Written by rjs, MarketWatch 666
Here are some selected new articles from the week ended 16 September 2018.
This article is a feature every Monday evening on GEI.
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US crude supplies at a 43 month low; August global oil output at a record high, but still a half million bpd short of demand
Oil prices ended modestly higher in a week that saw several sharp price moves, both to the upside and to the downside…after falling nearly 3% to $67.75 a barrel in their first drop in three weeks last week, contract prices for US crude for October delivery pulled back from an early rally to end 21 cents lower at $67.54 a barrel on Monday, after weekly data from Bloomberg suggested U.S. oil inventories were rising, contradicting an earlier report from Genscape forecasting declining inventories…however, with Hurricane Florence threatening East Coast supplies and ongoing turmoil in Libyan and Iraqi oil fields, traders betting that Iran sanctions would leave the market short of crude pushed oil prices 3% higher to over $70 a barrel on Tuesday on reports that South Korea, Japan and India had already reduced their Iranian crude imports, before prices settled back to close at $69.25 a barrel, an increase of $1.71, or 2.5%, on the day…oil prices then rose past $71 a barrel in a rally on Wednesday after the EIA reported a larger-than-expected drop in U.S. crude inventories before again settling back to close $1.12 higher at $70.37 a barrel…however, oil prices saw their steepest drop in over a month on Thursday in falling $1.78 to $68.59 a barrel, after OPEC reported rising crude production and the IEA (International Energy Agency) pegged global oil supplies at a record high….however, the price rally commenced again on Friday with oil up as much as 2% after it was reported that Secretary of State Pompeo was going to announce new sanctions on Iran, but then faded into a retreat after Trump instructed aides to proceed with tariffs on about $200 billion more of Chinese products, with oil prices closing just 40 cents higher at $68.99 a barrel, an increase of 1.6% for the week…
Natural gas prices, meanwhile, were up 5.3 cents over the first three days of last week before a less bullish than expected storage report knocked prices back 6.2 cents over Thursday into Friday to end the week at $2.767 per mmBTU, down less than a penny for the week overall…this week’s EIA natural gas storage report for week ending September 7th indicated that natural gas in storage in the US rose by 69 billion cubic feet to 2,636 billion cubic feet during that cited week, which left our gas supplies 662 billion cubic feet, or 20.1% below the 3,298 billion cubic feet that were in storage on September 8th of last year, and 596 billion cubic feet, or 18.4% below the five-year average of 3,232 billion cubic feet of natural gas that are typically in storage after the first week of September….this week’s 69 billion cubic feet increase in natural gas supplies was more than analyst’s expectations for a 65 billion cubic feet increase, but it was below the 74 billion cubic foot average of natural gas that have typically been added to storage during the first week of September in recent years, the ninth such below average inventory increase in the past ten weeks…natural gas storage facilities in the Midwest saw another 32 billion cubic feet increase this week, while supplies in the East increased by 20 billion cubic feet and are now just 12.9% below normal for this time of year…on the other hand, just 4 billion cubic feet cubic feet of gas were added to storage in the Pacific region, where natural gas supplies are 23.3% below normal for this time of year, while the South Central region saw a 7 billion cubic foot injection as their natural gas storage deficit increased to 23.4% below their five-year average..
The Latest US Oil Data from the EIA
This week’s US oil data from the US Energy Information Administration, covering the week ending September 7th, showed that due to lower oil imports, higher oil exports, and an increase in refining, we had to withdraw more oil from our commercial crude supplies for the eighteenth time in the past thirty-three weeks… our imports of crude oil fell by an average of 123,000 barrels per day to an average of 7,591,000 barrels per day, after rising by an average of 229,000 barrels per day the prior week, while our exports of crude oil rose by an average of 320,000 barrels per day to an average of 1,828,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 5,763,000 barrels of per day during the week ending August 31st, 443,000 fewer barrels per day than the net of our imports minus exports during the prior week…over the same period, field production of crude oil from US wells was reportedly down by 100,000 barrels per day to 10,900,000 barrels per day, which means that our daily supply of oil from the net of our trade in oil and from wells totaled an average of 16,663,000 barrels per day during the reporting week…
Meanwhile, US oil refineries were using a near record high 17,857,000 barrels of crude per day during the week ending September 7th, 210,000 barrels per day more than the amount of oil they used during the prior week, while over the same period 757,000 barrels of oil per day were reportedly being pulled out of the oil that’s in storage in the US….hence, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from oilfield production, and from storage was 437,000 fewer barrels per day than what refineries reported they used during the week….to account for that disparity between the supply of oil and the consumption of it, the EIA needed to insert a +437,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a fudge factor that is labeled in their footnotes as “unaccounted for crude oil”…since that “unaccounted for crude” figure was at -179,000 barrels per day during the prior week, the 611,000 barrel per day swing in that metric from last week means that the week over week changes for one or more of this week’s EIA oil metrics must be in error by a statistically significant amount..(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….
Further details from the weekly Petroleum Status Report (pdf) show that the 4 week average of our oil imports fell to an average of 7,577,000 barrels per day, still fractionally more than the 7,565,000 barrel per day average that we were importing over the same four-week period last year….the 757,000 barrel per day decrease in our total crude inventories was all withdrawn from our commercially available stocks of crude oil, as the amount of oil in our Strategic Petroleum Reserve remained unchanged, even as a sale of 11 million barrels from those reserves to Exxon et al was closed at the end of last week….this week’s crude oil production was reported as being down by 100,000 barrels per day to 10,900,000 barrels per day because a rounded 200,000 barrels per day decrease to 10,400,000 barrels per day in the output from wells in the lower 48 states combined with a 6,000 barrels per day increase in oil output from Alaska was only enough to lower the national total, which is now being rounded to the nearest 100,000 barrels per day, by 100,000 barrels per day to 10,900,000 barrels….US crude oil production for the week ending September 8th 2017 had been reduced to 9,353,000 barrels per day in the aftermath of Hurricane Harvey, so this week’s rounded oil production figure was roughly 16.5% above that of a year ago, and 29.3% 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 97.6% of their capacity in using 17,857,000 barrels of crude per day during the week ending September 7th, up from 96.6% the prior week and the highest September refinery utilization rate in 20 years….the 17,857,000 barrels per day of oil that were refined this week were again at a seasonal high, for the 14th out of the past 15 weeks, and far more than have ever been refined in a week in September, but not directly comparable to the 14,078,000 barrels of crude per day that were processed during the week ending September 8th 2017, when US refineries were operating at just 77.7% of capacity, because Gulf Coast refineries had been shut down in the aftermath of Hurricane Harvey at that time..
With the increase in the amount of oil being refined this week, gasoline output from our refineries was likewise higher, increasing by 169,000 barrels per day to 10,384,000 barrels per day during the week ending September 7th, after our refineries’ gasoline output had decreased by 22,000 barrels per day during the week ending August 31st…again, due to Hurricane Harvey, our gasoline production during the week is not comparable to that of a year ago, but it was still 2.1% lower than what had been a record 10,602,000 barrels of gasoline that were produced daily during the week ending August 25th of last year…meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) rose by 97,000 barrels per day to a near record high of 5,536,000 barrels per day, after they had risen by 260,000 barrels per day over the prior week…for a rough year over year comparison absent hurricane impacts, we’d note this week’s distillates production was 9.5% higher than the 5,055,000 barrels of distillates per day that were being produced during the week ending August 25th, 2017….
With the increase in our gasoline production, our supply of gasoline in storage at the end of the weekrose by 1,250,000 barrels to 235,869,000 barrels by September 7th, the 13th increase in 29 weeks, and the 27th increase in 44 weeks, as gasoline inventories, as usual, were being built up over the winter months….our supplies of gasoline rose this week as the amount of gasoline supplied to US markets fell by 85,000 barrels per day to 9,649,000 barrels per day, after falling by 165,000 barrels per day the prior week, and as our imports of gasoline rose by 65,000 barrels per day to 1,053,000 barrels per day, while our exports of gasoline rose by 203,000 barrels per day to 680,000 barrels per day…after this week’s increase, our gasoline inventories were at another seasonal high, 8.0% higher than last September 8th’s level of 218,310,000 barrels, and roughly 10.3% above the 10 year average of our gasoline supplies for this time of the year…
Meanwhile, with big increase in our distillates production, our supplies of distillate fuels were likewise much higher, increasing by 6,163,000 barrels to 139,283,000 barrels during the week ending September 7th, the 12th increase in 16 weeks and the largest increase this year…the major reason our distillates supplies increased was because the amount of distillates supplied to US markets, a proxy for our domestic demand, fell by 1,002,000 barrels per day to 3,288,000 barrels per day, as domestic distributors apparently cut their purchases after having stocked up before the holiday….partially offsetting that, our exports of distillates rose by 429,000 barrels per day to 1,418,000 barrels per day, while our imports of distillates fell by 236,000 barrels per day to 50,000 barrels per day….however, with our distillate supplies still recovering from the 14 year seasonal low that they hit 6 weeks ago, this week’s big inventory increase still leaves our distillates supplies 3.6% below the 144,552,000 barrels that we had stored on September 8th, 2017, and roughly 6.9% lower than the 10 year average of distillates stocks for this time of the year…
Finally, with rising oil exports and near record refining of crude, our commercial supplies of crude oildecreased for the 20th time in 2018 and for the 31st time over the past year, falling by 4,302,000 barrels during the week, from 401,490,000 barrels on August 31st to 396,194,000 barrels on September 7th, which marks the first time our crude supplies were below 400,000 barrels since February 2015…however, even though our crude oil inventories are now about 3 percent below the five-year average of crude oil supplies for this time of year, they are still roughly 18.6% above the 10 year average of crude oil stocks for the first week of September, because it wasn’t early 2015 that our oil inventories first rose above 400 million barrels…but since our crude oil inventories have now been falling through most of the past year and a half, our oil supplies as of September 7th were 15.4% below the 468,241,000 barrels of oil we had stored on September 8th of 2017, 17.5% below the 480,166,000 barrels of oil that we had in storage on September 9th of 2016, and 6.5% below the 423,958,000 barrels of oil we had in storage on September 11th of 2015…
OPEC’s Monthly Oil Market Report
Next we’re going to review OPEC’s September Oil Market Report (covering August OPEC & global oil data), which was released on Wednesday and is available as a free download, and hence it’s the report we check for monthly global oil supply and demand data…the first table from this monthly report that we’ll look at is from the page numbered 58 of that report (pdf page 68), and it shows oil production in thousands of barrels per day for each of the current OPEC members over the recent years, quarters and months, as the column headings indicate…for all their official production measurements, OPEC uses an average of estimates from six “secondary sources”, namely the International Energy Agency (IEA), the oil-pricing agencies Platts and Argus, the U.S. Energy Information Administration (EIA), the oil consultancy Cambridge Energy Research Associates (CERA) and the industry newsletter Petroleum Intelligence Weekly, as an impartial adjudicator as to whether their output quotas and production cuts are being met, to thus resolve any potential disputes that could arise if each member reported their own figures…
As we can see on this table of official oil production data, OPEC’s oil output increased by 278,000 barrels per day to 32,565,000 barrels per day in August, from their July production total of 32,287,000 barrels per day….however, that July figure was originally reported as 32,323,000 barrels per day, so OPEC’s July output was therefore revised 36,000 barrels per day lower with this report (for your reference, here is the table of the official July OPEC output figures as reported a month ago, before this month’s revisions)…as you can tell from the far right column above, an increase of 256,000 barrels per day in the oil output from Libya was the major reason for this month’s increase, with increases of 90,000 barrels per day in oil output from Iraq and 74,000 barrels per day in output from Nigeria more than offsetting the decrease of 150,000 barrels per day in Iranian output…however, excluding new member Congo, OPEC’s August output of 32,245,000 barrels per day was still 485,000 barrels per day below the 32,730,000 barrels per day revised quota they agreed to at their November 2017 meeting, mostly due to the big drop in Venezuelan output, which has also been impacted by US sanctions…
The next graphic we’ll look at shows us both OPEC and global monthly oil production on the same graph, over the period from September 2016 to August 2018, and it’s taken from the page numbered 59 (pdf page 69) of the September OPEC Monthly Oil Market Report…on this graph, the cerulean blue bars represent OPEC oil production in millions of barrels per day as shown on the left scale, while the purple graph represents global oil production in millions of barrels per day, with the millions of barrels per day of global output shown on the right scale…
OPEC’s preliminary estimate indicates that total global oil production rose by a rounded 490,000 barrels per day to a record high 98.88 million barrels per day in August, after July’s global output total was revised down by 140,000 barrels per day from the 98.53 million barrels per day global oil output that was reported a month ago, as non-OPEC oil production rose by 210,000 barrels per day in August after that revision….global oil output for August was also 2.13 million barrels per day, or 2.2% higher than the 96.75 million barrels of oil per day that were reported as being produced globally in August a year ago (see the September 2017 OPEC report online (pdf) for the year ago details)…with the increase OPEC’s output, their August oil production of 32,565,000 barrels per day represented 32.9% of what was produced globally during the month, up from their 32.8% of global share reported for July…OPEC’s August 2017 production was at 32,755,000 barrels per day, which means that the 13 OPEC members who were part of OPEC last year, excluding new members Congo and Equatorial Guinea, are still producing 637,000 fewer barrels per day of oil than they were producing a year ago, during the eighth month that their production quotas were in effect, with the 638,000 barrel per day decrease in output from Venezuela from that time responsible for the cartel’s output drop…
Despite the 490,000 barrel per day increase in global oil output in August, elevated summertime demand meant that we again saw a deficit in the amount of oil being produced globally during the month, as this next table from the OPEC report will show us…
The table above comes from page 32 of the September OPEC Monthly Oil Market Report (pdf page 42), and it shows regional and total oil demand in millions of barrels per day for 2017 in the first column, and OPEC’s estimate of oil demand by region and globally quarterly over 2018 over the rest of the table…on the “Total world” line of the fourth column, we’ve circled in blue the figure that’s relevant for August, which is their revised estimate of global oil demand during the third quarter of 2018…
OPEC’s estimate is that during the 3rd quarter of this year, all oil consuming regions of the globe have been using 99.38 million barrels of oil per day, which was a downward revision of 0.06 million barrels of oil per day from their prior consumption estimate for the quarter….meanwhile, as OPEC showed us in the oil supply section of this report and the summary supply graph above, the world’s oil producers were producing 98.88 million barrels per day during August, which means that there was a still a shortfall of around 500,000 barrels per day in global oil production vis-a vis the demand estimated for the month…
While global demand for the 3rd quarter was revised 0.06 million barrels per day lower, total global oil output for July was revised down by 140,000 barrels per day at the same time, which means the global shortfall of 910,000 barrels per day that we had figured for July last month would now be revised to 990,000 barrels per day…also notice that this report revised oil demand figures for the 1st and second quarters, which we’ve circled in green; that means our previous estimates of surplus or shortfall for those months will have to be revised as well…a month ago, we estimated there was a shortfall of around 70,000 barrels per day in global oil production vis-a vis the demand in June, a shortfall for May of 510,000 barrels per day, and a shortfall in April of 320,000 barrels per day… but as we see in the green ellipse above, oil demand for the 2nd quarter was revised 10,000 barrels per day lower, so our revised global oil shortfalls for the 2nd quarter months will thus be 60,000 barrels per day for June, 500,000 barrels per day for May, and 310,000 barrels per day for April…
while global oil demand figures for the second quarter were revised lower, global oil demand figures for the first quarter of 2018 were revised 60,000 barrels per day higher, which means that our previously recomputed oil surplus for the first quarter of 2018 will also have to be recomputed again….since we had last figured a global oil output surplus of 120,000 barrels per day for March, a surplus of 300,000 barrels per day for February, and a surplus of 140,000 barrels per day for January, that revision means that our new figures will show a surplus of 60,000 barrels per day for March, a surplus of 240,000 barrels per day for February, and a surplus of 80,000 barrels per day for January….totaling up all these 8 monthly estimates of surplus or shortfall, we find that for the first eight months of 2018, global oil demand exceeded production by roughly 61,370,000 barrels, actually a comparatively small net oil shortfall that is the equivalent of roughly 15 hours of global oil production at the August production rate…
This Week’s Rig Count
US drilling activity increased for the seventeenth time in twenty-five weeks during the week ending September 14th, even as the steady increases in drilling for oil we saw with higher oil prices during the first part of this year have stalled since May, with oil futures’ prices remaining in backwardation, albeit now less so than in recent weeks….Baker Hughes reported that the total count of rotary rigs running in the US increased by 7 rigs to 1055 rigs over the week ending on Friday, which was 119 more rigs than the 936 rigs that were in use as of the September 15th report of 2017, but was still down from the shale era high of 1929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began their attempt to flood the global oil market…
The count of rigs drilling for oil was up by 7 rigs to 867 rigs this week, which was also 118 more oil rigs than were running a year ago, while it was well below the recent high of 1609 rigs that were drilling for oil on October 10, 2014…at the same time, the number of drilling rigs targeting natural gas formations was unchanged at 186 rigs this week, which was also unchanged from the 186 natural gas rigs that were drilling a year ago, but way down from the modern high of 1,606 natural gas rigs that were deployed on August 29th, 2008…meanwhile, two rigs drilling exploratory wells in central Ohio considered to be “miscellaneous” continued to operate this week, an increase from just one such “miscellaneous” rig a year ago…
Offshore drilling in the Gulf of Mexico saw a net increase of 1 rig to 18 rigs, up from 17 Gulf of Mexico rigs a year ago…in addition, two rigs continued to drill offshore from Alaska this week, so the total national offshore count is now at 20 rigs, which is thus up by 3 rigs from last year’s total of 17 offshore rigs, since a year ago there was no offshore drilling other than in the Gulf…in addition, two more rigs began drilling through inland bodies of water in southern Louisiana this week, where there are now five such rigs operating, up from the 4 rigs that were drilling through inland waters there a year ago…
The count of active horizontal drilling rigs was up by 3 rigs to 921 horizontal rigs this week, which was also 126 more horizontal rigs than the 795 horizontal rigs that were in use in the US on September 15th of last year, but down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014…in addition, the directional rig count increased by 6 rigs to 71 directional rigs this week, which was still down from the 74 directional rigs that were in use during the same week of last year…on the other hand, the vertical rig count was down by 2 rigs to 63 vertical rigs this week, which was also down from the 67 vertical rigs that were operating on September 15th of 2017…
The details on this week’s changes in drilling activity by state and by shale basin are included in our screenshot below of that part of the rig count summary pdf from Baker Hughes that shows those changes…the first table below shows weekly and year over year rig count changes for the major producing states, and the second table shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of September 14th, the second column shows the change in the number of working rigs between last week’s count (September 7th) and this week’s (September 14th) count, the third column shows last week’s September 7th active rig count, the 4th column shows the change between the number of rigs running on Friday and those on the equivalent weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was on Friday the 15th of September, 2017…
Louisiana saw a three rig increase despite having a land based rig shut down in the southern part of the state because of a two rig increase on inland waters and because two additional Gulf of Mexico rigs were in state waters, while one rig offshore from Texas was idled…meanwhile, the three rig increase in Pennsylvania includes two rigs targeting the Marcellus and one rig targeting the Utica….the Utica shale count remained unchanged, however, because a Utica shale rig in Ohio was shut down at the same time…meanwhile, the natural gas rig count remained unchanged because 2 rigs targeting natural gas basins not tracked separately by Baker Hughes were shut down at the same time…all other activity shown above is oil directed, again with basins not tracked by Baker Hughes not shown…
Oil and gas industry ‘here to stay’ in Harrison County – Nearly two dozen elected officials met in Harrison County on Tuesday for an update on the oil and gas industry. The meeting, held at the Tappan Lake Marina, was led by two oil and gas representatives who say the industry is here to stay. “Oil and gas has been here for 8-9-10 years now, so it’s very prevalent here to stay for the next 30-40 years, so it’s better to keep everyone informed,” said Nick Homrighausen, executive director of community and economic development for the county. “We covered all aspects of oil and gas. We talked about what was happening in the upstream industry. There’s been a lot of deals this summer. … There’s a lot of movement there, and we wanted to explain some of that,” said Mike Chadsey, Director of Public Relations, Ohio Oil and Gas Association. Closing those new deals has allowed for continued growth across the county within the industry. Chadsey explained that he views Harrison County as one of the leader in downstream, upstream and midstream potential. “It’s really the heart of the Utica Shale Play,” Chadsey said. “And we take all responsibility to engage with elected officials and talk about the industry very seriously.” With five major pipeline projects in the community right now, organizers felt now was the time for an update. “Everyone is waiting on that ethane cracker plant which we anticipate, fingers crossed, hopefully our final investment decision here soon,” Chadsey said. “It’s really a lot of exciting times in Harrison County and really all of southeast Ohio.”
Ohio on receiving end of fracking waste – Warren Tribune Chronicle – Residents working to fend off a proposal to place a wastewater injection well along Hubbard Masury Road said this fight is about more than just their community.One trustee thinks it sends the wrong message about the entire state of Ohio.“We’ve absolutely become a dumping ground,” said Rick Hernandez. Data from the Ohio Department of Natural Resources shows from 2012 to so far in 2018, more than 91 million barrels of brine from the hydraulic fracturing, or fracking, industry in Ohio have been injected into class II injection wells in Ohio. That equates to more than 3.8 billion gallons of brine – a salt / water mix used to extract natural gas from below ground shale formations. ODNR numbers also show that more than 85 million barrels – 3.5 billion gallons – of brine produced outside the state have been injected into Ohio’s injection wells between 2012 and so far this year. Steve Irwin, ODNR spokesman, said the regulatory environments in Ohio and Pennsylvania may lead drilling companies to choose to inject their waste in Ohio. Irwin said ODNR has “primacy” to regulate the state’s oil and gas industry, meaning companies that want to establish injection wells in Ohio can apply for permits directly from ODNR. On the other hand, Pennsylvania’s oil and gas industry is regulated by both the state’s Department of Environmental Protection and the U.S. Environmental Protection Agency, which increases the permit application time and expense because a prospective injection company needs a permit from both agencies. State Rep. Glenn Holmes, D-Girard, has introduced House Bill 723 that would cap the number of injection well permits the chief of ODNR’s Division of Oil and Gas Resources Management can issue at 23 per county. Ohio has 216 active injection wells, according to ODNR. Trumbull and Ashtabula counties top the list with 17 active wells apiece. Next are nearby Portage and Stark counties with 16 each followed by Meigs County in southeast Ohio with 14. The legislation also would mandate the division chief to notify relevant state legislators whenever a request for a well permit is made. It’s expected the bill will be assigned to a committee when the General Assembly returns from its summer recess. State law allows Ohio to benefit financially from accepting fracking waste from other states. The state charges a 5-cent fee for the injection of each barrel of brine that is produced in Ohio. Conversely, the fee for the injection of each barrel of out-of-state brine is 20 cents.
Cabot to drill two more exploratory wells in Ohio by Dec. 31 — Cabot Oil & Gas has drilled three exploratory wells in north-central Ohio and intends to add two additional wells before the end of the year, Kallanish Energy reports. The three wells drilled are all in Ashland County, between Cleveland and Columbus. That drilling began last June. The wells are in Green, Vermilion and Mohican townships north and northeast of Loudonville. One of the three wells has been hydraulically fractured. The Houston-based company, a major player in the Marcellus Shale in Pennsylvania, reported it is unclear where the fourth and fifth well will be drilled, it told the Columbus Dispatch newspaper last week. The company is interested in the Knox formation in Ashland, Richland, Holmes, Wayne and Knox counties at the western edge of Ohio’s Utica Shale. That formation is below the Utica, and is north and west of Ohio’s main Utica drilling area. Cabot Oil & Gas had announced plans to spend $75 million in the first half of 2018 to look closely at two exploratory areas. The company gave no clue as to where that exploratory wells might be drilled. If the tests reveal that additional drilling is warranted in the second half of 2018, Cabot is prepared to sell off assets to fund that work, the company said in releasing its 2018 operating plan. It later announced it had scrapped one exploration area as a failure. Analysts said that was likely the High Alpine area of Texas. Ashland County is where Oklahoma-based Devon Energy drilled for oil in the early days of Utica Shale drilling – with little or no success.
National Forests Being Impacted by Marcellus Drilling, Fracking and Pipelines The withdrawal of two mineral leases set to be auctioned later this month in the Wayne National Forest was received with relief from an organization that had protested the proposal and frustration from the state trade organization for oil and gas interests. The two plots, one of 35 acres and the other about 40 acres, are in Monroe County, and the mineral leases were scheduled for auction Sept. 20, according to an announcement in July by the Bureau of Land Management. The BLM announced Aug. 28 that the auction was canceled, citing Title 43 Code of Federal Regulations, paragraphs 3120.1-3, but offering no further explanation. That part of the code refers to suspending the offering of a parcel while an appeal is under consideration. Wendy Park, a senior lawyer for the Center for Biological Diversity, said Wednesday that her organization’s protest was the only one she could find that was lodged against the lease offering. She said the center opposed the lease because of its potential impact on nearby water bodies and settled areas. “This is the first time the feds have pulled parcels from a Wayne National Forest lease auction after approving its fracking plan for the Wayne, in response to environmentalists’ concerns,” she said. When the 400,000 acres of the Wayne National Forest was opened to oil and gas extraction leasing in 2016, she said, the environmental impact examination was general rather than site specific, and the leases offered since then have not taken local conditions into account. “This is pretty much what we’ve been saying in all our protests, that they’re not taking a hard look at the impact of fracking on site-specific resources,” she said. In addition to endangered species of bats, she said, there also are public health and cultural concerns. “There are homes and communities near these leases, and toxic chemicals and air pollution would certainly have an impact on the health of local residents,” she said. “They also have failed to comply with the obligation to make sure cultural and historical resources are not harmed.” The Ohio Oil and Gas Association, however, was not pleased by the decision, and its spokesman Mike Chadsey said the association members are frustrated with the federal government.
Haunting Poems and Photos From a State Torn by Fracking — When Julia Spicher Kasdorf pulled off Pennsylvania’s Route 15 on her way upstate in 2012, she noticed something she’d never seen before. Across the highway, by the restaurant where she and her husband stopped for lunch, helicopters dangling strange pendants were hovering over the mountainside. Kasdorf, a poet and English professor at Pennsylvania State University, asked her server what was going on. “Those guys are here because of fracking,” the waitress said. Oil and gas companies were doing seismic testing for a new pipeline. Kasdorf grew up in central Pennsylvania surrounded by dairy farms. She’d seen the way coal mining had ravaged the state’s southwest, but this destruction was new. Determined to keep an open mind, she began seeking out stories from people affected by fracking. Her curiosity turned into a six-year project and a collaboration with documentary photographer Steven Rubin that culminated in their recent book, Shale Play: Poems and Photographs from the Fracking Fields. Her conversation at a roadside restaurant inspired the opening poem, “Fry Brothers Turkey Ranch with Urbanspoon and Yelp Reviews.” Here’s a snippet:
Report: More than half of Pennsylvania gas wells used ‘secret’ fracking chemicals — Energy companies in Pennsylvania did not identify potentially harmful chemicals used for drilling and fracking for natural gas in more than half of the wells created between 2013 and 2017, according to a recently released report. The report, from the Partnership for Policy Integrity, a nonprofit based in Massachusetts that does energy research and advocacy, says companies withheld information about at least one chemical in 55 percent of wells drilled between 2013 and 2017. Dusty Horwitt, who wrote the report, said that health effects of so-called secret chemicals can’t be ascertained if the chemical’s identity is not disclosed, but he also said that the public has a right to know about all the chemicals used. “We cannot be sure of the effects of any chemical whose identity is withheld as secret,” Horwitt said. “However, EPA records indicate that the fracking chemicals declared security in Pennsylvania may have serious negative health effects.” However, even if the companies do not publicly disclose every chemical, according to state and federal law, they are required to disclose all chemicals to the EPA and DEP. “State and federal law requires hydraulic fracturing fluids – which are typically made up of more than 99 percent water and sand, and less than 1 percent of highly diluted additives that we all commonly use in our everyday lives – to be transparently disclosed via an online, searchable database. Our organization – which represents the energy companies responsible for safely producing more than 95 percent of Pennsylvania’s natural gas – was an early and vocal supporter of greater transparency and disclosure. Pennsylvania has some of the strongest environmental rules in the nation and we’re committed to continuously improving best practices to protect and improve our environment.” Marcellus Shale Coalition president David Spigelmyer. Frac Focus is the national hydraulic fracturing chemical registry. The site provides public access to reported chemicals used for hydraulic fracturing.
Beaver County Pipeline Explosion Destroys Home, Prompts Evacuations – Beaver County officials say an early morning methane gas pipeline explosion in Pennsylvania destroyed one home and prompted an evacuation of others. The blast in Center Township was reported shortly before 5 a.m. Monday. Officials say a home, two garages and several vehicles were destroyed by fires stemming from the explosion. No injuries have been reported and crews were able to move several horses to safety. The community of Center Township is located roughly 25 miles northwest of Pittsburgh. Witnesses reported hearing a loud boom and seeing an orange glow fill the sky. Pipeline owner Energy Transfer Partners says the valves to the pipeline were shut off and the fire was out by 7 a.m. The 100-mile pipeline, known at the Revolution line, began operating earlier this month. It was built to supply the company’s Rover pipeline and Mariner East 2 lines. About 25 to 30 homes were evacuated as a precaution. The Central Valley school district canceled classes. Interstate 376 was closed due to danger from falling power lines. In June, a newly-built TransCanada natural gas pipeline exploded near Moundsville, West Virginia. No injuries or damage to private property were reported, but a fireball burned for several hours after an 83-foot section of the pipeline burst into flames, releasing more than $430,000 worth of natural gas. The Pipeline and Hazardous Materials Safety Administration said shifting land likely triggered the explosion of the Leach Xpress pipeline.
Revolution Pipeline Explosion After a Week of Operation Burns Up One Home & Two Barns, Horses are Saved – An explosion from a natural gas pipeline operating for only a week sparked a fire early Monday that destroyed a Beaver County home and two garages and prompted authorities to evacuate about two dozen other homes in the area. The 24-inch pipeline’s owner, Dallas-based Energy Transfer Corp., said it was investigating but an early assessment of the explosion site showed there had been “earth movement in the vicinity of the pipeline.” Center police Chief Barry Kramer attributed that to heavy, continuous rain over the weekend, but he said he’d leave determining the exact cause “up to the experts.” Nearly 5 inches fell between Friday night and Monday morning, according to the National Weather Service. An orange glow lit up the dark-morning sky after the fire began along Center Township’s Ivy Lane around 5 a.m. “It was just a huge fireball. My house was shaking,” said Ivy Lane resident Toni DeMarco, 54. Another Ivy Lane resident, 64-year-old Karen Gdula, heard what she said sounded like an 18-wheel tractor-trailer idling outside her bedroom window before the blast. “The ground shook,” Gdula said. “It looked like it was noon and it was 5 a.m. The flames were shooting higher than the pine trees.” Residents of between 25 and 30 homes on Ivy Lane and Pine Drive were evacuated to a nearby fire social hall along Brodhead Road and were being assisted by the American Red Cross. Authorities closed busy Brodhead Road, which is connected with Ivy Lane, and Interstate 376 between the Center and Aliquippa interchanges. About 1,500 people lost power after the explosion brought down six high-tension electrical towers, according Kramer. Central Valley School District also canceled classes.
ETP Pipeline Explosion Unlikely to Impact Appalachian Natural Gas Production – An explosion that ripped through an Energy Transfer Partners LP (ETP) pipeline in Western Pennsylvania early Monday isn’t likely to disrupt production significantly, as the system serves an older part of the Marcellus Shale where fewer producers operate, compared to other parts of the basin. Torrential rain and saturated ground likely caused the line to slip and explode, the company said, but the exact cause remains unclear as an investigation is underway. The pipeline was placed into service last week and is part of the broader Revolution system, which gathers wet gas and includes a 30-inch diameter pipeline and has a capacity of more than 400 MMcf/d. At the time of the blast, the company was in the process of purging and packing the gathering lines that feed ETP’s Revolution Plant in Washington County, where construction was recently completed. The plant would deliver tailgate volumes to affiliate Rover Pipeline’s Burgettstown lateral.The explosion is unlikely to have any meaningful impacts on the line’s producer customers or other interstate pipelines, such as those owned by Columbia Gas Transmission LLC or National Fuel Gas Co., in the area, Genscape Inc. analyst Vanessa Witte said. ETP in 2015 inked a long-term deal with privately owned EdgeMarc Energy Holdings LLC, announcing at the time that it would build the cryogenic gas processing plant, a fractionator and the gathering lines to facilitate the agreement. EdgeMarc has subscribed to more than 160 MMcf/d on Rover. Witte said the incident could limit some volumes from reaching the Burgettstown lateral, which was only recently authorized for service by the Federal Energy Regulatory Commission and has shown no scheduled nominations yet. ETP has also said there are other producer customers subscribed to the Revolution system, but it’s unclear who they are.
ETP to Inspect Entire Blast-Damaged Gas Pipeline in Pennsylvania – Energy Transfer Partners LP (ETP) representatives said late Monday the company plans to inspect the entire 24-inch diameter segment of the Revolution pipeline system that runs from Butler County, PA, to Washington County, PA, after part of it exploded during commissioning operations earlier in the day.“We’ll be inspecting the full line, looking at areas where, with all of this rain, there may be other areas that we need to take a look at and go back in to do some additional work,” said spokesperson Vicki Granado, who traveled from Dallas to address news media and local residents from Center Township in Beaver County, PA, where the ruptured pipeline destroyed a house, garage and multiple vehicles. There were no injuries.Heavy rain that has fallen throughout the region since late last week finally moved out Monday. However, ETP management suspects that unstable ground caused the pipeline, which is buried about three feet below the surface, to slip and explode. The impacted section was isolated and the fire extinguished itself once the gas flow was cut.“The gas caught some ignition source when it leaked out,” said Center Township Police Chief Barry Kramer, when asked to describe the accounts of residents living nearby who were evacuated for part of the day. “I don’t think there was time to smell it. It happened relatively quickly, although I don’t know that for sure.”
Pipeline that Exploded in Pennsylvania Part of Push to Build Fracking-Reliant Petrochemical Network – DeSmog (blog) A column of fire shot 150 feet in the air and destroyed a home, a barn, and several cars. Residents of over two dozen homes, including Belczyk, were evacuated, with one family barely escapingthe flames that engulfed their home, neighbors said. Interstate 376 was shut down amid concern over falling power lines, including a half-dozen high tension towers, which left 1,500 people temporarily without electricity. No one was injured or killed by the blast, authorities said, and because of recent rains, the possibility of a forest fire was averted. The 24″ diameter pipeline responsible for the blast had gone into service just seven days earlier. It’s owned by Energy Transfer Partners, the same pipeline company behind the Dakota Access Pipeline project and the Bayou Bridge pipeline in Louisiana. The Pennsylvania Public Utility Commission has said it suspects that the blast was caused by heavy rainfall, which they believe may have caused the pipeline to slip on the saturated ground, break, and then explode. Energy Transfer Partners dubbed its new “gathering” line the Revolution pipeline. Revolution was built to connect individual gas wells to a new cryogenic plant, the Revolution gas processing plant, where so-called “wet gas” from Marcellus wells would be separated into natural gas liquids and dry gas. From the Revolution plant, that dry natural gas, a fossil fuel made of methane that’s used for electricity and heat, would be shipped west direction on the 725 mile Rover pipeline. Natural gas liquids like ethane, which is used to make plastics and petrochemicals, would head out on the Mariner East 2 pipeline to a shipping terminal near the Atlantic Coast, where it could be shipped to the Gulf Coast or abroad. By providing a path for the liquids and gas to flow to market, the Revolution gathering line would facilitate the drilling and fracking of roughly 500 Marcellus and Devonian wells in just one Pennsylvania County, Butler County, alone, officials from the company building the cryogenic plant saidin 2015, when the deal was announced. Or at least that was Energy Transfer’s $1.5 billion plan. All three pipelines have been plagued by construction problems, particularly the much larger Mariner East natural gas liquids pipeline project. In the meantime, Energy Transfer Partners has faced strong pressure to finish the project from shale drillers, who aim to sell ethane for a higher price than it commands when it’s left mixed in with methane.
Mariner East Facing Additional Scrutiny After ETP Pipeline Explosion — Pennsylvania lawmakers on both sides of the aisle are again airing concerns this week about natural gas pipeline projects, calling on Energy Transfer Partners LP (ETP) to halt construction of the Mariner East (ME) 2 and 2X projects, after a gathering system in the western part of the state exploded on Monday.Democratic state Sen. Andrew Dinniman, who filed a complaint with the Pennsylvania Public Utility Commission (PUC) earlier this year that eventually led to a construction suspension on parts of the ME projects that is partially in effect, said on Twitter the incident in Beaver County’s Center Township is a “chilling reminder” of just how “powerful and dangerous these pipelines can be.”The infrastructure “shouldn’t be so close to our schools, residential neighborhoods and community centers. Mariner East should be permanently halted until we get real assurance that they’re being installed, inspected and operated with safety as the top priority.”Dinniman, who represents Chester County where sinkholes formed near the ME project earlier this year, was joined by another lawmaker from the area, Republican state Rep. Chris Quinn, in calling for work to stop.“While I’m relieved to know that no injuries occured, I also realize that this area of Beaver County is far less dense than the pipeline corridor in Delaware County,” Quinn said of a heavily populated area where the ME system is located. “A similar incident in my district could be even more destructive and have a greater human toll.“Therefore, I’m calling for an immediate halt to all pipeline construction activities,” Quinn added of the ME project. “This pipeline should not be built until the real and legitimate safety and environmental concerns raised by myself and local residents have been fully addressed.” Republican state Sen. Tom McGarrigle, who represents constituents near the ME projects, also called on ETP to stop construction until a full investigation of the Beaver County incident has been completed.
25 zones along the proposed Shell Falcon Pipeline are at risk of explosions due to landslides – EHN – Shell Pipeline Company has identified 25 locations that are prone to landslides in or near the route of its proposed Falcon Ethane Pipeline through Pennsylvania, Ohio, and West Virginia. Fourteen of those locations are in Southwestern Pennsylvania. The Falcon Pipeline is just one piece of a massive network of unconventional oil and gas-related infrastructure being built by Shell and its affiliates and business partners in Pennsylvania with the aim of turning the region into a new petrochemical hub. The development has elicited concern from researchers, residents and environmental groups about the increased risk of explosions and spills, as well as the cumulative impact on air and water quality in the region. Two of the sites identified by Shell as being prone to landslides along the proposed Falcon Pipeline route are in Allegheny County. The other 12 sites are in Beaver County – 35 miles west of Pittsburgh – where on Monday a natural gas pipeline not affiliated with Shell exploded, destroying one home, two garages, a barn, and several vehicles. The explosion, in a brand new section of Energy Transfer Partners’ Revolution Pipeline, is being attributed to a landslide following heavy rains over the weekend. This isn’t the first time a landslide has caused a natural gas pipeline to explode: In June, landslides resulted in the rupture and explosion of a TransCanada natural gas pipeline in Marshall County, West Virginia.Shell is currently constructing a multi-billion dollar ethane cracker plant in Potter Township, just five miles from the site of the Energy Transfer Pipeline explosion. Shell’s proposed Falcon Pipeline would transport large volumes of natural gas and liquids to the ethane cracker plant to be converted into ethylene for use in plastics manufacturing. In its permit application, Shell identified “landslide risk” areas along the proposed route for the Falcon Pipeline. The FracTracker Alliance, a Pittsburgh-based oil and gas industry watchdog group, has mapped those locations. In Pennsylvania, the 14 landslide-prone areas on or near the proposed pipeline route total 2.1 miles.
Spill sends diesel fuel into Arthur Kill — Authorities were at the scene of a spill at the Buckeye Terminal in Port Reading that sent an unknown amount of diesel fuel into the Arthur Kill Waterway, officials said Friday. The mishap was reported around 7:15 p.m Thursday and occurred during a product transfer at the terminal, according to the U.S. Coast Guard. “Due to high winds and rain at the time of the incident, facility personnel were unable to calculate the exact amount of fuel spilled into the waterway,” the Coast Guard said in a statement. “All fuel transfers at the facility are temporarily suspended until investigators can determine the cause of the spill and the facility can safely conduct fueling operations,” the statement said. A representative for the Buckeye Terminal could not be immediately reached. The Coast Guard said it deployed a pollution response team to the scene and an oil spill removal company was called to handle the cleanup. Crews put a containment boom in the water. More information was not immediately available Friday. The cause of the spill was being investigated.
Man killed, 12 injured after 70 gas explosions, fires rock Lawrence, Andover, North Andover – WHDH – – At least one person has died and 13 others were injured when as many as 70 gas-related explosions and fires rocked multiple homes and buildings in Lawrence, Andover and North Andover Thursday night, prompting officials to order widespread evacuations and establish emergency shelters. In the wake of the explosions, which were first reported around 5 p.m., all Columbia Gas customers in Lawrence, Andover and North Andover have been urged to evacuate immediately and National Grid has turned off power in all three communities.Gov. Charlie Baker joined city officials from Lawrence, Andover, and North Andover during a 9 p.m. press conference to stress to area residents to leave their homes and seek shelter at one of the many emergency shelters that have been set up to handle the thousands of displaced. Crews are working to depressurize gas lines across the region but the process may take quite some time.Lawrence police say a woman who was left trapped in a home on Chickering Road suffered leg injuries.The Essex District Attorney’s Office said 18-year-old Leonel Rondon was killed when a chimney fell onto his car.Andover town officials say at least four people were injured, including two firefighters and two civilians.At the peak of the chaos, 18 fires were burning at the same time in Andover. Video from Sky7 HD showed fires burning at multiple homes and buildings. One home appeared to be completely leveled and many others were seriously damaged. The total number of affected structures is expected to climb throughout the evening.Lawrence Mayor Dan Rivera has ordered all residents to evacuate the southern section of the city.Fire departments from across the region, including Boston, Methuen and New Hampshire, are responding to the impacted areas.The Red Cross and FEMA are also responding. All off-ramps along Interstate 495 between exits 41 and 45 have been closed until further notice. Service on the Haverhill commuter rail line has been temporarily suspended beyond North Wilmington Station.Shelters have been set up at Lawrence High School, North Andover Middle School, and at the Andover Senior Center. The Red Cross has set up three reception centers for people who have evacuated their homes:
Thousands of residents still out of their homes after gas explosions trigger deadly chaos in Massachusetts – Massachusetts Gov. Charlie Baker (R) declared a state of emergency Friday as officials inspected more than 8,600 homes and businesses to determine if it was safe for people to return, a day after a series of gas line explosions left one person dead and injured at least 23. The blasts, which led to scores of simultaneous structure fires across three towns in the Merrimack Valley, filled otherwise sunny skies with thick smoke and pushed thousands of residents out of their homes indefinitely. Electrical power has been cut to the communities, and residents have been told not to enter their homes until each one has been inspected for potential dangers. Columbia Gas of Massachusetts, which owns the gas lines involved in the blasts, has thus far given no indication of what might have caused the disaster. Baker and other officials, including Lawrence Mayor Dan Rivera, issued scathing criticisms of the company. “Since yesterday, when we first got word of this incident, the least informed and the last to act have been Columbia Gas,” Rivera said, with Baker at his side at a news conference. He said that the company had promised “hundreds of teams of technicians” but that “none have materialized.” “It just seems that there’s no one in charge,” Rivera said. “Like they’re in the weeds.” At a news conference a couple of hours later, Columbia Gas President Steve Bryant defended the company’s response. “We advanced this as rapidly as it could possibly be advanced,” he said. “I don’t think that anybody else managing this would have been further down the road then we are at the moment.” Bryant said the company had nearly 300 technicians in the field who had turned off gas to more than 3,200 of the affected customers, a necessary step before electricity can be restored. He said gas would be shut off to all homes in the area by Saturday or Sunday, allowing power to be turned back on and people to move back in. He referred questions about the cause of the incident to the National Transportation Safety Board (NTSB), which is leading the investigation.
Company Involved in Massachusetts Gas Explosions Has History of Blasts – As thousands of people were fleeing their coastal homes in the Carolinas yesterday, thousands more were forced from their homes in Lawrence, Andover, and North Andover, Massachusetts yesterday. The Massachusetts evacuations came without prior warning as more than 60 homes erupted in flames yesterday and at least three exploded from a natural gas malfunction involving the utility company, Columbia Gas of Massachusetts.Andover Fire Chief Michael Mansfield told local reporters that “It looked like Armageddon,” saying he could see “billows of smoke coming from Lawrence behind me” and “pillars of smoke in front of me from the town of Andover.”The Associated Press reported that “some local officials described scenes of panic as residents rushed to evacuate, many wondering if their homes would be next to erupt in flames. In North Andover, town selectman Phil Decologero said his entire neighborhood had gathered in the street, afraid to enter their homes. Just a few streets down, he said, homes were burning.”As of early this morning, local news channels were reporting one person was dead and approximately 25 individuals were injured in the fires. The Massachusetts Emergency Management Agency has initially suggested the possibility that gas lines became over-pressurized but a full investigation will be conducted, including one by Federal authorities including the National Transportation Safety Board.In a statement on their website, Columbia Gas referred to the disaster as an “incident” and said “crews need to visit each of the 8,600 affected customers to shut off each gas meter and conduct a safety inspection.” Yesterday, just hours before chaos would descend on the three towns in Massachusetts, Columbia Gas sent out a letterindicating it would be “upgrading natural gas lines in neighborhoods across the state.” The letter linked to a video which carried this statement in the accompanying text:“As with many other types of infrastructure, like roads, dams, and bridges, deterioration occurs over time and repairs or replacement are eventually needed. The old gas pipes installed in your neighborhood generations ago served us well, but they are now ready to be retired.” Pipes installed “generations ago” raise the question as to whether the pipes should have been upgraded long before now. The video shows deeply corroded metal pipes being replaced with “state-of-the-art plastic” pipes “more suited for underground use.”
FERC schedule slips for Transco project as NY primary politics complicate path for gas – The US Federal Energy Regulatory Commission has pushed back the timeline for completing its environmental review of Transcontinental Gas Pipe Line’s Northeast Supply Enhancement Project to January 25, 2019, from September 17, 2018. The revised schedule adds to the federal review timeline for a protect (CP17-101) that would allow for as much as 400 MMcf/d of incremental supply into New York markets and potentially place downward pressure on Transco Zone 6 pricing. The project is viewed as facing headwinds in state reviews in New Jersey, as well as in New York, where opposition to natural gas has played into the Democratic primary, set for Thursday. Transco spokesman Christopher Stockton said the company is assessing FERC’s updated schedule, “but we currently do not believe it will negatively impact the project’s winter 2020 [in-service date].” Williams in August moved its targeted start to the fourth quarter of 2020. FERC said the change was based on the status of the project’s general conformity review with state implementation plans to meet national air quality standards, as well as feasible mitigation options. The NESE project entails a new compressor station in Somerset County, New Jersey, as well as installation of about 23.5 miles of pipeline in the New York Bay, 3.5 miles of pipeline in Middlesex County, New Jersey and 10 miles of 42-inch-diameter pipeline in Lancaster County, Pennsylvania. Washington Analysis in a note said the new FERC schedule “underscores a difficult state-level review path that colors our bearish outlook for the pipeline’s chances of being built.” It said the delay of the final environmental report will delay the start of critical state reviews. While the project has filed with New York and New Jersey for Clean Water Act Section 401 certifications, state officials have made clear they will not consider the application complete without the final environmental impact statement, Washington Analysis noted. Also pending are determinations under the Coastal Zone Management Act.
Pipeline spills 8K gallons of fuel into Indiana river | TheHill — A Houston-based company says one of its pipelines has spilled more than 8,000 gallons of jet fuel into a river in Indiana. Buckeye Pipe Line says it shut the line down immediately when it found the pressure problem Friday night, The Associated Press reported on Sunday. Local officials say they have placed booms in St. Marys River, the body of water into which the fuel spilled, and are vacuuming the oil off the surface, the AP reported. The cleanup may take weeks, according to Decatur Mayor Kenneth L. Meyer. The Environmental Protection Agency said it’s monitoring the air around the area, as well as the water quality at a few places downstream from the contamination, according to the AP.
Pipeline Spills More Than 8,000 Gallons of Jet Fuel Into Indiana River – A pipeline spilled more than 8,000 gallons of jet fuel into an Indiana river, The Associated Press reported Sunday.The affected river was St. Marys River in Decatur, which is a town of 9,500 people about 100 miles from Indianapolis.Cleaning the spill could take weeks, Decatur Mayor Kenneth L. Meyer told the Fort Wayne, Indiana-basedJournal Gazette.The spill was first reported Friday night in a safety warning issued by the Decatur Police Department urging residents to avoid the area around the spill, local news outlet WANE reported Saturday.Houston-based Buckeye Pipe Line Company, L.P., which owns the pipeline, confirmed the spill to WANE Saturday.Company officials said there had been a failure Friday evening that had caused the spill. “One of their workers discovered a pressure drop, went immediately to check on it and immediately shut it down,” Allen County Homeland Security Director Bernie Beier told The Journal Gazette.The pipeline will remain shut off until it is repaired and safe to operate, and Buckeye’s Emergency Response Team worked to control the spill and clean the area, WANE reported. The company is investigating the cause of the failure.
CSX derailment and oil spill leads to federal lawsuit – – Federal and state officials accuse CSX Transportation of several environmental torts in response to oil spilled from a derailed train.The United States of America, the state of West Virginia and the West Virginia Department of Environmental Protection filed a complaint in U.S. District Court for the Southern District of West Virginia against CSX Transportation Inc. According to the complaint, a CSX train derailed in February 2015 and spilled oil into the Kanawha River and Armstrong Creek. The spill also affected the land around the waterways. Government officials allege the spilled oil violated the West Virginia Water Pollution Control Act, West Virginia Groundwater Protection Act, and Clean Water Act.The plaintiffs seek civil penalties up to $2,100 per barrel of oil discharged for violation of the Clean Water Act, civil penalties up to $25,000 per day for violation of the West Virginia Water Pollution Control Act and civil penalties up to $25,000 per day for violations of the West Virginia Groundwater Protection Act. They are represented by Devon A. Ahearn of Department of Justice in Washington, Fred B. Westfall, Jr. of Department of Justice in Charleston and Lauren E. Ziegler of Environmental Protection Agency in Philadelphia.
Orphan Wells: States Wrestle With Soaring Costs For Oil & Gas Industry Mess – – The latest boom in natural gas is transforming the Ohio Valley’s energy landscape. But over the years the industry has also abandoned thousands of oil and gas wells, often polluting nearby air, land, and water. An analysis by the Ohio Valley ReSource estimates more than 8,000 old wells in Kentucky, Ohio and West Virginia are considered “orphan,” with no company responsible. The costly process of plugging these wells often falls to state agencies struggling to pay for the cleanup. Across the country, many state regulators have few resources to deal with an ever-expanding list of abandoned wells. “The states are pretty good at regulating wells that are being explored, are being fracked, are in production, but they kind of lose interest once that happens,” said Alan Krupnick, a senior fellow with the nonpartisan environmental think tank, Resources For the Future. “There’s not enough attention being paid to reducing the risk from these abandoned wells.” Across the Ohio Valley, thousands of oil and gas wells sit idle. An analysis of state data by the Ohio Valley ReSource estimates more than 8,000 oil and gas wells are considered “orphan.” Definitions of orphan and abandoned wells vary by state, but in general, orphan wells lack an operator or company that can pay to plug them. That responsibility then falls to state regulators who are frequently struggling to keep up with demand and scrambling to find money to clean up the mess. A 2016 study of inactive well regulations in 22 states by Resources for the Future, a nonprofit advocacy group, found the majority lack policies to deal with legacy wells drilled decades ago and the means to collect sufficient funds to plug wells currently being drilled. “We want good policy to make sure that these wells when they’re eventually abandoned do not present environmental risk” Krupnick said. “One thing is they could raise the bonding amounts to the point where they’re covering the costs of these wells, of decommissioning the wells.”He said another challenge is that many states allow wells to remain in “idle status” for years. These wells aren’t producing, but operators aren’t being required to plug them. Unplugged wells can leak oil and other pollutants into water or the ground and inactive wells can emit methane, a powerful greenhouse gas many times more potent than carbon dioxide.
Pipeline in Hurricane Florence’s Potential Path Poses Added Danger – Hurricane Florence is projected to be an “extremely dangerous” storm, poised to inflict life-threatening impacts on low-lying coastal communities – and it may also dump vast quantities of rain over a limited area after making landfall, catastrophic rainfall and flooding as Hurricane Harvey did last year to Houston, Texas. Forecasters don’t know where such flooding will occur, but one possible target is the Appalachian Mountains, including mountainous southwest Virginia – the site of the Mountain Valley Pipeline (MVP). The pipeline would carry fracked methane gas from West Virginia into Virginia, where it will connect with an existing pipeline system. Methane is a powerful greenhouse gas that accelerates climate change, and extracting methane using fracking utilizes complex mixes of chemicals, many known to be toxic, contaminating millions of gallons of water as well as emitting dangerous air pollutants. Residents along the route have protested the loss of private property and destruction of treasured places, but the pipeline company has secured the right of eminent domain and has so far proved unstoppable. Along its 303-mile route, a swath 125 feet wide is now being clearcut; trenches are being opened; pipes 42 inches in diameter are being laid. This heavy-construction scar will through farms and national forests, up and down steep mountain slopes, even across the Appalachian Trail. Where the pipeline crosses steep mountains, erosion is a grave hazard. Locals fear that sediment will choke local streams and rivers, damaging the water sources of cities like Salem and Roanoke, VA as well as private wells and springs serving rural homes. Clearing land and digging trenches has already muddied local streams, choked off intermittent streams, and caused a mudslide that closed a local road, despite erosion control measures taken by the pipeline company. Heavy rainfall poses a particular threat. The geology of southwest Virginia magnifies the danger. Much of the land is karst, a porous limestone that has eroded over time, producing sinkholes, caverns and underground channels. Should the ground sink, pipes could buckle into underground caves. Heavy rainfall increases the threat. Now, with Florence on its way, residents and developers alike worry about what may happen if the hurricane drops torrents of rain. Construction on the MVP was temporarily halted on Tuesday, and the pipeline company said it was focusing on steps to maintain erosion and sediment controls. However, such controls have failed repeatedly in the face of normal rainfall events.
Mountain Valley Pipeline halts construction as Hurricane Florence takes aim at Carolinas, Virginia – With Hurricane Florence forecast to make landfall later this week, Mountain Valley Pipeline (MVP) temporarily halted construction on its 303-mile pipeline project on Tuesday and is taking measures to prevent extensive damage to its construction zone.Forecasters are expecting an unprecedented amount of rainfall from Florence across portions of Virginia, starting late this week and continuing through the weekend. MVP said it is taking “all possible precautions in Virginia” in consultation with the Virginia Department of Environmental Quality (DEQ) to maintain erosion and sediment controls along the pipeline’s right of way.Locals, however, worry about the impact heavy rainfall will have on the land. From the tree-clearing phase to the laying of the 42-inch-diameter pipe into trenches, MVP has facedproblems with erosion and sediment controls when it rains. In July, the Virginia DEQ served the company with a notice of violation for failing to install proper erosion controls.But the rains that have slowed construction of the pipeline so far do not compare to the potentially catastrophic rains that Hurricane Florence could unleash on a large part of Virginia, including the MVP construction zone south of Roanoke, Virginia. Last weekend, Virginia Gov. Ralph Northam declared a state of emergency in anticipation of the potential impact of Florence. “MVP has failed with the normal rainfalls we have in this area,” Sandy Schlaudecker, chair of Preserve Montgomery County, Virginia, said in an email to ThinkProgress. “I have great doubts that anything they have done will be enough. We will have people out documenting the damage as soon as it is safe.”
Virginia pipeline construction to continue with ‘aggressive’ monitoring – Will existing environmental rules be enough to protect Virginia streams from the potentially damaging side effects of two pipeline projects? Citizens and environmental groups cry no, but the State Water Control Board says its hands are tied. The seven-member board decided at a contentious Aug. 21 meeting to continue allowing two natural gas pipelines – the Mountain Valley Pipeline and Atlantic Coast Pipeline – to be constructed across the state, under additional oversight.The governor-appointed board is charged with administering the state’s water control laws and resolving special issues.Both pipelines will carry natural gas, extracted from underground shale formations using a controversial technique called hydraulic fracturing or “fracking.” Pipeline construction entails disrupting wetlands, crossing streams, removing trees and exposing bare soil, sometimes on steep slopes.The Mountain Valley Pipeline travels a largely north-south route through West Virginia into Virginia’s southwest corner, where work is already under way. Construction has also begun on the Atlantic Coast Pipeline in West Virginia. From there, it will cut a southeastern path through Virginia, including parts of the Chesapeake Bay watershed, to North Carolina. According to the Southern Environmental Law Center, it will cross Virginia waterways nearly 1,000 times.
Dominion’s 600-mile gas pipeline heading in direction of South Carolina — Bolt by bolt, a major pipeline is running toward South Carolina. Conservation advocates fear it could mean that exporting natural gas from the state is getting closer to reality. It would be one of the more controversial fallouts from the sale of SCANA to Dominion Energy, if that agreement actually goes through. The 600-mile Atlantic Coast Pipeline being built by Dominion is projected to pump 1.5 billion cubic feet per day of gas fracked from the ground under various Northern states. It would run from West Virginia to North Carolina. It could be expanded to cross into South Carolina near the mixing of Interstate 95 and South Carolina’s inland port shipping facility near Dillon, conservationists say. The route would put it on a line to continue on to ports such as Georgetown or Charleston, they warn. A Dominion spokeswoman said that’s not part of the company’s current plans. “Dominion Energy has not proposed any expansion of the Atlantic Coast Pipeline beyond what has already been approved by the Federal Energy Regulatory Commission,” said spokeswoman Kristen M. Beckham. Extending the pipeline into South Carolina could give fracking companies a much sought-after larger East Coast port from which to export gas to Europe. That would bring the state a new tax source and potentially jobs, particularly in Georgetown, which is struggling economically. Such an extension would also continue Dominion’s growing reliance on pipeline building for revenue. Conservation groups are concerned it could also mean building an onshore facility for processing any oil or gas drilled offshore South Carolina – a proposal opposed by most coastal residents, surveys show. It would add to pollution threats in waters already compromised by development.
If oil spilled off SC’s coast, a huge current would make it ‘impossible to control’ Oil spills in the Gulf Stream off South Carolina could form fast-moving slicks for hundreds of miles, making cleanup nearly impossible, devastating one of the Atlantic’s most important fisheries and wreaking havoc with the state’s billion-dollar tourist industry, a Post and Courier analysis shows.While spills in the Gulf Stream would travel far, spills closer to shore could ooze their way toward land, fouling beaches and marshlands anywhere from the Lowcountry to North Carolina’s Outer Banks.In what’s thought to be a first for a news organization, The Post and Courier generated more than 1,000 simulations of potential spills off the East Coast. To tell this undercovered story, The Post and Courier weaves history and science into a story that captures the majesty of the Gulf Stream and the stakes as the climate warms.The newspaper used a program developed by the National Oceanic and Atmospheric Administration that takes into account amounts of oil spilled, weather patterns and ocean currents, including the Gulf Stream.Simulations ranged from a spill of 1,000 barrels to a worst-case scenario: the 4.9 million-barrel BP/Deepwater Horizon disaster in 2010. Among the findings:
- In many medium-to-large spill scenarios, the Gulf Stream is like a high-velocity pump. Spills in the powerful current would spread quickly. Within two weeks, slicks off Georgia could hit the Outer Banks and then move into deeper waters off Virginia and pivot toward Europe.
- The Gulf Stream also serves as a lid – one that traps oil between the current and our coast. If spills happened within 50 miles of South Carolina – before the Gulf Stream – oil plumes could coat beaches along the tourist-driven Grand Strand. Other simulations show oil hitting the North Carolina coast around Wilmington and the Outer Banks.
- Shifting winds and currents add layers of complexity to oil-spill predictions – and potential cleanup operations. In some scenarios, winds push oil ashore. In others, oil ends up in eddies that spiral miles offshore.
The newspaper’s simulations come amid a heated debate about the potential risks and rewards of oil exploration along the East Coast.
Bayou Bridge Pipeline halted by property rights challenge – A legal challenge from Atchafalaya River Basin landowners and environmental groups has temporarily halted construction of the controversial Bayou Bridge Pipeline. On Monday (Sept. 10), a judge was scheduled to hear the case of St. Mary Parish landowners who filed an injunction against builders of the pipeline, which they say would cross their property illegally. But just before the hearing, Texas-based Energy Transfer Partners, which is constructing the pipeline jointly with Phillips 66, came to an agreement with landowners that effectively stops construction on a key section of the route. “It’s a huge victory and blow to Bayou Bridge,” said Anne Rolfes of Louisiana Bucket Brigade, one of the groups opposed to the pipeline. The proposed 162-mile pipeline would run from St. James to Lake Charles, with portions crossing the ecologically-sensitive Atchafalaya Basin. The pipeline would link to Energy Transfer’s Dakota Access Pipeline and the oil fields in North Dakota. The injunction was filed in July after members of the Atchafalaya Basinkeeper, a preservation group, noticed pipeline workers cutting trees and digging trenches on a 38-acre marshland in St. Mary. The property’s owners, which includes Peter Aaslestad and other members of his family, had not granted access to the property and opposed the pipeline’s construction through the basin, which contains one of the largest swamps in North America.
Why The U.S. Is Suddenly Buying A Lot More Saudi Oil – For a few months now, OPEC has been boosting production to ease concerns about high oil prices amid expected supply losses from Venezuela and Iran. The cartel’s largest producer and exporter, Saudi Arabia, has been specifically targeting an increase in crude oil exports to the most transparent market, the United States, which reports crude oil imports and inventory levels every week.On the one hand, the Saudis are looking to regain their foothold in the American market after having cut shipments to the United States to a 30-year-low at the end of last year, when OPEC’s efforts to erase the global oil glut were in full swing.On the other hand, the Saudis are responding to the demands of their staunch ally U.S. President Donald Trump, who has repeatedly slammed OPEC for the high gasoline prices, urging the cartel in early July to “REDUCE PRICING NOW!”In the week to August 31, the four-week average of U.S. crude oil imports from Saudi Arabia exceeded 1 million bpd for the first time since June 2017, data by the EIA showed.At that time last year, Saudi Arabia started to purposefully reduce its exports to the United States, where inventory data and refinery runs are reported every week. Those reports influence the price of oil and investor sentiment. In the last week of October 2017, the four-week average of U.S. imports from Saudi Arabia was just 506,000 bpd – almost half of the four-week average of 1.009 million bpd for the last week of August this year.
Midland WTI gets its own cavern at LOOP crude terminal – The Louisiana Offshore Oil Port has quietly allocated one of its eight underground crude oil storage caverns to West Texas Intermediate, a reflection of the Texas grade’s continued ascent as the US’ flagship oil. In documents published to its website, LOOP established this month a “Midland WTI cavern” into which the grade may be delivered. LOOP defines Midland WTI as maximum 44 API, maximum 0.45% sulfur, maximum 10 psi RVP, maximum 11 psi TVP and maximum 1% sediment and water. The cavern is known as Segregation 21. It replaces Segregation 20, which allowed for deliveries of maximum 46.5 API Eagle Ford, Bakken and Midland WTI. That took effect in October 2017. The cavern has historically been used for light grades. Before October 2017, LOOP in the past also allowed for the Nigerian grades Bonny Light (34.4 API, 0.20%S), Forcados (30.3 API, 0.18%) and Qua Iboe (36.3 API, 0.12%) to be delivered. The best option for delivering WTI into LOOP would be via Shell’s 375,000 b/d Zydeco pipeline (formerly known as Ho-Ho), which extends from Houston to the Louisiana terminal. Another option would be by barge or tanker from Corpus Christi or the Houston area delivering into LOOP’s offshore platform. A typical river barge holds 10,000-30,000 barrels of oil, while new articulated tug-barges (ATBs) used on the ocean can hold as much as 340,000 barrels. Shippers can also rail crude to Genesis Energy’s Raceland, Louisiana, terminal, where it can be injected into pipe and reach LOOP. The move reflects the rising importance of WTI globally. The Permian region of West Texas and southeastern New Mexico, from which WTI comes, is currently producing around 3.4 million b/d of oil, according to US government figures. The Permian accounted for 26% of total US oil production in 2017. Phillips 66 is a large regional consumer of light sweet grades at its 249,700 b/d Alliance refinery in Belle Chasse, Louisiana. LOOP’s eight caverns hold about 60 million barrels in total, or roughly 7.5 million barrels each. LOOP currently lists assignments for six of the eight caverns. This includes Mars in two caverns, Thunder Horse, LOOP Sour, and Segregation 17, into which Arab Medium, Basrah Light and Kuwait may be delivered. The status of two caverns is not known.
Big Oil Seeks Billions from U.S. Government to Protect It From…Climate Change – Gaius Publius: In a masterstroke of irony – and hubris – the oil industry wants the federal government to build and pay for “a nearly 60-mile ‘spine’ of concrete seawalls, earthen barriers, floating gates and steel levees on the Texas Gulf Coast” to protect “the crown jewels of the petroleum industry.” What are those crown jewels? One of the “world’s largest concentrations of petrochemical facilities, including most of Texas’ 30 refineries, which represent 30 percent of the nation’s refining capacity.” The cost, of course, is in the billions. From the AP:Texas is seeking at least $12 billion for the full coastal spine, with nearly all of it coming from public funds. Last month, the government fast-tracked an initial $3.9 billion for three separate, smaller storm barrier projects that would specifically protect oil facilities.That followed Hurricane Harvey, which roared ashore last Aug. 25 and swamped Houston and parts of the coast, temporarily knocking out a quarter of the area’s oil refining capacity and causing average gasoline prices to jump 28 cents a gallon nationwide. Many Republicans argue that the Texas oil projects belong at the top of Washington’s spending list. The industry doesn’t care at all about the “overall economy.” They only care about their own economy. If industry CEOs could hire Texans to work for a pittance instead of a wage, they would do that. If they could hire Texans to work for nothing instead of a pittance, they would do that too. The planned infrastructure is quite extensive. Just some of the detail: “While plans are still being finalized, some dirt levees will be raised to about 17 feet high, and 6 miles of 19-foot-tall floodwalls would be built or strengthened around Port Arthur, a Texas-Louisiana border locale of pungent chemical smells and towering knots of steel pipes.” The stink of the town is obviously due to the massive refinery structures. Note that this federal spending protects the property of non-U.S. companies as well: The town of 55,000 includes the Saudi-controlled Motiva oil refinery, the nation’s largest, as well as refineries owned by oil giants Valero Energy Corp. and [the French company] Total S.A. There are also almost a dozen petrochemical facilities.
U.S. Department Of Energy Authorizes Freeport LNG Exports –Last week, the U.S. Department of Energy authorized Freeport LNG to export up to 2.14 billion cubic feet of LNG from the same-name facility in Texas “to any country not prohibited by U.S. law or policy” beginning in the third quarter of 2019 when the Freeport facility will begin exports.The Energy Department release explained that the short-term order for Freeport LNG “allows for additional flexibilities to export LNG pursuant to short-term contracts and for the initial commissioning volumes from the project. Freeport will also still be able to export LNG pursuant to its long-term authorizations from DOE.”Last week, Freeport LNG said it had sealed a long-term deal with a U.S. division of Japan’s Sumitomo Corp for the delivery of 2.2 million tons of liquefied natural gas annually over a 20-year period, Reuters reported.The deal, to enter into effect in 2023 when the fourth liquefaction train at the Freeport facility is due to be completed, will be instrumental in providing the funds for the completion of the unit, which will have an annual capacity of 3.5 million tons of LNG. Now Freeport LNG needs to find long-term commitments for another 1.3 million tons of LNG to guarantee the construction of the fourth train. The first train should begin operating by the end of June 2019. Liquefied natural gas exports from the United States began in 2016, and since then, the Department of Energy reports, total production has reached the equivalent of more than 1.3 trillion cubic feet of natural gas. The only two operating LNG export facilities in the country are Sabine Pass and Dominion Cove Point, with a combined capacity of 3.5 billion cubic feet of gas daily. So far, the government has approved long-term LNG export contracts to the tune of 21.35 billion cubic feet of gas daily.
Projects may double Corpus Christi crude oil export capacity by late 2019 – Options for exporting more US crude oil from the burgeoning hub of Corpus Christi, Texas, continue to expand as companies prepare for a flood of crude available to head there within the next year. And infrastructure expansion is sorely needed. Planned long-haul pipelines out of the Permian Basin will potentially bring an additional 1.9 million b/d of light, sweet crude and condensate to Corpus Christi by the end of 2019. That’s on top of the about 2 million b/d of crude from the Permian Basin and Eagle Ford Shale play that reaches the port city currently. As the area only has three refineries and two condensate splitters, with a combined capacity of about 795,000 b/d, much of the oil that makes its way to the port has to be exported, or transported by water. Exports of WTI and Eagle Ford crude and condensate out of Corpus Christi are also ramping up. The port is the closest — and cheapest — point along the Gulf Coast to buy Eagle Ford crude and condensate. WTI Midland crude also is available there. Corpus Christi, located about 220 miles southwest of Houston, is less congested, has less fog and has a deeper draft than the Port of Houston. All of those reasons, traders say, can make it more appealing for exports. By exporting crude from Corpus Christi, buyers and sellers can avoid the snarl of Houston pipeline and port logistics and marine bottlenecks there. In June, the port of Corpus Christi exported 619,242 b/d of crude, according to port data. In January, the port exported 458,153 b/d. Current facilities in Corpus Christi have the ability to export some 1.1 million b/d of crude. By late 2019, numerous projects at the port aim to more than double the export capacity to around 2.4 million b/d, according to S&P Global Platts Analytics data. That number could top 3.2 million b/d in early 2021 if all of the proposed projects are completed. Driving this is expansion are expected production increases in the Permian Basin, as well as the nearby Eagle Ford play. Crude pumped there will feed new or expanded pipelines including the 590,000 b/d EPIC line; Plains All American’s 650,000 b/d Cactus II line and the 700,000 b/d Gray Oak line proposed by Phillips 66/Andeavor. Some planned infrastructure projects in Corpus Christi have focused on the need to directly load VLCCs that can transport some 2 million barrels of crude. However, until planned dredging of the Corpus Christi main channel is complete, or until a offshore crude export terminal is built, that will be impossible as the bay is too shallow to load VLCCs currently.
Permian E&Ps Significantly Boost 2020 Oil Hedges — Possibly on Doubts about Pipeline Completion — Oil and gas producers working in the Permian Basin increased their 2020 oil basis hedge positions by 431% during the second quarter, a sharp uptick that may signal doubts about 2019 target dates for key pipeline projects, Wood Mackenzie analysts said Tuesday. “It was an anomalously high trading volume” for 2020 Midland-Cushing (Mid-Cush) basis swaps during the quarter, said corporate research analyst Andrew McConn. “The only reasonable conclusion one can draw from this surge is that Permian producers are concerned that key pipeline projects won’t be completed on schedule.” With oil production forecast to grow on average in the Permian by more than 400,000 b/d year/year through 2022, output has been overwhelming takeaway capacity and causing oil and gas to sell inside the basin at steep discounts to national indexes. As recently as 2015, pipeline capacity constraints caused the Mid-Cush West Texas Intermediate discount to widen to $20/bbl, according to Wood Mackenzie researchers. “This has prompted many Permian operators to use derivatives to hedge against the risk of price differentials growing wider.” According to a U.S. exploration and production (E&P) review by Goldman Sachs of all hedging completed during 2Q2018, operators overall only slightly increased their 2018 oil hedging, but 2019 still was near normal levels. Hedging activity of Goldman’s covered E&Ps was considered to be minimal at the end of June versus the end of March. Post-2Q2018, E&Ps were 52% hedged for oil, 3% above an equivalent 49% at the end of the first quarter. For 2019, hedging had climbed to 23% from 16% post-1Q2018 results.
Study Suggests Pipeline Delay Worries Among Permian – Oil producers in the Permian Basin appear to be worried that key pipeline projects to boost takeaway capacity from the region might not hit their 2019 targeted start-up dates. That is the conclusion of Wood Mackenzie analysts, who in a new report observe that Permian producers increased their 2020 oil-basis hedge positions by 431 percent – or 175,000 barrels per day – during the second quarter of this year. “It was an anomalously high trading volume for this particular hedging derivative,” Andrew McConn, corporate research analyst at Wood Mackenzie, said in a written statement Tuesday regarding the 2020 Midland to Cushing WTI discount (Mid-Cush basis-swaps). “The only reasonable conclusion one can draw from this surge is that Permian producers are concerned that key pipeline projects won’t be completed on schedule.” Wood Mackenzie noted that Permian oil production is ramping up at “breakneck speed,” with growth estimated at more than 400,000 barrels per day year-over-year on average through 2022. The study’s authors contend the production surge is overwhelming takeaway capacity within the Permian, causing oil and gas to sell inside the basin at steep discounts to national indexes. To illustrate, they noted that significant pipeline capacity constraints as recently as 2015 caused the Mid-Cush WTI discount to widen to $20 per barrel. As a result, many Permian operators have turned to derivatives to hedge against the risk of price differentials growing wider, Wood Mackenzie stated. “The more than 52 percent increase in 2019 Mid-Cush hedge positions suggests that producers perceive risk for that year as well,” continued McConn. “Specifically, the risk that Midland oil prices don’t gradually rise and converge back to parity with the Cushing index – as futures markets currently imply.” Acknowledging that midstream companies are “racing” to add new pipeline capacity to ease congestion, Wood Mackenzie estimates that West Texas producers may not get “sustained relief” from current under-construction and final investment decision projects until late 2019. Wood Mackenzie stated that its most recent North American Crude markets short-term outlook projects that more than 2 million barrels per day of capacity should go online in the late-2019/early 2020 time frame.
Permian Takeaway Pains Leading to Other U.S. Basin Gains – Pipeline capacity constraints in the crowded Permian Basin won’t lead to any sharp pullback but they have led to opportunities elsewhere in the U.S. onshore, many of the largest domestic producers said last week.The annual Barclays Energy and Power CEO Conference, held in New York City, drew almost 200 companies and nearly 2,000 clients. Analysts Michael Cohen and Samuel Phillips offered a macro view of the salient points by exploration and production (E&P) companies and oilfield service (OFS) operators.There was no surprise about the leading topic at the flagship confab: Permian oil and gas takeaway constraints.“The key concern is in the Permian, where mixed messages from producers and service companies is keeping investors wondering about the sector overall,” said the analyst team.“Producers universally indicated that they planned to marginally slow down their drilling and completion activity in the Permian because of pipeline constraints.”But it’s not a long-term issue. Halliburton Co., which announced a reduction in its 3Q2018 outlook, said several E&Ps may have “blown through” 2018 Permian budgets, but they planned to get “straight back to work” in January.“E&Ps have strategies in mind” should a major price collapse occur in the Permian, said the Barclays team.They cited Diamondback Energy Inc. and Encana Corp., among a few others, which indicated that if differentials blow out too much, they “would likely adjust the shape of their production profiles in 2019 to deal with the egress issues.”
Oil and gas well fracking creates a lot of wastewater. Here’s where things get interesting — The extraction of petroleum hydrocarbons, particularly from impermeable strata like shale, is a thirsty process. It requires millions (and sometimes tens of millions) of gallons of water to stimulate a single production well. Couple this need with the feverish pace at which oil and gas production is expanding across the epicenter of shale energy extraction (far West Texas and eastern New Mexico), and it is easy to see the concerns about water resource management. Unconventional oil and natural gas extraction processes yield an incredible amount of wastewater. In the Permian Basin, as many as two to six barrels of wastewater are collected for every barrel of oil. This is where the story of shale energy extraction and the quest for domestic energy security becomes a tale of tremendous responsibility and opportunity. The bad news is that the systematic use of underground injection wells, known in the industry as saltwater disposal wells, has been linked to induced seismicity in several shale basins in the U.S. These induced earthquakes can damage property, thus potentially triggering a wave of litigation for energy companies. Equally problematic is the simple fact that pumping these large volumes of wastewater into the subsurface strata essentially removes that water from the water cycle. This may not be an emergency issue today in the U.S., but water management could become a pertinent topic in the very near future as the U.S. rig count rises. Our research group, the Collaborative Laboratories for Environmental Analysis and Remediation at the University of Texas at Arlington, has studied this extensively under some of the most complex and diverse field conditions. We found that multiple treatment technologies are required to remove the contaminants that generally preclude oilfield waste from reuse.
U.S. oil boom starts to cool, tightening global market- (Reuters) – U.S. oil production is running into capacity constraints, which are starting to have a material impact on the global availability of crude, causing the market to tighten and putting upward pressure on prices. The biggest problem is the lack of sufficient pipeline capacity to move oil from shale wells in western Texas and eastern New Mexico to refineries in the Midwest and export terminals on the Gulf Coast. But production in the Permian Basin has also been constrained by shortages of labour, equipment and materials, which have pushed drilling, pressure pumping and completion costs sharply higher. The most obvious impact has been a sharp drop in the price that Permian producers receive for their oil compared with other benchmarks, especially Brent (https://tmsnrt.rs/2p0CTbx ). West Texas producers are currently receiving just $55 per barrel for oil delivered to Midland, in the heart of the Permian, compared with $79 for North Sea Brent. The massive discount reflects the twin difficulties of moving the crude out of the Permian to the main inland trading hub at Cushing in Oklahoma or down to the refineries and export terminals on the coast. Midland crude is currently trading at discount of $14 per barrel compared with Cushing, while Cushing is itself priced at a further discount of $10 to Brent. Midland has traded at an average discount to Brent of more than $12 per barrel this year, up from $4 in 2017 and less than $1 in 2016, and the price differential is steadily worsening. Midland prices have mostly been falling this year while Brent has climbed, leaving Midland up by just $10 per barrel (22 percent) since the end of June 2017 while Brent has risen by $32 (68 percent). Well completions, which are more relevant for production, also show signs of stabilising in recent months, after increasing fairly consistently over the two previous years (“Drilling productivity report“, EIA, August 2018).Since the Permian Basin has been the biggest contributor to U.S. oil output growth in the last two years, the slowdown is starting to temper expectations for further increases in the rest of 2018 and through 2019.
Domestic Onshore Drilling Permits Gain in August, Slow Down in Early September – A total of 4,389 permits to drill in the U.S. onshore were filed by operators during August, up 22% from July and nearly one-third higher from a year ago, according to data compiled by Evercore ISI.Each month the analyst team provides an overview of domestic drilling permit activity onshore and offshore using data compiled from all major states and the Bureau of Ocean Energy Management. Drilling permits require approval before exploration and production companies may drill a new well or bypass/sidetrack an existing well.According to Evercore, August data is nowhere near the heights achieved in August 2014, when 7,746 permits were filed, nor the monthly onshore permit count peak of 8,441 in June 2008.Analysts also cited some “weakening” permit numbers for the month in Wyoming, down 24% from July, as well as Mississippi (off 44%) and Ohio (off 15%), which pressured the permit totals.However, the permit losses in August from July were “more than offset” by gains in Colorado (66%), Texas (21%) and Kansas (66%).Still, the year-to-date domestic permit count remains 2% below the count during the 2009 cyclical downturn, according to Evercore.This month began slow for permitting, with a total of 742 U.S. onshore permits and one new offshore plan issued during the first week of September, down from the first week of August at 830.“Year-to-date onshore weekly average is down at 742 permits from 2017’s weekly average of 847 permits,” said analysts. For the Gulf of Mexico (GOM), 18 permits were issued in August, up from 13 in July and 11 in the year-ago period. Eight permits were issued for new wells, two deepwater, three midwater, and three shallow water. Seven permits were issued for sidetracks, while three were issued for bypasses.
Pioneer Secures In-Basin Sand, 15-Year Contract for Permian Operations with U.S. Silica — Dallas-based Pioneer Natural Resources Co., one of the largest Permian Basin producers, has secured fracture sand reserves near its West Texas operations in a 15-year deal with U.S. Silica Holdings Inc.The contract guarantees long-term supply from U.S. Silica’s mine now underway near Lamesa, TX, which is close to Pioneer’s Midland sub-basin operations. Pioneer also took a stake in the Lamesa mine, but no details were disclosed.“Strategically located in close proximity to our Midland Basin acreage, delivered sand from the Lamesa mine will cost approximately half that of our current delivered sand, reducing well costs into 2019 and beyond,” CEO Timothy Dove said. “The long-term nature of this agreement will benefit both companies. U.S. Silica has been a trusted partner for many years, and this contract solidifies their position as one of our key suppliers of proppant.” Pioneer, the largest acreage holder in the Midland with an estimated 750,000 gross acres, last month increased its Permian capital spending by about 15% for the year to $3.4 billion.
Ex-CEO of Texas fracking sand company gets 15 years in scam – (AP) – The former CEO of a Texas fracking sand company must serve 15 years in federal prison over a $6 million Ponzi scheme that also landed an ex-lawmaker behind bars. Stanley Bates was sentenced Tuesday in San Antonio. The ex-FourWinds Logistics executive pleaded guilty to counts including securities fraud and money laundering in the scam linked to oil production. State Sen. Carlos Uresti of San Antonio resigned in June before being sentenced to 12 years for his conviction on counts including money laundering and wire securities fraud. Uresti was general counsel for now-defunct FourWinds. A consultant was also convicted and sentenced to more than five years. Prosecutors say investments were wrongly spent on gifts, travel, luxury vehicles and prostitutes. The three men must also repay more than $6.3 million.
Pipeline in fatal blast had a dime‑sized hole in it – A natural gas pipeline that exploded in Texas, killing a 3-year-old girl, had been leaking gas through a dime-sized hole for some time, records show. Delaney Tercero, 3, died and her sister and parents were badly burned in the explosion. A gathering line owned by Targa Pipeline Mid-Continent WestTex exploded on Aug. 9 near their mobile home outside Midland, Texas. Texas Railroad Commission (RRC) records obtained by E&E News through an open-records request indicate that Targa had the pipeline excavated. They found that the steel wall of the line and the tar coating that is supposed to protect it had been “compromised,” according to the RRC incident report. There was a hole, three-eighths of an inch by five-eighths of an inch wide, that had been leaking for “an undetermined length of time.” The gas in the 10-inch-diameter pipeline was not odorized. The line was about 20 feet from the front of the family’s mobile home. Targa hired a contractor to remove a 19-foot section of the pipe, and it was taken to a Targa location under “lock and key,” RRC officials wrote that only Targa lawyers have access to the damaged pipe. Targa plans to reroute the gathering line in the area, the report said. Delaney’s 2-year-old sister, Dalayza, remains hospitalized at University Medical Center in Lubbock. Her parents, Auden Tercero, 32, and Lucia Cereceres, 29, were also airlifted there after the explosion. The Aug. 10 posting by the sheriff’s office said Cereceres was on a ventilator and Dalayza was considered “extremely critical” and on a breathing tube.
‘We’ve waited a long time for this:’ Iowa Supreme Court to decide fate of Dakota Access pipeline – More than a year after the contentious Dakota Access pipeline began carrying crude oil underneath Iowa fields, local landowners who opposed the project finally got the chance to argue their case in front of the Iowa Supreme Court.”We’ve waited a long time for this,” Boone County farmer Dick Lamb said.The 1,172-mile pipeline transports about 470,000 barrels of crude oil each day from the Bakken formation in North Dakota to a distribution hub in Patoka, Illinois, cutting through 18 Iowa counties along the way. After the Iowa Utilities Board approved the project and the use of eminent domain to gain easements on properties, several landowners contested the decision in court.They were joined by other groups, including the Sierra Club Iowa chapter. In demonstrations, landowners, environmentalists and American Indians fought the $3.8 billion pipeline up and down the route as crews built the pipeline in 2016. In February 2017, Polk County District Judge Jeffrey Farrell ruled that pipeline builders acted lawfully in seizing private land through Iowa’s eminent domain laws. But the landowners appealed the decision to the state’s highest court.The case is being closely watched because it will determine the fate of the hotly contested pipeline in Iowa. But the ruling could also set a precedent for how courts interpret Iowa’s eminent domain laws in the future. Lawyers argued in front of Iowa’s seven justices for about an hour Wednesday. The case now awaits the court’s decision.
State regulators postpone Enbridge meetings after protests erupt – State regulators on Tuesday postponed a meeting on Enbridge’s controversial new $2.6 billion oil pipeline project after protests erupted in the hearing room.The Minnesota Public Utilities Commission (PUC) was evaluating whether Enbridge met conditions imposed by the panel in June in regard to the pipeline project, which would replace the company’s current Line 3. The conditions, which must be met for the company to receive its permit, include details of Enbridge’s corporate guarantee and insurance coverage in case of an oil spill.A disruption started around 11:15 a.m. when three pipeline opponents in the back of the PUC hearing room in downtown St. Paul took out a bullhorn and made speeches aimed at the commissioners.”You should all be ashamed,” one protester said.”It’s going to be really uncomfortable for you for the next couple of years,” another protester said.PUC Chairwoman Nancy Lange then recessed the meeting until 11:45 a.m. The commissioners came back at 11:55, and they were greeted with protesters shouting, “What do you do when your land is under attack? Fight back.”Lange tried to restart the meeting, and the protests diminished, though one pipeline opponent continued playing music on a boombox. Lange then canceled the rest of the meeting when her request to turn the music off wasn’t heeded. The PUC will reschedule the meeting as soon as possible, said Dan Wolf, the commission’s executive secretary. There were at least 20 opponents in the crowd, and about 20 pipeline supporters.
Colorado industry pumps millions into effort to defeat drilling setback – Oil and gas companies have pumped millions this campaign cycle into an effort to defeat a Colorado ballot measure that would increase new drilling setbacks by five-fold and cripple the future of the industry there. The pro-industry group Protecting Colorado’s Environment, Economy and Energy Independence, received $7.9 million during August alone, according to data from the state’s secretary of state. The industry learned in late August that Initiative 97 had received enough valid signatures to secure a spot on the November ballot. If approved, drilling setbacks would increase from the current 500-foot setback to 2,500 from all occupied structures as well as vulnerable areas, including waterways and parks. It will appear on the ballot as Proposition 112. “Proposition 112 will devastate the economy and cut nearly 150,000 jobs and billions in tax revenue for critical local services like schools, public safety and roads,” said Karen Crummy of Protect Colorado. “The measure is so extreme it has bipartisan opposition from former, current and future elected officials, including gubernatorial candidates Jared Polis and Walker Stapleton.” Protect Colorado has been running ads in an attempt to educate the public about what is at stake if Proposition 112 passes. More than 94% of non-federal land in the state’s top five producing oil and natural gas counties (Weld, Garfield, La Plata, Rio Blanco and Las Animas) would be unavailable for new production. And at least 85% of all new oil and natural gas development on non-federal lands would be off limits, according to the Colorado Oil and Gas Conservation Commission. “What is clear, and what industry clearly understands, is that 97 is a must kill for the Colorado oil and gas industry, which will spare no expense or effort, especially key players, to educate voters about the economic harm that 97 likely would inflict upon the state,” according to a note by Baird Equity Research. Key players in Colorado have already poured a lot of money into fighting the measure. Anadarko Petroleum, for instance, has contributed a total of $5.8 million to Protect Colorado so far this election cycle, including $1.83 million last month. DCP Midstream has donated $1 million, while Noble Energy and PDC energy have contributed $4.4 and $3.3 million, respectively, in 2018. Contributions have also come in from SRC Energy, Whiting Oil and Gas Corporation and many others. Total contributions to Protect Colorado throughout 2018 top $21 million through the end of August.
Trump’s EPA proposes weaker methane rules for oil and gas wells (Reuters) – The Trump administration on Tuesday proposed weakening requirements for testing and repairing methane leaks in drilling operations, among other measures, in a step toward rolling back an Obama-era policy to combat climate change. The Environmental Protection Agency (EPA) said the changes will save the industry $75 million a year in regulatory costs between 2019 and 2025, while increasing methane emissions. Methane, the primary component of natural gas, leaks from oil and gas wells during drilling. It accounts for 10 percent of U.S. greenhouse gas emissions and has more than 80 times the heat-trapping potential of carbon dioxide in the first 20 years after it escapes into the atmosphere. The oil and gas sector is the largest single source of U.S. methane emissions, according to EPA data. The proposal is the latest move by the Trump administration to roll back environmental rules put in place by former President Barack Obama. Last month, the administration proposed rolling back tougher fuel efficiency standards for vehicles and moved to replace a policy to limit emissions from power plants with one that would allow states to write their own standards. Last year, it delayed implementing the Obama-era rule limiting methane gas emissions from oil and gas operations on federal and tribal lands. Under the new proposal methane gas emissions will increase by a total 380,000 short tons between 2019 and 2025 compared with the EPA’s 2018 baseline estimate. Obama’s updates to the EPA’s New Source Performance Standards envisioned preventing emissions of 300,000 short tons of methane in 2020, rising to preventing 510,000 short tons of methane emissions in 2025. “It’s unfortunate that the Trump Administration is once again ignoring facts and common sense only to put the interests of the nation’s worst-run oil and gas companies ahead of the health and welfare of all Americans,” Matt Watson, associate vice president, energy, for the Environmental Defense Fund, said in a statement.
Forest Service Proposes Faster Permitting For Oil, Gas Leasing — The U.S. Forest Service (USFS) plans to propose streamlining environmental reviews and permitting for oil and gas leasing in the forests and grasslands it manages, which it said should lead to expedited leasing decisions.In an advance notice of public rulemaking published in Thursday’s issue of the Federal Register, the Department of Agriculture agency said the proposed rule would also improve coordination with the Interior Department’s Bureau of Land Management (BLM) and create “one simplified permitting system” for oil and gas operators.”The potential changes to the existing regulation permitting sections include eliminating language that is redundant with the National Environmental Policy Act process, removing confusing options, and ensuring better alignment with the BLM regulations,” USFS said. “The intent of these potential changes would be to decrease permitting times by removing regulatory burdens that unnecessarily encumber energy production. These potential changes would promote domestic oil and gas production by allowing industry to begin production more quickly.”USFS is accepting public comments through Oct. 15. The agency said the proposed changes would help modernize legislation that was first promulgated in 1990 and only given a minor update once, in 2007. According to the notice, USFS proposes to streamline and reform the process used to identify national forest land that BLM may offer for oil and gas leasing, and to update regulatory provisions that cover lease stipulation waivers, exceptions and modifications. It also plans to review language addressing an “operator’s responsibility to protect natural resources and the environment.”
Trump panel weighs change on royalties for gas from public land – (AP) – A Trump administration advisory committee on Thursday recommended a change in the way energy companies calculate how much money they owe taxpayers for pumping natural gas from public lands. But the U.S. Interior Department’s Royalty Policy Committee first had to clear up an apparent misunderstanding over how much leeway the companies would have in determining how much they owed. Critics said the proposal would have allowed companies virtually a free hand in calculating the royalties they had to pay, but committee members said that was not their intent. Instead, they said companies should get a choice between two formulas, both set by the government. Interior Secretary Ryan Zinke formed the committee to recommend ways to remove barriers to getting coal, oil and gas from public land while ensuring taxpayers get fair prices. The panel held its fourth meeting in the Denver suburb of Lakewood. Royalties from publicly owned energy reserves are distributed among federal, state and tribal governments, and billions of dollars are at stake. In fiscal year 2017, the government passed out $7.1 billion in royalties on oil, gas and coal extracted from federal lands, federal offshore areas and Native American lands, according to the Interior Department, which manages most federally owned energy. Environmentalists and taxpayer advocates said an early version of the Royalty Policy Committee’s proposal – posted on the Interior Department’s website – had a loophole that would have let companies decide how to calculate royalties instead of using a formula set by the Bureau of Land Management, part of the Interior Department. The proposal “would remove BLM’s authority to determine valuation, handing power over to producers to self-regulate,”
North Dakota Geologists Seek Local Sand Source for Fracking – North Dakota geologists are attempting to locate local sources of sand to be used for hydraulic fracturing as the oil industry demand grows. The North Dakota Geological Survey is collecting sandstone samples from Billings and McKenzie counties this year, the Bismarck Tribune reported. The agency had already collected samples in other areas and authored a 2011 study that found the state’s sand sources are lower in quality than other U.S. sources. This second phase of research comes as demand for sand increases and companies experiment with lower-cost options. Companies are now accepting sands that they wouldn’t have accepted between 10 and 15 years ago, according to Monte Besler, who owns FRACN8R Consulting in Williston. “We’re trying to test and characterize our sand resource so that industry can decide whether or not we have a usable alternative,” said Fred Anderson, a geologist with the state survey agency. Preferred sand for fracking is spherical and close to pure quartz, similar to the Northern white sand that’s shipped to the Bakken from Minnesota, Wisconsin and Illinois. North Dakota’s sand contains quartz, but it’s more mixed than pure, according to Anderson. Anderson said it’s possible that the state’s sand could be processed to get it closer to the desired sand characteristics. North Dakota operators want to find a local sand source to save on transportation costs instead of importing by rail, said Ron Ness, president of the North Dakota Petroleum Council.
Native American tribes sue over Keystone XL pipeline | TheHill: Two Native American tribes are suing the Trump administration over its approval of the Keystone XL oil pipeline, which they say will damage important cultural sites. The Fort Belknap and Rosebud Sioux tribes brought the lawsuit against the State Department on Monday, claiming the pipeline was approved last year without consideration of the harm it could inflict. The tribes are asking a court to rescind the permit, arguing that the president ignored their human rights and specific protections for tribes when he approved the project last year. “All historical, cultural, and spiritual places and sites of significance in the path of the pipeline are at risk of destruction,” the tribes told the federal District Court for the District of Montana in their filing. The lawsuit is the latest in a series of ongoing legal battles which have stalled the pipeline’s construction since the State Department issued a permit allowing it to move ahead in 2017. The pipeline was most recently delayed last month after a judge ordered an environmental review of the project.
California Jury Finds Plains Guilty in 2015 Oil Spill – A jury in Santa Barbara County, CA, has found Houston-based Plains All American Pipeline LP guilty of criminal charges in a 2015 pipeline oil spill that fouled local beaches. After a four-month trial, the state Superior Court jury found Plains guilty of one felony count for causing the spill by failing to properly maintain its pressurized oil pipeline, the 10.2-mile Las Flores to Gaviota Pipeline, or Line 901, that ruptured with some of the oil reaching the Pacific Ocean at Refugio State Beach through a drainage culvert. Plains shut down Line 901 and another nearby pipeline, Line 903.The jury also found Plains guilty on eight misdemeanor counts for failing to report the spill in a timely manner, knowingly making false reports to the state, and for killing marine mammals, protected sea birds and other sea life. The jury considered 13 counts against Plains, which had been whittled down from an original list of 46 counts in a 2016 indictment by a California grand jury.Plains was acquitted on one misdemeanor charge. The judge declared a mistrial on three other counts after the jury failed to come to agreement.Plains officials said the publicly traded master limited partnership “continues to accept full responsibility for the impact of the accident, and we’re committed to doing the right thing.” They cited the company’s “comprehensive clean up effort” and the absence of any “knowing wrongdoing” by the company or its employees in the verdicts.Plains maintained that its operations of Line 901 met or exceeded all applicable legal and industry standards, and that the jury “erred in its verdict on one count where applicable California laws allowed a conviction under a negligence standard.” Plains indicated it would evaluate legal options regarding the jury’s decision. In the original 46 counts, Plains and a former employee, who was terminated before the trial began, were specifically named for allegedly violating state laws. Following the spill, Gov. Jerry Brown signed three laws on oil pipeline preventive and contingency planning requirements spurred by the Plains incident.
California Gov. Jerry Brown moves to block Trump on offshore drilling, declares ‘not here, not now’ – California Gov. Jerry Brown on Saturday signed legislation to thwart the Trump administration’s efforts to expand offshore oil drilling along the California coast. At the same time, the Democratic governor announced the state’s opposition to the federal government’s plan to expand oil drilling on public lands, an idea that’s is controversial in conservation-minded California. It follows the U.S. Interior Department move in January that proposed to open up 90 percent of the country’s offshore oil and gas reserves through new federal leases. “Today, California’s message to the Trump administration is simple: Not here, not now,” Brown said in a press release. “We will not let the federal government pillage public lands and destroy our treasured coast.” The two bills signed by Brown on Saturday, Senate Bill 834 and Assembly Bill 1775, seek to prohibit new construction of oil drilling-related infrastructure, such as pipelines, within state waters if the federal government authorizes any new offshore oil leases.The White House and Interior Department did not immediately return CNBC’s request for comment. California can make it difficult to expand oil and gas drilling, because it controls waters that are within three miles of its shoreline. The federal government has rights over waters between three and 231 miles offshore. Moreover, the new legislation signed by the governor require new public notices and processes for lease renewals, as well as other hurdles to authorize new construction of oil and gas-related infrastructure associated with new federal leases. There has been no federal expansion of oil drilling along California’s coastline for more than three decades, and public opinion polling in the state has shown Californians oppose more oil drilling off the coast.Back in 2015, the state experienced its worst oil spill in 25 years when a ruptured oil pipeline spilled over 140,000 gallons of crude into the ocean, and coastal beaches near Refugio State Beach in Santa Barbara County. On Friday, a jury in Santa Barbara County convictedTexas-based Plains All-American Pipeline of nine criminal charges related to the spill, including a felony for failing to properly maintain its pipeline infrastructure.
ExxonMobil strikes deal with Alaska to feed LNG project – ExxonMobil has agreed on terms and conditions for the sale of its 13.8 Tcf of natural gas resources in the Prudhoe Bay and Point Thomson fields of Alaska’s North Slope to Alaska Gasline Development Corp., the state-owned entity leading development of the Alaska LNG Project, state and AGDC officials announced Monday. The agreement follows a similar commitment of gas to the LNG project made last May by BP, also a major North Slope gas owner. State Commissioner of Natural Resources Andy Mack said the two agreements commit 22.7 Tcf to the LNG project, the majority of the about 32 Tcf of gas identified on the slope. The figures include the state’s royalty share of gas, which ranges between 12.5% and 16.6% of the gas depending on the leases involved. “Today’s announcement is further evidence that the major North Slope producers are committed to this project. It’s good news, but it’s just one step of many needed for a major project like this,” Mack told a briefing for reporters. As part of the deal, the state reached an agreement with ExxonMobil to modify certain terms of a 2012 lawsuit settlement with the owners of Point Thomson, the largest stakes in which are held by ExxonMobil and BP, Mack said. ConocoPhillips, the third major North Slope gas owner, is still in discussions with AGDC on commitment of its gas to the project,
Prices Slide As Weather Moderates And Summer Comes To A Close — Highlights of the Natural Gas Summary and Outlook for the week ending September 7, 2018 follow. The full report is available at the link below.
- Price Action: The October contract fell 14.0 cents (4.8%) to $2.776 on a 14.5 cent range ($2.904/$2.759).
- Price Outlook: Weather forecasts are beginning to moderate and summer cooling demand is rapidly coming to a close. However, the storage deficit remains daunting and although US production is set to rise, impending nuclear maintenance may keep power burn elevated and the storage deficit to the 5-year looks to remain very high for the next two weeks. For daily updated storage projections, subscribe to our joint publication with RBN Energy. CFTC data indicated a (21,987)contract reduction in the managed money net long position as longs liquidated and shorts added. This is the lowest long position since January 5, 2016. Total open interest rose 57,630 to 3.830 million as of September 04. Aggregated CME futures open interest rose to 1.657 million as of September 07, a new record. The current weather forecast is now warmer than 8 of the last 10 years. Pipeline data indicates total flows to Cheniere’s export facility were at 2.8 bcf. Cove Point is net exporting 0.7 bcf.
- Weekly Storage: US working gas storage for the week ending August 31 indicated an injection of +63 bcf. Working gas inventories rose to 2,568 bcf. Current inventories fall (652) bcf (-20.2%) below last year and fall (581) bcf (-18.4%) below the 5-year average.
- Storage Outlook: The EIA weekly implied flow was 2 bcf from our EIA storage estimate. Although our weekly storage error has been somewhat disappointing, over the last 5 weeks the EIA has reported total injections of 232 bcf compared to our 233 bcf estimate and that is more than acceptable. The forecasts use a 10-year rolling temperature profile past the 15-day forecast. Our joint publication with RBN updates storage projections daily.
- Supply Trends: Total supply rose 0.7 bcf/d to 80.5 bcf/d. US production rose. Canadian imports rose. LNG imports rose. LNG exports rose. Mexican exports fell. The US Baker Hughes rig count was unchanged +0. Oil activity decreased (2). Natural gas activity increased +2. The total US rig count now stands at 1,048 .The Canadian rig count fell (24) to 204. Thus, the total North American rig count fell (24) to 1,252 and now exceeds last year by +106. The higher efficiency US horizontal rig count rose +1 to 918 and rises +125 above last year.
- Demand Trends: Total demand rose +2.1 bcf/d to +72.1 bcf/d. Power demand rose. Industrial demand fell. Res/Comm demand rose. Electricity demand rose +4,347 gigawatt-hrs to 89,856 which exceeds last year by +12,756 (16.5%) and exceeds the 5-year average by 4,846 (5.7%%).
The cooling season is now entering its final stretch. With a forecast through September 21 the 2018 total cooling index is at 5,367 compared to 4,638 for 2017, 5,391 for 2016, 4,230 for 2015, 3,351 for 2014, 4,793 for 2013, 7,110 for 2012 and 6,577 for 2011.
US natural gas in storage increases 69 Bcf to 2.636 Tcf: EIA – US natural gas in storage increased by 69 Bcf to 2.636 Tcf for the week ended September 7, the US Energy Information Administration reported Thursday. The build was slightly less than an S&P Global Platts’ survey of analysts calling for a 70-Bcf addition. The injection was less than both the 87-Bcf build reported during the corresponding week in 2017 and the five-year average addition of 76 Bcf, according to EIA data. As a result, stocks were 662 Bcf, or 20%, less than the year-ago level of 3.298 Tcf and 595 Bcf, or 18%, less than the five-year average of 3.232 Tcf. The injection was more than the 63-Bcf build reported the week prior as cooler temperatures across the South dropped gas-fired power generation by 7 Bcf, with estimates in Texas reaching the lowest levels since June, according to S&P Global Platts Analytics. The East region added 20 Bcf to 659 Bcf, which was 103 Bcf less than the five-year average. The Midwest gained 32 Bcf to 734 Bcf and is now 155 Bcf below average. A 4-Bcf injection in the Mountain region brought stocks up to 166, or 29 Bcf less than average, while the Pacific also added 4 Bcf to 250 Bcf, compared the five-year average of 326 Bcf. South Central posted a 7-Bcf injection, bringing volumes to 806 Bcf, which is 226 Bcf below average. At 2,636 Bcf, total working gas is below the five-year historical range. The NYMEX October Henry Hub natural gas futures added 1.3 cent to $2.842/MMBtu following the 10:30 am EDT storage announcement. Over the past five years, storage levels peaked in the week ending November 9 at 3.8 Tcf. That would allow for nine more injections before the flip to net withdrawals begin. An early forecast for at least the next three weeks show no reduction in the deficit, according to Platts Analytics. Storage is expected to peak at approximately 3.3 Tcf before the switch to withdrawals in early November. If so, it would be the lowest level to start the heating season since 2005 when stocks peaked at 3.2 Tcf. However, high gas production has kept prices from rising despite the large storage deficit.
Natural Gas Price Moves Higher Briefly After Storage Report – The U.S. Energy Information Administration (EIA) reported Thursday morning that U.S. natural gas stockpiles increased by 69 billion cubic feet for the week ending August 31. Analysts were expecting a storage injection of around 65 billion cubic feet. The five-year average for the week is an injection of 74 billion cubic feet, and last year’s storage increase for the week totaled 87 billion cubic feet. Natural gas inventories rose by 63 billion cubic feet in the week ending August 31. Natural gas futures for October delivery traded up about a penny in advance of the EIA’s report, at around $2.83 per million BTUs, and it rose to about $2.85 shortly after the report was released. For the period between September 13 and September 19, NatGasWeather.com predicts “moderate” demand and offers the following outlook: It remains hot over the Southwest with 90s and 100s, while also hot over the Southeast with lower 90s. Warm high pressure will strengthen over the northern half of the country to close out the week with 80s becoming widespread besides the Northwest. In its Short-term Energy Outlook published earlier this week, the EIA forecast dry natural gas production to average 81 billion cubic feet per day in 2018, up by 7.4 billion cubic feet in 2017 and establishing a new record high. The agency expects natural gas production will continue to rise in 2019 to an average of 84.7 billion cubic feet per day. Total U.S. stockpiles slipped slightly week over week to 20.1% below last year’s level and rose to 18.4% below the five-year average. The EIA reported that U.S. working stocks of natural gas totaled about 2.636 trillion cubic feet at the end of last week, around 596 billion cubic feet below the five-year average of 3.232 trillion cubic feet and 662 billion cubic feet below last year’s total for the same period. Working gas in storage totaled 3.298 trillion cubic feet for the same period a year ago.
Henry Hub Natural Gas to Average $2.99 in ’18, $3.12 in ’19, Says EIA – Relatively low storage levels, robust domestic consumption and growing export levels are propping up Henry Hub prices, which are expected to average $2.99/MMBtu this year and $3.12/MMBtu in 2019, slightly higher than previously forecast, according to the Energy Information Administration (EIA).Both price forecasts, found in EIA’s latest Short-Term Energy Outlook (STEO), are up marginally from last month, when the agency said it expected 2018 Henry Hub prices to average $2.96/MMBtu and upward pressure to push average prices to $3.10/MMBtu in 2019.New York Mercantile Exchange contract values for December 2018 delivery traded during the five-day period ending Sept. 6 suggest a price range of $2.31-3.77/MMBtu, encompassing the market expectation of Henry Hub prices in December at the 95% confidence level, EIA said.The front-month natural gas futures contract for delivery at Henry Hub settled at $2.77/MMBtu on Sept. 6, an increase of 1 cent/MMBtu from Aug. 1.”The Henry Hub natural gas spot price averaged $2.96/MMBtu in August, 12 cents/MMBtu higher than in July,” EIA said. “Cooling degree days in the United States averaged 13% higher than the 10-year (2008-2017) average in August, which contributed to high natural gas demand for power generation.”Natural gas inventories have been low this year compared to the five-year (2013-2017) average, reflecting relatively high residential and commercial gas consumption early in the year and growth in both liquefied natural gas and pipeline exports throughout the year, according to EIA.Last week, EIA reported a 63 Bcf build, growing natural gas inventories to 2,568 Bcf/d, which was 643 Bcf below the same time a year earlier and 590 Bcf below the five-year average. EIA is forecasting that natural gas inventories will reach 3,308 Bcf by the end of October, which would be the lowest end-of-October inventory level since 2005.
Oil set to be toppled as North America’s ‘main energy source’ this year, risk management firm says –Oil will be toppled as North America‘s primary energy source this year, according to risk management firm DNV GL, with natural gas and electrification set to reshape the region’s energy future.The Norway-headquartered firm said Monday that overall energy demand in the U.S. and Canada would continue to decline over the coming months, as improving efficiencies in the transport sector dramatically reduce North America’s reliance on oil.”Energy efficiency is going to outpace the growth in GDP (gross domestic product), that’s the main reason why energy demand is peaking,” DNV GL’s group president and CEO Remi Eriksen told CNBC’s “Squawk Box Europe” on Monday.”(And) there will be a massive change in technology in the transport sector, not only on the roads but also at sea,” he added.In a separate report published Monday by DNV GL, the company said “natural gas is set to overtake oil as the region’s largest single energy source (this year) and remain the dominant source until 2050.”DNV GL predicted overall energy demand in the U.S. and Canada would continue to shrink as the regional economy becomes less based on manufacturing and as electricity plays a greater role. This would eventually lead to energy demand falling 43 percent by 2050, it added. The world’s largest oil firms have different views over the potential for an oil demand peak, but all say that even if demand peaks, trillions of dollars of investments in oil gas would be required to develop new barrels.
The United States is now the largest global crude oil producer – The United States likely surpassed Russia and Saudi Arabia to become the world’s largest crude oil producer earlier this year, based on preliminary estimates in EIA’s Short-Term Energy Outlook (STEO). In February, U.S. crude oil production exceeded that of Saudi Arabia for the first time in more than two decades. In June and August, the United States surpassed Russia in crude oil production for the first time since February 1999. Although EIA does not publish crude oil production forecasts for Russia and Saudi Arabia in STEO, EIA expects that U.S. crude oil production will continue to exceed Russian and Saudi Arabian crude oil production for the remaining months of 2018 and through 2019. U.S. crude oil production, particularly from light sweet crude oil grades, has rapidly increased since 2011. Much of the recent growth has occurred in areas such as the Permian region in western Texas and eastern New Mexico, the Federal Offshore Gulf of Mexico, and the Bakken region in North Dakota and Montana. The oil price decline in mid-2014 resulted in U.S. producers reducing their costs and temporarily scaling back crude oil production. However, after crude oil prices increased in early 2016, investment and production began increasing later that year. By comparison, Russia and Saudi Arabia have maintained relatively steady crude oil production growth in recent years. Saudi Arabia’s crude oil and other liquids production data are EIA internal estimates. Russian data mainly come from the Russian Ministry of Oil, which publishes crude oil and condensate numbers. Other sources used to inform these estimates include data from major producing companies, international organizations (such as the International Energy Agency), and industry publications, among others.
U.S. Hydraulic Fracturing Market Estimated to be Valued at $13.91 Billion by 2025 | Hexa Research – The U.S. Hydraulic Fracturing Market to reach USD 13.91 billion by 2025, owing to the rise in the oil and gas exploration and extraction activities in the country over the forecast period. There is a rise in the demand for primary energy resources owing to the rise in population and industrialization. To meet these demands and ensure the continuous supply of natural resources in the country, the market for unconventional techniques such as hydraulic fracturing is expect to grow over the forecast period. This technology was first employed in in the U.S.in 1947 and has been constantly upgraded since then. In 2015, around 67% of natural gas was produced from hydraulically fractured wells in the country. The U.S. hydraulic fracturing market is expected to grow significantly owing to the rise in the recent developments and innovations such as using hydraulic fracturing in combination with horizontal drilling during shale formations. This has revealed new sources for huge amount of natural gas supplies, which is fulfilling the energy needs of the nation and is expected to transform the energy future. The use of this technology was first employed around the year 2000 after which it was continuously being used in the oil and gas production and extraction processes. There is a significant rise in the domestic oil and gas production from hydraulically fractured oil and gas production wells. In 2015, the production of oil from hydraulically fractured reservoirs accounted for more than 50% of the total oil production and the gas production accounted for around 70% of the total gas production in the country. This combination technology of directional drilling and hydraulic fracturing allows the oil and gas reservoirs to be punctured directionally or horizontally alongside the foundation of targeted rocks, giving exposure to the rock formation bearing oil and gas in the production well, which is expected to drive the growth for this market over the forecast period.
EIA Cuts Forecast For 2019 US Crude Production Growth (Reuters) – U.S. crude oil production in 2019 is expected to grow at a slower rate than previously forecast, according to a monthly U.S. government forecast on Tuesday. U.S. crude production is expected to rise by 840,000 barrels per day (bpd) to 11.5 million bpd next year, lower than a previous expectation for it to rise 1.02 million bpd to 11.7 million, according to a report from the U.S. Energy Information Administration. Oil demand growth in 2019 is expected to rise by 250,000 bpd, a decrease from EIA’s previous projection for an increase of 290,000 bpd. The agency largely left 2018 production and demand growth forecasts unchanged. A shale boom has helped send U.S. production surging above 10 million bpd this year for the first time since the 1970s. But drilling activity in the Permian basin, the largest U.S. oil patch, has begun showing signs of a slowdown due to limited pipeline takeaway capacity. U.S. crude oil production in 2018 is expected to grow 1.31 million barrels per day (bpd) to 10.66 million bpd, little changed from EIA’s previous forecast. Demand in 2018 is likely to grow by 470,000 bpd, also unchanged. “EIA’s September outlook revised expectations for Brent spot prices upward to an average of $73 per barrel for 2018,” EIA Administrator Linda Capuano said. “The change was largely due to lower expectations for Canada’s crude oil production and OPEC’s condensate production,” she said. Saudi Arabia wants oil to stay between $70 and $80 a barrel for now as the world’s biggest crude exporter strikes a balance between maximizing revenue and keeping a lid on prices until U.S. congressional elections in November, OPEC and industry sources have told Reuters. EIA forecasts Brent spot prices to average $74 per barrel in 2019.
Why a ‘new energy order’ is threatening shareholder returns for oil companies —Oil companies are soon to be stuck between a rock and a hard place despite increased oil prices, according to energy analysts at J.P. Morgan.Under pressure from consumers and governments to transition to new and greener energy sources, oil majors will have to “reinvent themselves,” Christyan Malek, head of EMEA oil and gas research at the bank, told CNBC’s “Squawk Box Europe” on Tuesday.But this will increase capital expenditure and thereby hit shareholder returns, the companies’ primary lure for investors, he added.In a research note published this week, J.P. Morgan described a “trilemma” facing oil firms: traditional oil and gas revenue growth, energy transition to reduce carbon footprint, and returning surplus cash to shareholders. “The industry has gotten to a point where they can no longer pay lip service, they have to spend dollars [on diversifying],” Malek said. “But they’ve got to do that whilst giving back cash to shareholders, as well as supporting the bread and butter business. To do all three is very difficult, and that is why we think the sector’s risk-reward is, at best, challenged.” Fossil fuels divestments now total an eye-popping $6 trillion, with nearly 1,000 institutional investors having pledged to divest from coal, oil and gas under pressure from environmental groups, governments and increasingly conscientious consumers. This is according to a recently-published divestment report from Arabella Advisors, which revealed an increase in divestment from the 2016 figure of $5.2 trillion. The growing movement has been led by the insurance industry but followed by universities across 37 countries, sovereign wealth funds, medical institutions, cities including New York, and the nation of Ireland. The Church of England last month voted to divest from fossil fuel companies if by 2023 they had not shown ample progress in abiding by the parameters of the Paris Climate Accord to limit global warming. Oil majors like Shell have publicly labeled divestment as a material risk.
Next Financial Crisis Lurks Underground – In 10 years, fracking in America has turned the energy world upside down. A decade and a half ago, Congress was hand-wringing about impending shortages of oil and natural gas. By the end of 2015, President Barack Obama lifted the ban against oil exports. Today, America is the world’s largest producer of natural gas and is an oil powerhouse, ready to eclipse both Saudi Arabia and Russia. This has led to muscular claims about American energy wealth. Erik Norland, executive director of CME Group, a derivatives marketplace,calls fracking “one of the top five things reshaping geopolitics.” This radical change has resulted in widespread concern about the impact of fracking on the environment, about earthquakes and water contamination. But another, less well-known controversy may prove to be more important. Some of fracking’s biggest skeptics are on Wall Street. They argue that the industry’s financial foundation is unstable: Frackers haven’t proven that they can make money. “The industry has a very bad history of money going into it and never coming out,” says the hedge fund manager Jim Chanos, who founded one of the world’s largest short-selling hedge funds. The 60 biggest exploration and production firms are not generating enough cash from their operations to cover their operating and capital expenses. In aggregate, from mid-2012 to mid-2017, they had negative free cash flow of $9 billion per quarter. These companies have survived because, despite the skeptics, plenty of people on Wall Street are willing to keep feeding them capital and taking their fees. From 2001 to 2012, Chesapeake Energy, a pioneering fracking firm, sold $16.4 billion of stock and $15.5 billion of debt, and paid Wall Street more than $1.1 billion in fees, according to Thomson Reuters Deals Intelligence. A key reason for the terrible financial results is that fracked oil wells show a steep decline rate: The amount of oil they produce in the second year is drastically smaller than the amount produced in the first year. According to an economist at the Kansas City Federal Reserve, production in the average well in the Bakken – a key area for fracking shale in North Dakota – declines 69 percent in its first year and more than 85 percent in its first three years. A conventional well might decline by 10 percent a year. For fracking operations to keep growing, they need huge investments each year to offset the decline from the previous years’ wells.
No fracking boom if not for low interest rates after financial crisis, CNBC contributor says – video – Bethany McLean, author and CNBC contributor, says fracking companies haven’t proven that they can produce cash flow and have incurred a lot of debt, which isn’t good for shareholders.
Barge holding fuel drifts near Skidegate Inlet – A barge carrying thousands of litres of fuel broke free from its moorings during Saturday’s storm and has drifted southeast of Queen Charlotte near the community of Skidegate in Haida Gwaii. The Canadian Coast Guard has responded and is working with the barge’s owner as well as Haida Gwaii Nation and provincial and federal authorities to manage any public safety and environmental risks. “We are also mobilizing a hazmat team to do an initial search of the vessel,” Jocelyn Lubczuk, a spokesperson with the Canadian Coast Guard, said. Lubczuk said the luxury fishing lodge was moored in Alliford Bay but was spotted adrift in Skidegate Bay near Jewell Island around 9:30 p.m. and a four-inch crack in the hull kept it grounded on the island’s shore. The Western Canada Marine Response Corporation (WCMRC), which handles marine spills, was called in to help and its skimming vessel was dispatched from Prince Rupert. “We staged some equipment nearby. Right now the barge is on the ground so it is right up on the beach. It is not spilling,” While no pollution has been observed, authorities are carefully watching the situation. “The estimated volume of hydrocarbons on board is about 18,000 litres of gas and about 15,000 litres from diesel. We haven’t observed any pollution in the water yet,” Lubczuk said.
First Nations group proposes oil pipeline that protects indigenous rights – First Nations have played a central part in Canada’s national debate over pipeline projects, leading protests that have seen thousands take to the streets or building tiny homes in hopes of thwarting construction.Behind the scenes, however, one group has been quietly refining a precedent-setting proposal that they say offers a means of protecting indigenous rights while unlocking the country’s vast oil and gas reserves: a First Nations-led pipeline.“We did this because First Nations wanted to be able to demonstrate how to do this right,” said Calvin Helin, the chairman and president of Eagle Spirit Energy Holdings and a member of the Lax Kw’alaams band on Canada’s west coast. Six years in the making, plans for the Eagle Spirit pipeline envision transporting up to 2m barrels a day of medium to heavy crude oil from Alberta’s landlocked oil sands to tide water on the west coast.The proposal still faces considerable hurdles, leading some to describe the project as far-fetched. But Helin describes it as an alternative way forward at a time when the politics around pipelines has become increasingly sensitive.The project was launched amid complaints by some First Nations over the Northern Gateway pipelines, a proposed project that sought to carry Alberta oil to a port in northern British Columbia for export. Despite their concerns about the project’s environmental standards, the communities most affected by the proposal didn’t feel like anyone was paying attention, said Helin.Their viewpoint was vindicated in 2016 when a court ruled that Ottawa had failed in its duty to consult with aboriginal groups. Soon after, the project was cancelled by the prime minister, Justin Trudeau.It was a victory for First Nations, said Helin. “But at the end of the day, they weren’t opposed to pipelines. And so they came together and have led this project from the very beginning.”The Eagle Spirit pipeline – since expanded into plans for a C$12bn ($9bn) multi-pipeline energy corridor that could include liquefied natural gas and natural gas liquids – would see First Nations become the major equity holders, giving them a share of the profits and control over its environmental model. According to Helin, so far the project has the support of 34 of the 35 communities it would traverse. “We’ve just gotta have meetings with one community,” he said. “We’ve gone to great pains to meet with everybody, we’ve done thousands of meetings.”
Mexico oil production to reach 2.6 mil b/d by 2025: Lopez Obrador – Mexico’s President-elect Andres Manuel Lopez Obrador said Sunday he plans to focus on developing and exploring onshore and shallow water areas under the control of state oil company Pemex to boost the country’s oil production. “We have a projection, and our plan is to have production of at least 2.6 million b/d by the end of the presidential term; additional production of 800,000 b/d,” Lopez Obrador said in webcast press conference. Lopez Obrador was speaking to journalists after a meeting with Mexican drilling and oil service companies at Villahermosa in Tabasco. Mexico’s production averaged 1.8 million b/d in July, down from an historical high of 3.4 million b/d in 2004, latest data from Mexico’s National Hydrocarbon Commission showed. Lopez Obrador said the incoming administration plans to tender drilling contracts in December when his six-year term begins to develop Pemex’s shallow water and inland areas to boost oil production. “We are inviting all companies to participate in these tenders. However, we will have a preference over domestic contractors,” he added. He said he planned to add Peso 75 billion ($3.9 billion) to Pemex’s exploration and production budget to boost drilling and thus raise output. The tenders will help Mexico reverse its production downtrend by the end of 2019, he added. Mexico’s oil industry is at a crisis as a result of low public investment in the sector. Pemex in 2017 had an E&P capital expenditure budget of Peso 81.5 billion, down from Peso 222 billion in 2014, the company’s annual financial statements show. The cut in Pemex’s budget resulted in a significant decrease in drilling activity; it drilled 83 wells in 2017, compared with 705 in 2013. Lopez Obrador blamed the previous administration for Pemex’s lower capital expenditure, claiming it was done on purpose amid expectations the private sector would offset lower activity from the state company. “It has been a complete failure, this wrongly named energy reform,” Lopez Obrador said The president-elect has historically been an opponent of private participation in Mexico’s energy sector. His critics note Pemex’s spending cuts reflect lower global oil prices after 2014.
Worldwide oil and gas rig count grows again – The number of working oil and gas rigs working worldwide grew again month-on-month in August 2018 according to the Baker Hughes, a GE company, (BHGE) monthly rig count, monitored by Kallanish. The rise was due to a monthly increase in the number of international and Canadian rigs. The U.S. rig count, was unchanged on-month, whilst still remaining ahead year-on-year.The number of rigs operating in the US remained at 1050 following increases in April, May and June and a fall in July. Numbers in Canada grew strongly again m-o-m in August, rising by 16 units to 220.The North American rig count for the month was therefore 1,270, an increase of 16 (1.3%) m-o-m and still up by 106 (9.1%) y-o-y. The international rig count for August 2018 was 1008, up by 11 from the 997 polled in July and also well ahead of the 952 rigs counted in August 2017.The worldwide rig count for August 2018 was 2,278 therefore, up by 27 (1.2%) from the 2,251 counted in July and up by 162 (7.7%) from the 2,116 counted in the same period 12 months before.Internationally, the rig count rose m-o-m in all monitored regions except Asia Pacific. It rose by 6 in Africa to 104 although numbers in the Asia Pacific region fell by 4 rigs to 225. The rig count ticked up again m-o-m in Latin America by 2 to 192. The count in Europe rose m-o-m by 5 rigs to 85. The second largest region in terms of rig numbers after North America, the Middle East, also saw working rig numbers improve by 2 to 402. This was 11 more than in August 2017. The BHGE Rotary Rig Counts assess the number of rotary drilling rigs actively exploring for or developing oil or natural gas in the United States, Canada and international markets.
Ports compete to build ‘white elephant’ gas terminal — Three German cities are competing to become the site of Germany’s first import terminal for liquified natural gas (LNG). Whichever of Stade, Brunsbüttel and Wilhelmshaven, all located on or close to the country’s North Sea coast, wins the contract, they will likely be helped by substantial federal government subsidies.Plans to liquefy gas from the North Atlantic coast of the United States and Canada are well advanced, and German energy giant Uniper agreed to a 20-year deal to buy LNG from Pieridae, the Canadian enterprise behind the scheme. After liquification, the gas would be shipped across the Atlantic in tankers. But as yet there are no ports in Germany with an LNG terminal equipped to process the gas and deliver it into the national network. Berlin is very keen to see the infrastructure developed, citing the need for energy supply diversification.
US Warns Russia It May Sanction New Gas Pipeline to Germany— The U.S. warned Russia that it may follow through on sanction threats over the construction of a major natural gas pipeline to Germany. Asked if the U.S. might impose punitive measures against Nord Stream 2 and other projects, Energy Secretary Rick Perry answered “yes,” during a joint news conference with his Russian counterpart Alexander Novak on Thursday in Moscow. “Minister Novak and I both agree that getting to that point of sanctions is not where we want to go,” he said. Perry urged Russia to be a “responsible supplier” and to stop using its resources for “influence and disruption,” adding that the U.S. opposes the gas link because it would concentrate two-thirds of Russian exports of the fuel to the European Union in a single choke point. Novak said that Russia was concerned if the U.S. sanctions a “competitive” gas pipeline. Nord Stream 2 would double Russia’s current capacity to deliver natural gas directly to Germany under the Baltic Sea and circumvent Ukraine. The project would be a major supply route to the EU and has been a sore point between the U.S. and its allies. In July, U.S. President Donald Trump slammed what he called German dependence on Russian energy, saying it made the nation “captive” to Moscow. The Kremlin said Trump’s attacks were economically motivated and an attempt to promote U.S. liquefied natural gas in Europe. Later that month, Trump eased his tone after a summit with President Vladimir Putin, saying the U.S. could compete successfully with the Russian gas pipeline even if the project wasn’t in Germany’s best interests
Russia, Japan discuss energy cooperation, sign LNG agreement in Vladivostok – Russia and Japan are considering further expansion of their economic cooperation, a core element of which is energy projects, following a meeting between national leaders and the signing of new cooperation agreements between several companies in Vladivostok on Monday. “The energy sector is a key area of bilateral cooperation,” Russian President Vladimir Putin said following a meeting with Japanese Prime Minister Shinzo Abe, ahead of the opening of the Eastern Economic Forum in Vladivostok on Tuesday. Putin said the LNG sector in particular was a key focus area for future cooperation, noting that Japanese companies may take part in the planned expansion of Sakhalin 2, Arctic LNG 2 and Baltic LNG projects as well as an LNG transshipment facility in Kamchatka. Following the meeting on Monday, several Russian and Japanese companies signed agreements, including Novatek and Jogmec who signed a memorandum of understanding on LNG cooperation. The MoU covers exploring opportunities for cooperation “on Novatek’s projects in the Yamal and Gydan peninsulas, including the Arctic LNG 2 project and on developing a regular transport link via the Northern Sea Route for LNG deliveries to the Japanese and Asia-Pacific markets, as well as exploring LNG marketing opportunities in the Asia-Pacific region,” Novatek said.