75% stock and 25% cash deal worth $50 billion including debt. Anadarko’s board of directors resumed negotiations with Occidental last week after determining the rival bid could be superior to Chevron’s offer. Occidental says the revised offer creates immediate value and makes it more certain the deal will close. By offering more cash, Occidental will no longer have to seek approval from shareholders to purchase Anadarko. The risk of Occidental shareholders voting down the purchase created uncertainty that Occidental’s management could bring the buyout over the finish line. “Our revised proposal and merger agreement represents our comprehensive response to all points that your counsel has raised with ours over the course of the past week,” Occidental CEO Vicki Hollub said in a letter to Anadarko’s board of directors. Hollub revealed in the letter that counsel for Anadarko’s board requested three seats on Occidental’s board of directors. Occidental’s new offer does not include that provision because the improved bid does not warrant giving up the three seats, she said. Earlier on Sunday, Occidental announced it had reached a deal to sell Anadarko’s African assets to French oil major Total for $8.8 billion. That would achieve most of Occidental’s goal of divesting $10 billion to $15 billion in assets as part of the buyout. The announcement followed a commitment by Warren Buffett’s Berkshire Hathaway last week to invest $10 billion in Occidental to help fund the Anadarko buyout. Some investors and analysts, including CNBC’s Jim Cramer, have criticized the sale of preferred stock to Berkshire because it comes with a steep 8% annual dividend.
Oxy Jazzes Up Anadarko Offer, Makes $8B Total Deal – Occidental Petroleum Corporation (Oxy) revealed Sunday that it has jazzed up its offer for Anadarko Petroleum Corporation (APC) and agreed a deal to sell APC’s Africa assets to Total S.A. for $8.8 billion. Oxy has delivered a letter to the board of directors of APC setting forth the terms of a proposal to acquire APC for $76 per share, comprised of $59 in cash and 0.2934 shares of Oxy common stock per share of APC common stock. Oxy’s previous offer was for $76 per share, comprised of $38 in cash and 0.6094 shares of Oxy common stock for each share of APC common stock. The revised proposal has been unanimously approved by the Oxy board of directors and represents a premium of approximately 23.3 percent to the $61.62 per share value of Chevron’s pending offer, Oxy said in a company statement. Oxy added that the increased cash portion of $59 per share provides “significant immediate value, greater closing certainty and enhanced accretion”. In connection with Oxy’s proposal to acquire APC, the company has entered into a binding agreement to sell APC’s Algeria, Ghana, Mozambique and South Africa assets to Total for $8.8 billion. The sale is contingent upon Oxy entering into and completing its proposal to acquire APC and would be expected to close simultaneously “or as soon as reasonably practicable afterwards”, Oxy said. The proceeds of the sale of these assets would cover a portion of the cash consideration to fund the proposed acquisition of APC, according to Oxy. “We firmly believe that Occidental is uniquely positioned to drive significant value and growth from Anadarko’s highly complementary asset portfolio,” Oxy President and CEO, Vicki Hollub, said in a company statement. Commenting on Oxy’s Total deal, Greig Aitken, director of M&A research at Wood Mackenzie, said, “this is a move that will alleviate the concerns of Anadarko’s shareholders”. “Anadarko’s main concern appears to be uncertainty regarding the execution of the deal. Can Oxy finance the deal, will the bid value erode due to a falling share price, will its shareholders acquiesce?” Aitken added. “Combined with the recent $10 billion Berkshire Hathaway commitment, this disposal has allowed Oxy to increase the cash component of its bid from 50 percent to 76 percent (an increase of approximately $10.5 billion).
Anadarko likely to deem Occidental’s buyout offer superior to Chevron’s bid on Monday: Sources – Anadarko Petroleum’s board of directors is likely to determine on Monday that Occidental Petroleum’s buyout offer is superior to the agreement the board reached last month to sell Anadarko to Chevron, sources tell CNBC’s David Faber. The decision would flip the momentum of the bidding war in Occidental’s favor and put pressure on Chevron to sweeten its $33 billion offer. Occidental has taken several steps to outmatch the much larger Chevron since launching its $38 billion rival offer nearly two weeks ago. On Sunday, Occidental revised its bid, offering to purchase Anadarko for 78% cash and 22% stock, compared with its earlier 50-50 cash-and-stock proposal. Increasing the cash component of the deal means Occidental will not have to hold a shareholder vote on the acquisition, making it more certain that the driller could complete the deal. Occidental was able to offer more cash after securing a $10 billion preferred stock investment from Warren Buffett’s Berkshire Hathaway. Occidental also inked a deal to sell Anadarko’s African oil and natural gas assets to French oil major Total for $8.8 billion, which would also fund the cash component of the acquisition. If Anadarko’s board does deem Occidental’s bid superior, Chevron will have four days to put another offer on the table. Anadarko would have to pay Chevron a $1 billion breakup fee if its board ultimately chooses Occidental’s offer.
Anadarko to cancel Chevron buyout deal after board deems Occidental’s bid superior – Anadarko Petroleum’s board of directors said on Monday that Occidental Petroleum’s buyout offer is superior to its agreement to sell its business toChevron, putting the deal with the oil giant in jeopardy.The reversal marks the latest twist in a rare bidding war in the oil and gas sector. Chevron now has four days to counter Occidental’s latest bid for Anadarko, an oil and gas driller with prized assets in the U.S. Permian Basin, the Gulf of Mexico and Africa.Shares of Occidental Petroleum were down slightly in after hours trading, while Chevron’s stock price ticked higher. Anadarko’s shares were roughly flat after jumping 3.8% on Monday. Chevron reached an agreement last month to buy Anadarko for $33 billion, or $65 a share. Shortly after, Occidental offered $38 billion, or $76 a share. Occidental on Sunday sweetened its bid by offering to pay mostly cash for Anadarko, after earlier structuring the transaction as a 50-50 cash-and-stock deal. Anadarko’s board of directors on Monday unanimously decided that the revised offer is a “Superior Proposal” under the terms of its agreement with Chevron. The board intends to cancel the deal with Chevron and enter into a definitive agreement to sell its business to Occidental. According to that agreement, Chevron has the right to put another offer on the table through Friday. Chevron’s merger agreement with Anadarko is structured as 75% stock and 25% cash. If Chevron does not make a counter offer, or if its revised proposal is rejected, Anadarko must pay Chevron a $1 billion breakup fee.
Chevron walks away from Anadarko Petroleum deal, will collect $1 billion breakup fee – Chevron said Thursday it will not submit a new offer to acquire Anadarko Petroleum, walking away from the deal after Occidental Petroleum pulled ahead in a battle to take control of the driller with prized assets in the top U.S. shale oil field. The decision means Chevron will collect a $1 billion breakup fee, a windfall that it could use to purchase another driller in the Permian Basin, the engine of the American oil drilling boom. Shares of the San Ramon, California-based oil major were up about 3% on Thursday. Anadarko announced on Monday that its board had unanimously decided that Occidental’s revised $38 billion bid was superior to a $33 billion Chevron buyout. Anadarko said it intended to break its agreement with Chevron and strike a deal with Occidental if Chevron did not submit a better offer. Occidental, with backing from Warren Buffett’s Berkshire Hathaway, offered to pay 78% cash and 22% stock for Anadarko, while the Chevron transaction was structured as a 75% stock and 25% cash deal. “Winning in any environment doesn’t mean winning at any cost. Cost and capital discipline always matter, and we will not dilute our returns or erode value for our shareholders for the sake of doing a deal,” Chevron Chairman and CEO Michael Wirth said in a statement.
Rystad: U.S. Shale Is Now The World’s Second Cheapest Source Of Oil Supply -U.S. shale oil – which just four years ago was the world’s second most expensive oil resource – is now the second cheapest source of new oil supply globally, just behind the giant onshore oil fields in the Middle East, Rystad Energy said on Thursday.North America’s tight oil has reduced costs over the past four-five years and has proven to be a competitive source of oil supply even when oil prices are not very high, according to the energy research firm. Rystad Energy estimates in its latest cost of supply curve update that the averageBrent Crude breakeven price for tight oil is now US$46 a barrel, just four dollars above the average $42 per barrel breakeven oil price for the giant onshore fields in Saudi Arabia and other Middle Eastern countries.To compare, in 2015, North America’s shale ranked as the second most expensive resource in Rystad Energy’s global liquids cost curve, with an average breakeven price at $68 per barrel.In 2019, onshore Middle East leads the cheapest source of supply, followed by North American shale, offshore shelf with average breakeven price of $49 a barrel, deepwater with a $58 breakeven price, and Russia onshore with $59 a barrel breakeven. The most expensive source of oil supply is the oil sands, where the average breakeven oil price is $83 a barrel, Rystad Energy’s cost curve analysis shows. “Tight oil is a short cycle investment with a relatively brief lead time from the sanctioning of new wells to the start of production. This gives E&P companies the flexibility to adapt to market conditions and easily change activity levels,” Espen Erlingsen, Head of Upstream Research at Rystad Energy, said, commenting on the analysis. “In the ever-changing oil price environment, this implies tight oil investment has less uncertainty compared to offshore,” Erlingsen added. According to the Q1 Dallas Fed Energy Survey, with executives from 82 E&P firms chiming in, average breakeven prices to profitably drill a new well in the U.S.range from $48 to $54 per barrel, depending on the region. Drillers need $50 a barrel on average to profitably drill a new well, down from $52 per barrel when the same question was asked last year. Average breakeven prices in Midland in the Permian were $48, the lowest-cost in the U.S., and the lowest-cost region in the past three years.
The Shale Boom Is About To Go Bust — The shale industry faces an uncertain future as drillers try to outrun the treadmill of precipitous well declines. For years, companies have deployed an array of drilling techniques to extract more oil and gas out of their wells, steadily intensifying each stage of the operation. Longer laterals, more water, more frac sand, closer spacing of wells – pushing each of these to their limits, for the most part, led to more production. Higher output allowed the industry to outpace the infamous decline rates from shale wells. In fact, since 2012, average lateral lengths have increased 44 percent to over 7,000 feet and the volume of water used in drilling has surged more than 250 percent, according to a new report for the Post Carbon Institute. Taken together, longer laterals and more prodigious use of water and sand means that a well drilled in 2018 can reach 2.6 times as much reservoir rock as a well drilled in 2012, the report says. That sounds impressive, but the industry may simply be frontloading production. The suite of drilling techniques “have lowered costs and allowed the resource to be extracted with fewer wells, but have not significantly increased the ultimate recoverable resource,” Technological improvements “don’t change the fundamental characteristics of shale production, they only speed up the boom-to-bust life cycle,” he said.For a while, there was enough acreage to allow for a blistering growth rate, but the boom days eventually have to come to an end. There are already some signs of strain in the shale patch, where intensification of drilling techniques has begun to see diminishing returns. Putting wells too close together can lead to less reservoir pressure, reducing overall production. The industry is only now reckoning with this so-called “parent-child” well interference problem. Also, more water and more sand and longer laterals all have their limits. Last year, major shale gas driller EQT drilled a lateral that exceeded 18,000 feet. The company boasted that it would continue to ratchet up the length to as long as 20,000 feet. But EQT quickly found out that it had problems when it exceeded 15,000 feet. “The decision to drill some of the longest horizontal wells ever in shale rocks turned into a costly misstep costing hundreds of millions of dollars,” the Wall Street Journal reported earlier this year.
Fracking- Earthquakes are triggered well beyond fluid injection zones — Using data from field experiments and modeling of ground faults, researchers at Tufts University have discovered that the practice of subsurface fluid injection used in ‘fracking’ and wastewater disposal for oil and gas exploration could cause significant, rapidly spreading earthquake activity beyond the fluid diffusion zone. Deep fluid injections — greater than one kilometer deep — are known to be associated with enhanced seismic activity — often thought to be limited to the areas of fluid diffusion. Yet the study, published today in the journalScience, tests and strongly supports the hypothesis that fluid injections are causing potentially damaging earthquakes further afield by the slow slip of pre-existing fault fracture networks, in domino-like fashion. The results account for the observation that the frequency of human-made earthquakes in some regions of the country surpass natural earthquake hotspots. The study also represents a proof of concept in developing and testing more accurate models of fault behavior using actual experiments in the field. Much of our current understanding about the physics of geological faults is derived from laboratory experiments conducted at sample length scales of a meter or less. However, earthquakes and fault rupture occur over vastly larger scales. Observations of fault rupture at these larger scales are currently made remotely and provide poor estimates of the physical parameters of fault behavior that would be used to develop a model of human-made effects. More recently, the earthquake science community has put resources behind field-scale injection experiments to bridge the scale gap and understand fault behavior in its natural habitat. . The hazard posed by fluid-induced earthquakes is a matter of increasing public concern in the US. The human-made earthquake effect is considered responsible for making Oklahoma — a very active region of oil and gas exploration — the most productive seismic region in the country, including California. “It’s remarkable that today we have regions of human-made earthquake activity that surpass the level of activity in natural hot spots like southern California,” said Robert C. Viesca, associate professor of civil and environmental engineering at Tufts University’s School of Engineering, co-author of the study and Bhattacharya’s post-doc supervisor. “Our results provide validation for the suspected consequences of injecting fluid deep into the subsurface, and an important tool in assessing the migration and risk of induced earthquakes in future oil and gas exploration.”
Fracking can cause earthquakes tens of kilometres away – new research — Earthquakes threaten to be a show-stopper for fracking. In the Netherlands, the largest gas field in Europe will be shut down by 2030 after sustained damage to homes from earthquakes became too severe. In Oklahoma, US officials have severely curtailed operations after injection of waste water underground caused several earthquakes above magnitude five – one nearly 180,000 times stronger than the 2.3 magnitude earthquake that brought a seven-year pause on fracking in the UK.While operations have since resumed in Britain, the practice still remains a political battleground, with earthquakes at the centre. The UK government’s fracking commissioner, Natascha Engel, recently resigned, claiming that an [unreasonably low] magnitude 0.5 threshold for tolerated earthquakes amounted, in effect, to a ban on fracking.Residents, on the other hand, largely oppose fracking near their homes. Fears of damage to property and the well itself at a fracking location in Lancashire, in the north of England, notably lowered house prices in the area. In the absence of a known mechanism by which fracking could cause earthquakes more than a mile or two from drilling sites, operators have often denied responsibility for such quakes. However, new research has now linked distant earthquakes to fracking, providing evidence that much larger areas surrounding sites may be at risk from drilling operations than previously demonstrated. This is a critical problem not only for fracking, but for cleaner energy solutions too. By design, the breaking of rock that inevitably accompanies both waste water disposal and fracking produces small, usually imperceptible earthquakes. Occasionally though, the injection of fracking fluid or waste water can cause movements in natural pre-existing geological faults – large cracks that already exist in the rock. If sufficiently severe, the resulting earthquake can cause damage to houses, threatening local communities. Some of these earthquakes occur very near the fracking site itself, but others have been reported as far as 50 kilometres away, making it difficult to guarantee the safety of surrounding areas.
In “new era” of oil and gas regulation, Colorado communities waste no time writing own rules – Less than three weeks after Gov. Jared Polis signed into law a sweeping billgiving cities and towns in Colorado new powers to regulate oil and gas drilling, communities sitting atop the state’s vast fossil fuel deposits are already looking at how to flex their newfound muscle. Lafayette, just hours after the bill was signed, added another six months to its moratorium on drilling in the city. Broomfield next week will discuss temporarily banning new oil and gas wells while it mulls new rules on the industry. Larimer County is launching an Oil and Gas Regulations Task Force that will meet over the spring and summer to come up with recommendations on how county leaders can move forward imposing limits on an activity that has been at the center of recent public health debates. “I think it’s no-holds barred for communities,” said Joe Salazar, a former state lawmaker from Thornton who heads the anti-fracking group Colorado Rising. “The oil and gas industry has been abusive for a long time and now communities are going to fight back. It’s the dawn of a new era.” That new era began on April 16 when the governor signed into law Senate Bill 19-181, which passed the Democratic-led legislature earlier in the month. The measure transfers much of the state’s authority over oil and gas activity to local governments. It also fundamentally revamps the mission of the Colorado Oil and Gas Conservation Commission, the main regulatory body over energy extraction in the state, to prioritize public health and safety in permitting decisions and abandon the agency’s traditional role of fostering energy development.
Court delays block Keystone XL pipeline construction in 2019 – Court delays block Keystone XL pipeline construction in 2019 (AP) – An executive for the company proposing the Keystone XL oil pipeline from Canada’s oil sands into the U.S. says it has missed the 2019 construction season due to court delays. TransCanada executive vice president Paul Miller made the statement during a Friday earnings call with analysts. The company also announced it was changing its name to TC Energy Corp. Plans to begin construction of the long-delayed pipeline got blocked last November when a federal judge in Montana ordered additional environmental reviews of the project. President Donald Trump has been trying to push it through. He issued a new permit for Keystone last month. The $8 billion line would carry up to 830,000 barrels (35 million gallons) of crude daily, along a route stretching from Canada to Nebraska.
US says it will complete Keystone environmental review (AP) – U.S. government attorneys say the Trump administration plans to finish a new environmental review of the Keystone XL oil pipeline from Canada even if a federal appeals court throws out a lawsuit that blocked the project. President Donald Trump issued a new permit for the $8 billion pipeline last month. In court filings on Tuesday, government attorneys said it is “undisputed” that Trump’s permit is not subject to two major environmental laws – the National Environmental Policy Act and Endangered Species Act. Nevertheless, the attorneys say the State Department will complete an environmental study ordered by a federal judge in Montana in November. The long-delayed line would carry up to 830,000 barrels (35 million gallons) of crude daily from Canada to Nebraska.
Could “Liking” an Anti-Pipeline Facebook Post Soon Be Illegal? – A new South Dakota law – written in consultation with the company that owns Keystone XL – could punish people for exercising their right to peaceful protest. Is it a harbinger of things to come? In March, Governor Kristi Noem of South Dakota signed legislation to usher in a new law that has come to be known informally as the Riot Boosting Act: an assault on Americans’ right to protest that perversely tries to pass itself off as a good-governance measure. Conceived with the assistance of TC Energy (TransCanada) – the company behind the embattled Keystone XL pipeline – this law would, among other things, authorize the state to sue individuals and groups for protesting projects like Keystone XL, should there be any damages as a result of the protest. The insidious nature of this law becomes obvious on closer inspection. By coining a new term – “riot boosting” – South Dakota creates an atmosphere of vagueness and fear that aims to chill the voices of indigenous people and others who are passionately opposed to projects like Keystone XL. After all, the state already has a law on the books to punish those who might destroy property or put people in danger during a protest.
Tester urges Interior to fight drilling next to Glacier park (AP) – U.S. Sen. Jon Tester is urging the Interior Department to continue its fight against energy development on land in northwestern Montana considered sacred to some Native Americans, after the government dropped a court appeal in the matter. In a letter released Friday, the Democratic lawmaker accused Interior Sec. David Bernhardt of undermining the Blackfeet Nation’s attempts to prevent drilling in the Badger Two-Medicine area. The 10-square-mile (26-square-kilometer) area bordering Glacier National Park is the site of the Blackfeet creation story. Most oil and gas leases in the area, issued decades ago, have since been cancelled by federal officials. But under Bernhardt, officials last month reversed course and dropped the government’s appeal of one of two leases that were still in dispute. Agency officials have declined to explain the move.
80K gallons of produced water spill on Dunn County farm land (AP) – A pipeline spill in Dunn County released nearly 80,000 gallons of produced water and impacted pasture land. North Dakota’s Department of Environmental Quality says the spill is believed to have been caused by workers installing an electrical line. Produced water is a mixture of saltwater and oil that can contain drilling chemicals. Pipeline operator XTO Energy reported the spill 27 miles southwest of Mandaree in late April and on Monday updated the spilled volume to 1,900 barrels. A barrel holds 42 gallons. State officials have inspected the site and are monitoring remediation.
15,000-gallon brine spill cleaned up in Renville County (AP) – A pipeline spill in Renville County released about 15,000 gallons of saltwater, but it didn’t impact any farmland or waterways.The state Oil and Gas Division says Cobra Oil and Gas Corp. reported Tuesday that 360 barrels of brine spilled Monday at a tank battery about 2 miles north of Sherwood.Brine is a byproduct of oil production. The spill was contained by on-site dikes, and all of the saltwater was recovered. A state inspector visited the site and will monitor any additional cleanup.
Judge sends suit over pipeline back to North Dakota court (AP) – A federal judge has sent back to North Dakota state court a lawsuit alleging the environmental group Greenpeace conspired against the Dakota Access oil pipeline. The two sides had agreed to the move, and U.S. District Judge Daniel Hovland recently signed off on it. Texas-based pipeline developer Energy Transfer Partners maintains Greenpeace and others should be held responsible for trying to disrupt pipeline construction and damage the company’s reputation and finances. Greenpeace accuses ETP of using the legal system to bully critics. Greenpeace had cited federal law dealing with court jurisdiction to try to get the state lawsuit moved to federal court, where the group had already prevailed against racketeering claims alleged by ETP. But ETP disputed Greenpeace’s argument, and the group late last week acknowledged the company was correct.
Sanford: Western North Dakota most likely home for plastics plant– A company that is exploring the potential of a value-added natural gas project in North Dakota does have western North Dakota on its short list. “It’s the only place they could be,” Lt. Governor Brent Sanford told the Williston Herald on Thursday. “They start looking at things like where do you have underground storage formation, where do you have the gas lines, where are they able to supply the gas, where do they have the most ethane produced.” Between 25,000 and 50,000 barrels per day of ethane are produced at natural gas processing plants in Williams County near Tioga and Williston. Right now, that ethane is being shipped by pipeline to Canada presently, for plastics manufacturing. That’s just the tip of what’s available gas-wise in the state. “We know we have the gas,” Sanford said. “We’re flaring enough gas to power the whole state. The opportunity is here, and our gas is rich in ethane.” The state produced 2.6 billion cubic feet per day of natural gas in February, according to the most recent figures from the North Dakota Division of Oil and Gas. About 20 percent of that was flared or burned off, due to a lack of infrastructure and processing capacity. A petrochemical plant would not only change the dynamic when it comes to flaring for its economy, but for the economy by capturing more of the wealth chain and keeping it in the state. During the last legislative session, lawmakers approved a sales tax exemption for certain natural gas processing facilities, in hopes of attracting a plastics manufacturing plant. Bakken Midstream told lawmakers during deliberations that it is considering a value-added natural gas infrastructure project in North Dakota.
Oregon DEQ denies Jordan Cove LNG water quality permit – The Oregon Department of Environmental Quality on Monday denied a water quality certification for the proposed Jordan Cove liquefied natural gas (LNG) export terminal and its feeder pipeline, the Pacific Connector pipeline, though the agency left the door open for the company to reapply.In a letter Monday to the project backers, the agency said “DEQ does not have a reasonable assurance that the construction and authorization of the project will comply with applicable Oregon water quality standards.”DEQ is in charge of administering the federal Clean Water Act in Oregon and the certification is required for the U.S. Army Corps of Engineers to issue permits for the project.The decision was applauded by opponents of the controversial project, but it is not a deal killer. Jordan Cove can request a contested case hearing within 20 days. DEQ also said it was making its decision “without prejudice,” meaning the company can also resubmit a new application. The agency said it was denying the application because there “is insufficient information to demonstrate compliance with water quality standards, and because the available information shows that some standards are more likely than not to be violated.”Specific concerns included impacts on water quality from construction and operation of the Pacific Connector pipeline. The 36-inch diameter pipe would affect more than 352 bodies of water and traverse mountainous, landslide-prone areas in its 230-mile path from an interstate gas hub in Klamath County to the proposed export terminal in Coos Bay. It would also need a 95-foot right of way across Southern Oregon, a massive path that would require clearcutting timber and building roads — creating the potential for significant erosion. DEQ also raised concerns about the release of release of drilling materials from the crossing of the Coos Bay estuary.
As Oregon Sends Jordan Cove LNG Back to Drawing Board, Gulf Coast Projects Press Forward – On Monday, Oregon state regulators dealt a blow to the proposed Jordan Cove Liquefied Natural Gas (LNG) project, refusing to issue a state water quality certificate required by the Army Corps of Engineers, citing unresolved concerns about water pollution and the company’s failure to answer information requests from the state in a timely manner. “The state water quality standards are intended to protect people and species from harm, and it’s clear Jordan Cove would cause incredible damage to Oregon’s waterways.”The state decision was made without prejudice, meaning that the company can reapply.Jordan Cove has sought federal permits to daily ship more than 1 billion cubic feet of natural gas, a fossil fuel which can be worse for the climate than coal, according to multiple studies, when burned for electrical power.If built, Jordan Cove would become the largest source of climate-changing greenhouse gas emissions in Oregon, numbers from a recently completed federal environmental review show, releasing 2.14 million metric tons of carbon dioxide (CO2) equivalents a year – a huge chunk of Oregon’s total greenhouse gas goal, set at 51 million tons next year and tightening after that.It would take the state’s only remaining coal-fired power plant 15 years to create as much greenhouse gas pollution as Jordan Cove would emit in one year, that analysis found. That coal-fired power plant, the Boardman plant, is slated to close next year, and Portland General Electricannounced in February that it planned to build a 380 megawatt wind, solar, and battery energy facility to power 105,000 homes to partially replace Boardman’s 575 megawatts of power.Nonetheless, driven by a massive glut of gas from the North American shale drilling rush, a massive wave of LNG export projects is underway. Five of the 11 projects FERC currently lists as “proposed” are larger than Jordan Cove, including the 3.6 billion cubic feet (bcf) per day Brownsville project in Brownsville, Texas, and the 3.4 bcf/day Venture Global LNGproject in Plaquemines Parish, Louisiana, which would each have more than tripled the capacity of the proposed Oregon terminal.In April, FERC announced approval for Tellurian’s Driftwood LNG project in Louisiana – recipient of the largest local tax break in U.S.history, with a capacity of 4 bcf/day – and the Port Arthur Liquefaction Project in Port Arthur, Texas, with a 1.86 bcf/day capacity. Earlier this month, the Trump administration’s Department of Energy granted Driftwood and Sempra Energy’s Port Arthur project export approvals that would permit their LNG to be sold in Asian countries. And FERCissued a final environmental impact study for a proposed 3.4 bcf/day plant in Plaquemines Parish, Louisiana, moving that project closer to approval.
Trump Wants To Open Over 1 Million Acres In California To Fracking – On April 25, the Trump administration released details of its plan to open up more than a million acres in California to oil drilling and hydraulic fracturing – including areas close to Sequoia, Kings Canyon and Yosemite National Parks. The plan would end a 5-year moratorium on leasing federal land in the state to oil and gas developers, but it comes at a time when opposition to drilling for fossil fuels in California is growing.The Bureau of Land Management (BLM), which is part of the U.S. Department of the Interior, released the proposal to bring oil and gas extraction to 1,011,470 acres of public and private land in California in its 174-page “Hydraulic Fracturing Draft Supplemental Environmental Impact Statement.”The Trump administration first put forward the idea last year, and it targets land across eight counties in Central California: Fresno, Kern, Kings, Madera, San Luis Obispo, Santa Barbara, Tulare and Ventura.“The Central Valley has some of the worst air quality in the nation, and we know fracking and drilling make air quality worse,” said Clare Lockwood, a senior attorney at the Center for Biological Diversity.“We will push back every step of the way against this reckless plan to subject more of California’s land, wildlife, and communities to fracking,” emphasized Monica Embrey, a senior campaign representative at the Sierra Club. In 2013, a federal judge ruled that by issuing oil leases in Monterey without examining the environmental dangers posed by fracking, the federal government had violated the National Environmental Policy Act. The ruling was the result of a lawsuit brought by Earthjustice, the Center for Biological Diversity and Los Padres ForestWatch.Three years later, another judge overturned a similar plan for drilling and fracking. Those rulings all happened under Obama, but last year a federal court ordered the Trump administration to stop issuing permits for fracking off the California coast. Now the Trump administration is reintroducing its 2018 plan to bring fracking to large swaths of land in California. The opposition to this latest plan is likely to be fierce, as environmental groups get ready to fight back against Trump’s stubborn refusal to accept the promise and popularity of sustainable energy. The president continues to deny the impact of climate change, despite all the evidence to the contrary, and he continues to line the pockets of his Big Oil and Big Gas cronies
Trump’s CA fracking plan is ‘dangerous,’ environmental groups say – The Trump administration’s plan to open up more than 1 million additional acres of public and private land in California to fracking is raising alarm in the environmental community. Environmentalists are challenging the proposal as “dangerous” to humans and iconic national parks nearby, including Yosemite and Sequoia-Kings Canyon National Parks. Last month, the U.S. Bureau of Land Management issued a draft supplemental environmental impact statement on the plan that includes using hydraulic fracturing, or fracking, to extract oil and gas from eight central counties in the state. “The risks posed to our national parks by further oil and gas development, particularly these iconic treasures that helped to inspire the modern-day conservation movement, is saddening to say the least,” Mark Rose, National Parks Conservation Association’s Sierra Nevada field representative, said in a statement. “Yosemite, Sequoia and Kings Canyon already experience some of the worst air quality within the park system, posing unprecedented threats to visitors and the natural resources that call these places home.” Rose further warns that allowing more “fracking near these treasured lands and the more than 1 million acres spanning from the Central Valley to the coast could be disastrous for our national parks, surrounding communities and other public lands.” California now ranks as the seventh largest state in terms of crude oil production, after being in third place until 2016. The state has already issued 121 permits for fracking so far this year, according to the California Department of Conservation. The BLM proposal includes additional oil and gas development in Fresno, Kern, Kings, Madera, San Luis Obispo, Santa Barbara, Tulare and Ventura counties. The agency plans to hold hearings in California on its proposal starting May 21 and indicated the 45-day public comment period ends June 10.
Fringe demand goes mainstream: Stop drilling and mining — Democrats are embracing a once-fringe demand that could cut emissions at the scale of the Obama administration’s biggest climate policies. A growing number of presidential candidates want to lock down the vast fossil fuel deposits sitting beneath federally owned lands and waters. President Obama resisted such calls until the end of his term, when he halted new leases for coal mines and some offshore drilling. Now, White House hopefuls want to go even further on their first day in office. “Keep it in the ground” has transformed from an activist chant into a mainstream campaign promise thanks to a Democratic electorate increasingly attuned to climate change. It also signals a backlash against President Trump’s aggressive drilling proposals. “Any candidate that comes through the Low Country, or South Carolina in general, needs to be talking about banning offshore drilling. They need to be talking about protecting our beaches. And if they don’t, I can’t imagine them having much credibility with our voters,” said Rep. Joe Cunningham, a South Carolina Democrat who used the issue to flip a red seat in last year’s midterms.Former Texas Rep. Beto O’Rourke (D) last week joined at least four other presidential candidates who are calling for a complete fossil fuel moratorium on public lands and in federal waters.O’Rourke and Massachusetts Sen. Elizabeth Warren have promised to halt new fossil fuel leasing on their first day in the White House. Vermont Sen. Bernie Sanders (I) and New York Sen. Kirsten Gillibrand, along with Warren, have co-sponsored the “Keep It in the Ground Act,” which would also stop leasing. Washington Gov. Jay Inslee has endorsed that legislation, too, and former Secretary of Housing and Urban Development Secretary Julifln Castro has said he supports the idea.Hawaii Rep. Tulsi Gabbard wrote a bill that would prohibit new federal permits for fossil fuel projects and exploration. Sens. Kamala Harris of California and Cory Booker of New Jersey have co-sponsored legislation that would codify and expand the Obama administration’s restrictions on Arctic offshore drilling. And that’s not counting the other candidates who have signed on to the Green New Deal, which calls for drastically reducing fossil fuels while protecting public lands and waters, though it doesn’t specifically prescribe a moratorium.
House climate panel will study drilling ban backed by 2020 Dems – Rep. Kathy Castor (D-Fla.), chairwoman of the special House committee studying the impacts of climate change, said Friday her panel will examine a proposal by 2020 presidential hopeful Sen. Elizabeth Warren (D-Mass.) to ban new fossil fuel drilling on public lands and waters. A number of other 2020 Democratic candidates – including Sens. Bernie Sanders (I-Vt.) and Cory Booker (D-N.J.) and former Rep. Beto O’Rourke (D-Texas) – also have endorsed a moratorium on drilling on public lands. “We’re going to examine that in the Climate Crisis Committee because what the scientists are telling us now is that we’ve got to cut our carbon pollution dramatically,” Castor said during an appearance on C-SPAN’s “Newsmakers” that is set to air later Friday. “If we are going to have a just transition [to clean energy], especially for communities across the country that have a lot of jobs in fossil fuels, it doesn’t make a lot of sense to expand extraction, especially on public lands,” she continued. “It’s an important issue moving forward in the context of how we cut our carbon pollution.” Several liberal lawmakers have argued that the government should ban oil and fossil fuel drilling if it wants to mitigate the effects of climate change. A recent U.S. Geological Survey report found that the extraction and burning of fossil fuels from federal lands accounted for nearly one-quarter of U.S. carbon dioxide emissions between 2005 and 2014. With Democrats taking control of the House last fall, the incoming Speaker, Rep. Nancy Pelosi (D-Calif.), named Castor, a close ally, to lead a new select committee examining climate change. That panel does not have the authority to write legislation, but it is tasked with offering policy recommendations to the full House Democratic Caucus by next year. “That gives us time to take a look at [a ban],” Castor said, “but a lot of the committees now are on the front lines of turning back the damage of what the Trump administration is doing to clean air and clean water.” Castor’s comments came a day after the House passed her bill to block President Trump from pulling the U.S. out of the Paris climate agreement. But the legislation is going nowhere in the Senate, where Senate Majority Leader Mitch McConnell (R-Ky.) has vowed to be a “Grim Reaper” for what he deemed socialist bills coming out of the House.
Pipeline Bottlenecks Cost Canadian Producers $20 Billion –Canada has plenty of oil, and demand is high, but the Canadian oil industry has nevertheless taken a major hit this year thanks to its persisting pipeline bottleneck. The Albertan oil industry has long been plagued by insufficient pipeline volumes but has not been able to fix the issue with any semblance of efficiency thanks to major bureaucratic and litigation-based delays on building new infrastructure like the long-delayed Trans Mountain pipeline expansion project. With pipeline capacity maxed out, Canadian oil producers have run out of storage space, leading to a major glut in oil reserves with nowhere to go. This has forced Canada to sell their oil at a major discount. In fact, a new study released this week by conservative think tank the Fraser Institute calculates that Canadian oil producers missed out on a whopping $20.62 billion more than they earned this year thanks to their severely depressed prices. Compared to the West Texas Intermediate benchmark, in the last year Canadian heavy crude traded, on average, at a discount of $26.50 U.S. a barrel. This is a huge dive from the five-year preceding, when Canadian heavy crude traded at an average of just $11.90 U.S. a barrel less than West Texas Intermediate. The pipeline capacity deficit has negatively impacted the Canadian economy in a number of ways. “Canada’s lack of adequate pipeline capacity has imposed a number of costly constraints on the country’s energy sector including overdependence on the US market and reliance on more costly modes of energy transportation,” states the Fraser Research Bulletin. “In 2018, these factors, coupled with the maintenance downtime at refineries in the US Midwest, resulted in significant depressed prices for Canadian heavy crude (Western Canada Select) relative to US crude (West Texas Intermediate) and other international benchmarks.” Fraser Institute went on to say that their calculations also found that if Canadian oil had been able to be transported in volumes corresponding to their current levels of production instead of watching their oil glut balloon and prices drop accordingly, Western Canadian Select would have traded at an average price of $52.90 U.S. a barrel during 2018 instead of the actual average price from last year, which clocked in at just $38.30 a barrel. “In September 2018, western Canadian oil production reached 4.3 million barrels per day but the takeaway capacity on existing pipelines remained constant at around 3.9 million barrels per day,“ the think tank’s report states.
Canada Likely to Greenlight Trans Mountain Expansion — The Canadian government is likely to proceed with expansion of the Trans Mountain oil pipeline when it announces its final decision on the conduit next month, officials familiar with the matter say. The government has made no secret about its interest in finding a way to expand the line, but has tiptoed around the matter to avoid opening any decision up to legal challenges that have already delayed the project — and things remain fluid as consultations continue. However, with a June 18 decision approaching, the government is likely to proceed with the expansion, the officials said, speaking on condition of anonymity because the they’re not authorized to speak publicly. Prime Minister Justin Trudeau has begun signaling his interest. “The only way to do it is to do it responsibly, and that’s what we’re doing. The need for it, and the national interest, is clear,” he said on April 30. However, to rush ahead without appropriate consultation “would be a guarantee you would continually be bogged down in the courts for the years to come.” The construction of the expansion, which would add 590,000 barrels of daily shipping capacity, would be a boon for Canadian oil drillers that have suffered from a lack of pipeline space that has weighed on local crude prices. That pipeline pinch sent Western Canadian Select crude to a record low of $13.46 a barrel last year, spurring Alberta’s government to order an unprecedented province-wide oil-production cut. Prices have since recovered to around $50.
First Nations seek ‘influence and control’ in pipeline purchase -First Nations seeking an equity stake in the Trans Mountain pipeline and its proposed expansion aren’t just seeking profit, they want “influence and control” over its environmental impact.“As shareholders of this pipeline, we want to be able to appoint a director who will promote Indigenous concerns, who will provide environmental oversight,” said Michael LeBourdais, chair of the Western Indigenous Pipeline Group and chief of the Whispering Pines/Clinton Indian Band.The band had sought an ownership stake during negotiations with Kinder Morgan Canada on a mutual benefits agreement related to an expansion that would triple the capacity of the 60-year-old pipeline. The Trans Mountain pipeline was purchased by the federal government from Kinder Morgan in August of last year for $4.5 billion. Ottawa is expected to approve a $9.3 billion expansion in June after having completed a new round of consultations with First Nations ordered by the court.Several First Nations have expressed interest in buying a stake in the pipeline since the purchase.“We always wanted to buy,” he said. “We always wanted equity. But in our negotiations with Kinder Morgan, equity was not on the table. When the government of Canada bought the pipe it opened the door to equity.” Whispering Pines is one of 43 First Nations in B.C. and Alberta that have signed mutual benefits agreements with Trans Mountain worth about $400 million.But a number of First Nations have opposed the project in court on a legal landscape that is exceptionally complex.While elected band councils have signed agreements with the pipeline proponents, the courts have recognized that hereditary First Nations leaders must also be consulted and accommodated on matters concerning the use of their traditional territories. Last week, Grand Chief Stewart Phillip of the Union of B.C. Indian Chiefs wrote an open letter to B.C. First Nations warning them against investing in the pipeline. “In a world where demand for oil has peaked and is declining, the oilsands, which has higher costs and higher carbon emissions than other sources of oil, will be some of the first oilfields to be shut down,” wrote Phillips.
Burnaby loses yet another Trans Mountain court battle. Is it time to stop? –Another day, another court loss for the City of Burnaby in regards to the Trans Mountain pipeline expansion project. On Thursday, the Supreme Court of Canada dismissed the city’s “application for leave to appeal from the judgment of the Federal Court of Appeal” – so much mumbo jumbo – which means the highest court in the land will not hear the city’s appeal. Burnaby was appealing a section of a decision from the appeals court after work on the Trans Mountain was halted in August of 2018. The appeals court cited the National Energy Board’s lack of consideration of the impacts of marine shipping on waters such as Burrard Inlet, as well as inadequate consultation of First Nations. The city was looking for more requirements being imposed on the NEB before the pipeline project could move ahead.Last August, the Supreme Court of Canada dismissed another city appeal – this one was challenging the NEB’s jurisdiction in Burnaby.At the time, that was the 17th-consecutive court ruling in favour of Trans Mountain against various challengers, according to the Canadian Press. At that point, Trans Mountain was looking like the Harlem Globetrotters and every challenger was the Washington Generals. Then, just days later, came the stunning court decision that has the federal government is still working to satisfy. Currently, the feds have extended the deadline to consult with First Nations about the project. It’s unclear how sincere this consultation is – it could still just be window dressing considering that the feds actually own the pipeline and it would be a political disaster for the federal Liberals if the project doesn’t go ahead.
Shell to Spud Deepwater Mexico Well in December – With investments flowing into Brazil and Mexico, deepwater opportunities abound for the two countries, according to Martin Stauble, Shell’s vice president of exploration for North America and Brazil.“Both countries from a deepwater perspective are certainly exciting hubs to pay attention to,” Stauble said during the Offshore Technology Conference in Houston Tuesday afternoon.Stauble said Shell has successfully added attractive pre-salt acreage into the mix through recent bid rounds. The company plans to spud five pre-salt wells in Brazil in 2019 and 2020. The first one, Alto de Cabo Frio, will spud in September.Drilling plans for Mexico are expected later this year.“Mexico – we didn’t have any position there in deepwater until early last year when we walked away with nine deepwater blocks,” said Stauble. “The first well we expect to get drilled in Mexico will hopefully be in early December.”Shell then plans to spud four or five more wells in 2020.“The main challenge is whether we get all the required regulatory bits and pieces together by December, but we have good collaboration with the [Mexican government],” Stauble said.He added that currently, it can take up to two years to get a permit to spud a well in Mexico. There’s also still difficulty getting seismic permits in Brazil. “I’m very keen on deepwater. I like it. It’s exciting. It has grown. And it is profitable,” he said. “You’re going to see Shell growing in this space with continued investment.”
Pemex’s Dismal Earnings Spark Investor Jitters— Just as Petroleos Mexicanos’ bonds finally recovered from last year’s rout, a dismal earnings report sent them tumbling back down. Pemex said on April 30 that its oil output declined 12 percent in the first quarter from a year ago, while its refineries operated at just 34 percent of capacity. In the next five days, yields on the company’s bonds maturing in 2027 jumped 31 basis points to 6.539 percent, making them the laggards among Mexican peers in that period. The results are another blow to Pemex, the world’s most indebted oil major with about $106.5 billion in outstanding debt. The government of Andres Manuel Lopez Obrador has plans to restore the company to its former glory, but struggled to reverse more than a decade of production declines, leaving investors unconvinced. “Pemex’s problems run deep, and international financial markets don’t have faith that it will do what’s needed to solve them,” said Alejandra Leon, Mexico energy analyst at IHS Markit. “We haven’t seen any indication that Pemex has implemented concrete action to reverse production declines, and what was surprising is that the refining business didn’t reflect higher income from combating fuel theft that was part of the rescue package.”
No deaths reported in Mexico pipeline blast – (Reuters) – No deaths were reported after a fuel pipeline exploded in southern Mexico, an emergency services official said on Thursday, adding that a fire triggered by the blast was under control. Mexican state oil firm Pemex is investigating the incident that occurred in one of its pipelines in southern Chiapas state, a company spokesperson said.David Leon, Mexico’s head of emergency services, said the pipeline burst late on Wednesday in the Reforma municipality of Chiapas. The fire had yet to be extinguished but was under control, he said.Two incinerated cars were found at the blast site, Reforma mayor Herminio Valdez told Milenio. They were likely being used to transport stolen fuel, he said. In January, at least 117 people died when a Pemex pipeline exploded in the state of Hidalgo shortly after President Andres Manuel Lopez Obrador launched a crackdown on rampant fuel theft, ordering pipelines closed in an effort to stamp out criminal activity.
Argentina’s YPF shifts focus to shale oil to reverse overall production decline – YPF, the largest oil and natural gas producer in Argentina, is focusing on shale oil for production growth as a glut slows natural gas output, managers at the state-backed company said Friday. The shift is aimed at reversing an expected an up to 3% decline 3% in overall output this year. “We have shifted our focus to accelerating our shale oil developments” in Vaca Muerta, the country’s largest shale play, said Sergio Giorgi, YPF’s vice president of strategy and business development. Giorgi spoke on a conference call with investors after the company reported late Thursday that its overall hydrocarbon production dropped 11.5% to 486,500 barrels of oil equivalent a day in the first quarter from 549,600 boe/d in the same quarter a year ago, dragged down by a 20.6% plunge in natural gas production to 34.7 million cubic meters a day from 43.7 million cu m/d. Oil production also fell, but only 0.5% to 226,400 b/d from 227,600 b/d, while output of natural gas liquids dropped 11.2% to 41,700 b/d from 47,000 b/d. Despite the decline, Giorgi said YPF is sticking to its earlier target of a 2-3% drop in overall production this year. “It is challenging, but doable,” he said. YPF recently started the full-scale development of Bandurria Sur with Schlumberger and La Amarga Chica with Malaysia’s Petronas in the oil window, building on its experience in Loma Campana, a partnership with Chevron. Loma Campana was producing most of its net 30,500 b/d of shale oil in Q1, up 63.3% on the year, which helped it increase its total net shale output by 45.1% to 71,100 boe/d in Q1 from 49,000 boe/d, according to the company’s latest financial results. To extend the growth, the company is widening its testing in the oil window, now concentrated in the southeast of the play, and building treatment and transport infrastructure, helping to offset declines at its many maturing conventional oil fields around the country. YPF is running six shale oil pilots and expects to go into full-scale development on two of them in 2020 and 2021. It is working with Shell on the Bajada de Anelo block and with a consortium of France’s Total, Germany’s Wintershall and BP-backed Pan American Energy on the San Roque block. Another pilot is on its 100%-owned Loma La Lata Oeste block, which is next to Loma Campana, while two blocks in the north of the play — Bajo del Toro with Norway’s Equinor and Chihuido with Chevron — are being tested with the idea of going into full development starting as soon as 2021.
‘We are hammering the last nail in the coffin of the fracking industry’ – It was always a poisoned chalice, mediating between multinational fracking firms and the local communities dead set against the extreme form of energy extraction in their backyards. Nonetheless, it still shocked many when the government’s “shale commissioner”, the former Labour MP Natascha Engel, resigned at the end of last month after barely six months in the job. The role was impossible, despaired Engel, who lost her seat in North East Derbyshire in 2017 after coming out in favour of fracking in the constituency. The government, she complained, was “choosing to listen to a powerful environmental lobby campaigning against fracking rather than allowing science and evidence to guide our policymaking”.Hurrah, thought Dave Shaw, as the news filtered through to Doncaster. Six years after he co-formed Frack Free South Yorkshire to oppose shale gas extraction on his doorstep, he was joyous. Over the phone in the following days, he said: “I most definitely feel we are winning. I feel like we are hammering the last nail in the coffin of the fracking industry.”Until 2011, hardly anyone in the UK who wasn’t a geologist had heard of fracking, which is the process of creating fractures in shale rock formations to release natural gas trapped inside. Then there was a series of small earthquakes caused by fracking near Blackpool by a firm called Cuadrilla. Concerns began to mount and the government issued a moratorium on fracking. But in December 2012, the government lifted the ban and began issuing exploration licences covering large swathes of the UK, including about 95% of South Yorkshire. Shaw – who is a Labour councillor as well as a builder – has been at the forefront of the fightback. Last week, he was in the final planning stages of one of the best-publicised protests yet, at the Tour de Yorkshire cycle race. Team Sky – the British squad that has won the Tour de France in six of the past seven years – were racing, only they had transformed into Team Ineos, after their new sponsor, a petrochemical and plastic-producing company that holds licences to frack all over Yorkshire. “It gives us an opportunity to highlight what Ineos is doing and talk about the hypocrisy of Team Sky, who rode around last season with whales on the back of their jerseys as part of a campaign against plastic pollution in the oceans and are now being sponsored by [one of] the biggest producers of plastics [in Europe].”
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