Written by rjs, MarketWatch 666
Here are some selected new articles from the week ended 20 January 2019.
This article is a feature every Monday evening on GEI.
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US oil production at a record high; rig count drops by most in 35 months…
Oil prices rose for a third consecutive week, and while they ended the week more than 20% higher than their December 27th nadir, they still remain almost 30% below their October 3rd closing high…after rising 7.6% to $51.59 a barrel on hopes for a resolution of the US-China trade war last week, US oil prices for February delivery opened this week higher but quickly weakened and ended Monday $1.08 lower at $50.51 a barrel, pressured by weak Chinese trade data that increased concerns that a global economic slowdown would hurt crude demand…however, oil prices turned around rose with global stock markets on Tuesday, propelled by a Chinese fiscal stimulus intended to reverse their slowing economy, with U.S. crude prices ending $1.60, or 3.2%, higher at $52.11 a barrel…buoyed by a rising stock market, oil prices continued higher early Wednesday, but then fell back over $1 at midday after the EIA report showed record crude production and much higher refined product inventories, but recovered late in the session to end the day 20 cents higher at $52.31 a barrel…weighed by that surging U.S. crude output and weakening global demand, oil prices turned lower early Thursday, tumbling to as low at $50.98 a barrel, before recovering to close with a loss of just 24 cents at $52.07, on a rebound in U.S. stocks and a report that OPEC had sharply curtailed production in December...after a quiet Friday morning, oil jumped 3.3% to a 2-month high on news that China had proposed to eliminate its trade surplus by importing more US goods, with oil closing $1.73 higher at $53.80 a barrel…US crude for February thus ended the week 4.3% higher, while the international benchmark Brent crude for March, which had seen a steeper pullback early in the week, ended 3.7% higher at $62.70 a barrel..
Meanwhile, natural gas prices spiked nearly 16% higher to $3.591 per mmBTU on Monday, largely on forecasts for a long, severe cold spell, but struggled to maintain that price level the rest of the week and ended Friday at $3.482 per mmBTU, still more than 12% higher than the prior week’s close…the natural gas storage report for the week ending January 11th from the EIA indicated that the quantity of natural gas in storage in the US fell by 81 billion cubic feet to 2,533 billion cubic feet over the week, which left our gas supplies 77 billion cubic feet, or just 3.0% below the 2,610 billion cubic feet that were in storage on January 12th of last year, and 464 billion cubic feet, or 11.4% below the five-year average of 2,860 billion cubic feet of natural gas that have typically been in storage as of the 2nd weekend of January….this week’s 81 billion cubic feet withdrawal from US natural gas supplies was just about on the consensus estimate for a 82 billion cubic feet withdrawal, but it was considerably less the average of 203 billion cubic feet of natural gas that have been withdrawn from US gas storage during the first full week of January over the last 5 years…since the report now tells us that “At 2,533 Bcf, total working gas is within the five-year historical range” we’ll include this week’s graph from the natural gas storage report showing natural gas in storage over the past two years, as compared to that 5 year range…
The above graph comes from this week’s Natural Gas Storage Report, and it shows the quantity of natural gas in billion cubic feet in storage in the lower 48 states over the period from December 2016 up to the week ending January 11th 2019 as a blue line, the average of natural gas in storage over the 5 years preceding the same dates shown as a heavy grey line, while the grey shaded background represents the previous upper and lower range of natural gas in storage for any given time of year for the 5 years prior to the two years that are shown by today’s graph…thus the grey area also shows us the normal variation of natural gas storage levels as they fluctuate from season to season, with natural gas in storage underground normally building to a maximum by the first weekend in November, falling through the winter, and usually bottoming out at the end of March or the first week of April, depending of course on the spring heating requirements in any given year…notice how our supplies of natural gas in blue started last year’s heating season fairly close to the 5 year average of natural gas in storage shown in dark grey, then diverged over the year, beginning with the colder than normal January, with the gap separating the grey “normal” line and the blue current supply line slowly getting increasingly wider, until it finally fell below the 5 year low, represented by the grey shaded area, in July of this year…from that time until mid November, the gap between our natural gas supplies and the previous 5 year minimum became progressively wider, until a milder than normal December allowed for a period of slower than normal depletion…with the exceptional warmth over the 4 most recent weeks (see map below for the most recent week), we have only needed to withdraw 240 billion cubic feet of natural gas from storage to meet our needs; that compares to the 860 billion cubic feet of natural gas that we needed during the same 4 week period a year ago…as a result, we still had 2,533 billion cubic feet remaining in storage as of January 11th, a bit more than the 2,529 billion cubic feet of gas that were in storage on January 10th 2014, and hence we’re now “within the five-year historical range“
(source)
The Latest US Supply and Disposition of Oil Data from the EIA
This week’s US oil data from the US Energy Information Administration, reporting on the week ending January 11th, indicated a moderately large withdrawal of oil from our commercial crude supplies, largely because of a large increase in our oil exports and a modest drop in our oil imports…our imports of crude oil fell by an average of 319,000 barrels per day to an average of 7,527,000 barrels per day, after rising by an average of 454,000 barrels per day the prior week, while our exports of crude oil rose by an average of 901,000 barrels per day to an average of 2,966,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 4,561,000 barrels of per day during the week ending January 11th, 1,220,000 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 200,000 barrels per day higher at a record 11,900,000 barrels per day, so our daily supply of oil from the net of our trade in oil and from wells totaled an average of 16,461,000 barrels per day during this reporting week…
Meanwhile, US oil refineries were using 17,223,000 barrels of crude per day during the week ending January 11th, 343,000 fewer barrels per day than the amount of oil they used during the prior week, while over the same period 383,000 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 would seem to indicate that our total working supply of oil from net imports, from oilfield production and from storage was 379,000 barrels per day short of what refineries reported they used during the week….to account for that disparity between the supply of oil and the disposition of it, the EIA inserted a (+379,000) 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”….(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports rose to an average of 7,605,000 barrels per day last week, but was still 3.6% less than the 7,892,000 barrel per day average that we were importing over the same four-week period last year….the 383,000 barrel per day increase in our total crude inventories was due to a 383,000 barrel per day withdrawal from our commercially available stocks of crude oil, while the oil stored in our Strategic Petroleum Reserve remained unchanged….this week’s crude oil production was reported 200,000 barrels per day higher at 11,900,000 barrels per day because the rounded estimate for output from wells in the lower 48 states increased by 200,000 barrels per day to 11,400,000 barrels per day in light of last week’s confirmed monthly figures, while a 2,000 barrel per day increase to 507,000 barrels per day in oil output from Alaska was not enough to change the rounded national total…last year’s US crude oil production for the week ending January 12th was at 9,750,000 barrels per day, so this week’s rounded oil production figure was 22.1% above that of a year ago, and 41.2% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016…
US oil refineries were operating at 94.6% of their capacity in using those 17,223,000 barrels of crude per day during the week ending January 11th, down from last week’s 96.1% of capacity, but still the highest capacity utilization rate for the second week of January since 1999….likewise, the 17,223,000 barrels per day of oil that were refined this week were again at a seasonal high for the date for the 29th time out of the past 33 weeks, and 2.1% higher than the 16,875,000 barrels of crude per day that were being processed during the week ending January 12th, 2017, when US refineries were operating at 93.0% of capacity…
Even with the decrease in the amount of oil being refined, the gasoline output from our refineries was higher, rising by 192,000 barrels per day to 9,584,000 barrels per day during the week ending January 11th, after our refineries’ gasoline output had decreased by 752,000 barrels per day to a 50 week low during the prior two weeks…hence, even with the modest increase in this week’s gasoline output, our gasoline production was still 1.3% lower than the 9,710,000 barrels of gasoline that were being produced daily during the same week last year….meanwhile, refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 151,000 barrels per day to 5,412,000 barrels per day, after that output had decreased by 28,000 barrels per day the prior week….despite that decrease, this week’s distillates production was 6.6% higher than the the 5,076,000 barrels of distillates per day that were being produced during the week ending January 12th, 2018….
With the increase in our gasoline production, our supply of gasoline in storage at the end of the week jumped by 7,503,000 barrels to 255,565,000 barrels by January 11th, after jumping by a 3 year high of 8,066,000 barrels during the week ending January 4th….our gasoline supplies rose this week as the amount of gasoline supplied to US markets fell by 170,000 barrels per day to 8,565,000 barrels per day, while our imports of gasoline fell by 173,000 barrels per day to 377,000 barrels and our exports of gasoline rose by 103,000 barrels per day to 830,000 barrels per day….with this week’s increase, our gasoline inventories are at a seasonal high for the second week of January, 4.5% higher than last January 12th’s level of 237,322,000 barrels, and roughly 5% above the five year average of our gasoline supplies for this time of the year…
Even with the decrease in our distillates production, our supplies of distillate fuels increased for the 6th time in seventeen weeks, rising by 2,967,000 barrels to 143,009,000 barrels during the week ending January 11th, after our distillates supplies had increased by a record 20,140,000 barrels over the previous two weeks…our distillates supplies increased this week even though the amount of distillates supplied to US markets, a proxy for our domestic demand, rose by 1,494,000 barrels per day to 4,449,000 barrels per day (after falling by 1,911,000 barrels per day over the course of the prior 3 weeks), in part because our imports of distillates rose by 117,000 barrels per day to 378,000 barrels per day, while our exports of distillates fell by 436,000 barrels per day to 917,000 barrels per day….as a result of this week’s increase, our distillate supplies were 2.7% above the 143,088,000 barrels that we had stored on January 12th, 2017, even as they remained 3% below the five year average of distillates stocks for this time of the year…
Finally, with soaring exports and falling imports, our commercial supplies of crude oil decreased for sixth time in 7 weeks, falling by 2,683,000 barrels over the week, from 439,738,000 barrels on January 4th to 437,055,000 barrels on January 11th…however, with a run of 10 large weekly increases before the recent smaller decreases, our crude oil inventories are still roughly 8% above the five-year average of crude oil supplies for this time of year, and roughly 30% above the 10 year average of crude oil stocks for the second week of January, with the disparity between those figures arising because it wasn’t until early 2015 that our oil inventories first rose above 400 million barrels…since our crude oil inventories have mostly been rising since this Fall, after falling through most of the past year and a half until then, our oil supplies as of January 11th were thus 5.9% above the 412,654,000 barrels of oil we had stored on January 12th of 2017, while remaining nearly 10% below the 485,456,000 barrels of oil that we had in storage on January 13th of 2016, and 3.9% below the 455,169,000 barrels of oil we had in storage on January 8th of 2015..
OPEC’s Monthly Oil Market Report
This week we’re also going to review OPEC’s January Oil Market Report (covering December OPEC & global oil data), which was released on Thursday of this past week, and which 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 56 of that report (pdf page 66), 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 dropped by 751,000 barrels per day to 31,578,000 barrels per day in December, from their November production total of 32,328,000 barrels per day….however, in November, Qatar was still a member of OPEC, producing 615,000 barrels per day, and that November figure was originally reported as 32,965,000 barrels per day, so OPEC’s November output excluding that of Qatar was at 32,350,000 barrels per day….therefore OPEC’s November output excluding Qatar was revised 22,000 barrels per day lower with this report (for your reference, here is the table of the official November OPEC output figures as reported a month ago, before this month’s revisions)…
As you can tell from the far right column on the table above, the 468,000 barrels per day drop in the oil output from Saudi Arabia was the major factor in the 751,000 barrel per day OPEC production decrease, with largely involuntary production decreases of 172,000 barrels per day in the oil output from Libya and 159,000 barrels per day in the oil output from Iran accounting for the rest…OPEC’s December agreement called for oil producers to cut output by 1.2 million barrels per day beginning in January, so this December production cut was for all practical purposes carried out unilaterally by Saudi Arabia, with the decrease of 65,000 barrels per day in the oil output from the United Arab Emirates, their close ally, also likely intentional…..excluding new OPEC member Congo, the December output of 31,349,000 barrels per day from the remaining 13 OPEC members was 761,000 barrels per day below the 32,110,000 barrels per day revised quota they agreed to at their November 2017 meeting, (excluding the 620,000 bpd quota for Qatar), mostly due to the big drop in Venezuelan output, another OPEC country that 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 January 2017 to December 2018, and it’s taken from the page numbered 57 (pdf page 67) of the January 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 fell by 350,000 barrels per day to 100.02 million barrels per day in December, after November’s total global output figure was revised down by 270,000 barrels per day from the 100.64 million barrels per day global oil output that was reported a month ago, as non-OPEC oil production rose by a rounded 400,000 barrels per day in December after that revision, with increased US and Canadian output the major contributors to the non-OPEC increase….global oil output during December was also 2.83 million barrels per day, or 2.9% higher than the revised 97.19 million barrels of oil per day that were being produced globally in December a year ago (see the January 2018 OPEC report online (pdf) for the originally reported year ago details)…with the December decrease in OPEC’s output following the downward revision to their November output, their November oil production of 31,578,000 barrels per day represented just 31.6% of what was produced globally during the month, down from the 32.8% share they reported for November, when Qatar was still a member….OPEC’s December 2017 production was reported at 32,416,000 barrels per day, which means that the 13 OPEC members who were part of OPEC last year, excluding Qatar from last year and new member Congo from this year, are now producing 573,000 fewer barrels per day of oil than they were producing a year ago, during the twelfth month that their production quotas were in effect, with a 597,000 barrel per day decrease in output from Venezuela and a 1,060,000 barrel per day decrease in output from Iran from that time more than offsetting the production increases of 635,000 barrels per day from the Saudis, 340,000 barrels per day from the Emirates, and 309,000 barrels per day from Iraq…
Despite the 350,000 barrel per day decrease in global oil output in December, we still saw a small surplus 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 31 of the January OPEC Monthly Oil Market Report (pdf page 41), 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 in the fifth column, we’ve circled in blue the figure that’s relevant for December, which is their revised estimate of global oil demand during the fourth quarter of 2018…
OPEC’s estimate is that during the 4th quarter of last year, all oil consuming regions of the globe were using 99.94 million barrels of oil per day, which was revised from their estimate of 99.98 million barrels of oil per day of a month ago….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 100.02 million barrels per day during December, which means that there has been a surplus of around 40,000 barrels per day in global oil production as compared to the demand estimated for the month…
A month ago we estimated a global surplus of around 660,000 barrels per day in global oil production during November, based on figures published at that time…however, as we saw earlier, November’s global output figure was revised down by 270,000 barrels per day from those figures, while global demand was simultaneously revised 40,000 barrels per day lower, so with these revised figures, we now find that global oil production in November was running roughly 430,000 barrels per day greater than demand…also a month ago, we estimated a surplus of 160,000 barrels per day for October; hence, with the downward revision to 4th quarter demand, that October oil production surplus would now be 200,000 barrels per day…
While 4th quarter demand was revised 40,000 barrels per day lower, 3rd quarter demand was revised 30,000 barrels per day higher at the same time, from 99.32 million barrels of oil per day to 99.35 million barrels of oil per day…that revision now means there were supply shortfalls of 10,000 barrels per day in September, 580,000 barrels per day in August, and 960,000 barrels per day per day in July….
Since there are no revisions to supply or demand for the prior months, the surplus or shortfall figures for those months that we had recomputed last month remained unchanged; for the 2nd quarter months, we figured there were global oil shortfalls of 170,000 barrels per day in June, 610,000 barrels per day in May, and 400,000 barrels per day in April, while the first quarter of 2018 recorded global oil surpluses of 20,000 barrels per day in March, 200,000 barrels per day in February, and 40,000 barrels per day in January…
By totaling up those 12 monthly estimates of surplus or shortfall, we find that for the twelve months of 2018, global oil demand exceeded production by roughly 56,250,000 barrels, actually a comparatively tiny net oil shortfall that is the equivalent of roughly 13.5 hours of global oil production at the December production rate…..however, should the entirely of the 1.2 million barrel per day OPEC production cut come to pass, we would be looking at a much larger shortfall during this coming year, and it does not yet appear that the market is taking the possibility of an oil shortfall of that magnitude into account..
This Week’s Rig Count
US drilling activity, as evidenced by the number of drilling rigs active at the end of the week, fell by the most in 35 months during the week ending January 18th, as drilling for both oil and natural gas decreased, probably due to the recently depressed oil prices for both, and due to the 6.7 month backlog of uncompleted wells… Baker Hughes reported that the total count of rotary rigs running in the US fell by 25 rigs to 1050 rigs over the week ending January 18th, which was still 114 more rigs than the 936 rigs that were in use as of the January 19th report of 2018, but down from the shale era high of 1929 drilling rigs that were deployed on November 21st of 2014, which was the week before OPEC announced their attempt to flood the global oil market…
The count of rigs drilling for oil fell by 21 rigs to 852 rigs this week, which was the largest oil rig pullback since February 19, 2016…nonetheless, there were still 105 more oil rigs active this week than were running a year ago, while that number 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 bearing formations decreased by 4 rigs to 198 natural gas rigs, which was still 9 more rigs than the 189 natural gas rigs that were drilling a year ago, but way down from the modern high of 1,606 natural gas targeting rigs that were deployed on August 29th, 2008…
Two platforms that had been drilling in the Gulf of Mexico offshore from Louisiana were shut down this week, which reduced the Gulf of Mexico rig count to 19 rigs for this report, which the same number of rigs that were deployed in the Gulf of Mexico a year ago at this time…since there is still no other offshore drilling off either coast or off Alaska at this time, nor was there during the same week of 2017-18, that Gulf of Mexico total is identical to the US total…
The count of active horizontal drilling rigs decreased by 19 rigs to 929 horizontal rigs this week, the largest horizontal rig pullback since February 26th, 2016…however, it still left 127 more horizontal rigs active than the 802 horizontal rigs that were in use in the US on January 19th of last year, but it was down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014….in addition, the directional rig count decreased by 7 rigs to 55 directional rigs this week, which was also down from the 77 directional rigs that were in use during the same week of last year, and the lowest directional rig count since December 16, 2016….on the other hand, the vertical rig count increased by 1 rig to 66 vertical rigs this week, which was also up from the 57 vertical rigs that were operating on January 19th of 2018…
The details on this week’s changes in drilling activity by state and by shale basin are included in our screenshot below of that part of the rig count summary pdf from Baker Hughes that shows those changes…the first table below shows weekly and year over year rig count changes for the major producing states, and the second table shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of January 18th, the second column shows the change in the number of working rigs between last week’s count (January 11th) and this week’s (January 18th) count, the third column shows last week’s January 11th active rig count, the 4th column shows the change between the number of rigs running on Friday and those running before the equivalent weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 19th of January, 2018…
Offhand, i can’t understand how Oklahoma could be down 10 rigs while the Cana Woodford was up 5 rigs and the Ardmore Woodford also added another one; the Mississippian shale is partly underlying Oklahoma, but it appears the 2 rigs that were shut down in that basin were pulled out of Kansas…while 3 rigs were pulled out of the panhandle region Granite Wash basin, one of those was pulled out in Texas, still leaving a big question mark on Oklahoma activity…meanwhile, the Permian basin saw a seven rig increase, as eight rigs were pulled out of Texas Oil District 8, which is the core Permian Delaware, while a Permian Delaware rig was added on the New Mexico side of the border…note that in addition to the major producing states shown above, Montana also had a Williston basin rig shut down, leaving two active in the state, still up from 1 rig a year ago… this week’s natural gas rig situation also looks quite complicated; for starters, a natural gas rig was added in Ohio’s Utica, while at the same time one of the two Utica gas rigs which had been operating in Pennsylvania was shut down, netting zero for the basin…another gas rig was added in the West Virginia portion of the Marcellus, and yet another was added the Haynesville, in northwestern Louisiana…meanwhile, despite the Ardmore Woodford rig increase, that masked an increase of two oil rigs and a reduction of one rig targeting natural gas…similarly, the one rig increase in the Eagle Ford of south Texas included an increase of two rigs targeting oil, and a reduction of natural gas rigs from 9 to 8…and in addition, 4 natural gas rigs were pulled out of “other” basins not tracked individually by Baker Hughes, to give us the total that we reported on earlier…
Utica Shale well activity as of Jan. 12 – Seven horizontal permits were issued during the week that ended Jan. 12, and 18 rigs were operating in the Utica Shale.
- DRILLED: 235 (231 as of last week)
- DRILLING: 142 (143)
- PERMITTED: 471 (470)
- PRODUCING: 2,128 (2,124)
- TOTAL: 2,976 (2,968)
TOP 10 COUNTIES BY NUMBER OF PERMITS:
- 1. BELMONT: 608 (602 as of last week)
- 2. CARROLL: 525 (525)
- 3. HARRISON: 443 (442)
- 4. MONROE: 421 (421)
- 5. GUERNSEY: 251 (251)
- 6. NOBLE: 223 (223)
- 7. JEFFERSON: 210 (209)
- 8. COLUMBIANA: 159 (159)
- 9. MAHONING: 30 (30)
- 10. WASHINGTON: 22 (22)
- 14. STARK: 13 (13)
Seven Permits Issued in Ohio’s Utica – The Ohio Department of Natural Resources reports that it awarded seven new permits for horizontal oil and gas wells in the Utica shale region last week. According to ODNR, six permits were issued to Rice Drilling LLC for wells in Belmont County in the southeastern portion of the state. A single permit was awarded to Gulfport Energy Corp. for a new well in Harrison County. As of Jan. 12, ODNR has issued 2,976 permits across the Utica. The agency reports that 2,505 of these wells are drilled and 2,128 were in production. ODNR reported that there were 18 rigs operating in the Utica as of Jan. 12. There were no new permits issued in the northern tier of Ohio’s Utica, which includes Mahoning, Columbiana and Trumbull counties. Nor were there new Utica permits awarded in neighboring Lawrence and Mercer counties in western Pennsylvania, according to the Pennsylvania Department of Environmental Protection.
Ohio’s Utica Shale Country May See a Boost from Chesapeake Energy Leaving the Play – WKSU News — There is a new leading player in the development of Ohio’s oil and natural gas drilling industry. ENCINO Energy just bought all of the Utica shale holdings of Chesapeake Energy and says it plans to invest in those, and to keep the former Chesapeake Utica headquarters in Louisville in Stark County. ENCINO was formed a year ago by long-time Texas-based energy executives and the Canadian Pension Plan Investment Board. It’s paying $2 billion dollars for nearly one million acres of drilling rights held byChesapeake and the five story headquarters in Louisville. Stark Development Board President Ray Hexamer says ENCINO’s entry into the Utica is encouraging for both Louisville and the region. “For a community, you’d rather be someone’s first and biggest asset than one of five hundred assets. And they’re all very skilled in this industry so if they paid the amount money that they did, they see the potential.” Chesapeake sold its Utica assets to help pay down debt it took on while expanding in shale plays across the country.
Ohio Fracking Laws Contested in Sixth Circuit – – Several Ohio landowners argued before a Sixth Circuit panel Thursday that a mining company’s fracking operation under their property is unconstitutional, seeking to revive federal claims against the company and the Buckeye State. Six people and a trust that collectively own 127 acres in Harrison County, Ohio, filed a federal lawsuit against Chesapeake Exploration LLC and the state’s Division of Oil and Gas Resources Management after Chesapeake was issued a permit to drill three wells beneath the surface of the property. At the time the complaint was filed in February 2018, Chesapeake had drilled one of the wells and pumped “more than 8 million gallons of water, sand and chemicals” into the land as part of its hydraulic fracturing, or fracking, operation. Fracking involves the high-pressure injection of millions of gallons of chemical-laden water deep underground to crack rock and release oil and gas. The owners claimed the operation constituted an unlawful taking under the 14th Amendment, and also argued the Ohio law allowing for subsurface mining is unconstitutional. U.S. District Judge Patricia Gaughan disagreed, however, and granted both the mining company and the state’s motions to dismiss last June. “Plaintiffs,” she wrote, “do not allege that a well will be erected on their property or that the surface of their property will be impacted in any way by the drilling. Plaintiffs also do not allege any current surface damage.”The judge continued, “Rather, plaintiffs allege that Chesapeake will enter beneath the land, inject water, sand and chemicals beneath the land, and remove oil, gas, and natural gas liquids from beneath the land, pursuant to the unitization procedure set forth under Ohio law.” (Emphasis in original.)Judge Gaughan also determined that Chesapeake’s actions regarding the mining operation, including applying for the permit and drilling the first well, did not render it a state actor for the purposes of the landowners’ civil rights claim. Attorney Phillip Campanella argued on behalf of the landowners Thursday in the Sixth Circuit, saying his clients have “a right to exclude the invasion of the subsurface” portion of their property.
Taking on Climate Change and Petrochemicals in the Ohio River Valley – When it comes to the fossil fuel industry, we’ve all heard the promises before: new jobs, economic growth and happier communities, all thanks to their generosity and entrepreneurial spirit. But what they always fail to mention is that their business damages ecosystems, drives climate change, and fills our air and water with dangerous, carcinogenic chemicals. We know this because we’ve seen the same tragic story again and again: fossil fuels and petrochemicals causing disastrous health outcomes for normal Americans just trying to live their lives. In particular, in southern Louisiana along an 85-mile corridor of the Mississippi River between Baton Rouge and New Orleans, petrochemical plants are causing some of the nation’s highest cancer rates. There are important lessons to be learned from this area, infamously dubbed “Cancer Alley.” Especially as the fossil fuel industry plans to invest more than $200 billion in new petrochemical facilities across the U.S. in the coming years. These plants separate ethane from natural gas through the heat and pressure process described above. Plants then use it to create ethylene, one of the major building blocks used in making plastics. Not only does this process involve burning fossil fuels, but the end result is another kind of pollution. Increasing investment in these facilities will not only deepen our reliance on fossil fuels; it’ll also increase the amount of plastics that end up in our oceans – at a time when we should instead be concentrating on alternatives like clean energy. Yet, the petrochemical and fossil fuel industries keep finding ways to lock us into their products and business. We already know the threats to regional watersheds from hydraulic fracturing (fracking), including soil erosion, groundwater pollution, and drinking water contamination. But we should also recognize that the danger doesn’t stop once natural gas leaves the ground. For example, multiple studies have shown that petrochemical facilities that use natural gas expose employees – as well as surrounding communities – to multiple toxins that are incredibly damaging to their health. The results are clear. Research shows that people living and working in and near petrochemical facilities can have higher rates of cancer, diabetes, various skin conditions, respiratory problems and other life-altering diseases. In some cases, rates of toxic chemicals and carcinogens found among people living by plants have been as high as three times the national average.
Berrien County officials investigating oil spill – Berrien County officials are attempting to get to the bottom of an oil spill in the county. The oil spill was discovered on January 2nd when investigating an unrelated obstruction in a drain. Berrien County Resident Prince Prabhu says he hopes the investigation uncovers why this spill happened. “First figure out why it happened and take precautions to not let it happen again,” Prabhu said. During the discovery and clean-up officials estimate 400 to 500 gallons of oil was spilled. “As soon as we do more investigating hopefully we will learn the source of where this oil is coming from,” Berrien County Sheriff Paul Bailey said. Officials say the oil had a red tint which indicates it could be on a few types of oil such as heating oil. Berrien County Drain Commissioner Christopher Quattrin said his office worked with Michigan’s Department of Environmental Quality during and after the clean-up. The clean-up is estimated to cost approximately $30,000, and officials say they are looking into “revenue streams” so the tax payers won’t be charged for the clean-up. The Berrien County Sheriff’s Department’s investigation is already underway and they hope to have answers as to how the spill happened in the upcoming months.
Protesters gather at National Fuel headquarters – Almost 100 people came out to the National Fuel headquarters in Williamsville on Saturday to protest the Northern Access Pipeline Project. Members of the Seneca Nation, and representatives from groups such as Earthworks, spent hours marching around the building to bring awareness to the concerns they have about the pipeline. One of the people protesting was Theresa Schueckler. Schueckler has been involved in litigation with National Fuel over her 200-acre property in Allegheny County. the proposed pipeline would run though her land. In December a judge ruled in her favor stating that National Fuel could not use eminent domain as a means to obtain the land for the building of the pipeline. “We have on our 200 acres we have spent our life trying to preserve clean air and clean water,” Schueckler said. Schueckler was confident that she no longer needed to worry about her land. Her opinion changed after a different ruling by an Erie County judge in a similar case. Members of the Seneca Nation also participated. Their main concern is the the proposed pipeline’s route through the Cattauragus Creek. John Seneca lives near the water and says he would rather the company found an alternative to fossil fuels rather than using the pipeline to transport more of them.
Legislators, groups concerned about pipeline project planned for Agawam — Hundreds of individuals and 40 organizations – including newly elected Sen. Jo Comerford, D-Northampton, Rep. Natalie Blais, D-Sunderland, and two newly elected Hampshire County state legislators, along with the Ashfield Affinities Group, Solar Store of Greenfield and StopNED (Northeast Energy Direct) – have signed on to comments submitted to federal regulators as part of an environmental assessment of Tennessee Gas Pipeline Co.’s proposed 261 Upgrade Projects planned for Agawam. The upgrades are part of the Columbia Gas “Reliability Plan,” which includes a new pipeline across West Springfield and other expansions in its Greater Springfield service area. The projects, for which TGP applied last October, would create 72,400 dekatherms per day of additional capacity on the company’s existing system by installing 2.1 miles of 12-inch diameter loop running parallel and adjacent to the pipeline that’s there, according to the company. It also involves removing an inactive 6-inch diameter pipeline and replacing it with 12-inch diameter pipeline loop in some locations, while also replacing two turbine compressors with a single cleaner-burning compressor, and installing of auxiliary facilities at the existing compressor station. TGP had proposed the Northeast Energy Direct Pipeline through Franklin County, but that was halted in 2016 because of insufficient demand. The company hopes to begin construction on the Agawam project in March 2020 and have them operational that November.
Baker approves air permits for natural gas project in Weymouth – In a decision blasted by South Shore lawmakers as reckless, irresponsible, and dangerous, Governor Charlie Baker’s administration on Friday approved air quality permits for a natural gas compressor station in Weymouth, with state environmental regulators concluding the Enbridge Energy project conforms with air pollution regulations. The project will support natural gas capacity upgrades and the expansion of a gas transmission pipeline system that runs from Mahwah, N.J., to Beverly, for transportation and deliveries on the Maritimes & Northeast Pipeline system. Collectively, it’s referred to as the Atlantic Bridge Project, which includes the siting of the compressor station, and which received federal approval in January 2017. “This reckless and irresponsible decision is harmful to the health, safety and wellbeing of residents of Weymouth and the entire South Shore,” Representative James Murphy, Democrat of Weymouth, said in a statement released after state energy officials disclosed their decision just before 5 p.m. Friday.
Tioga County fracking group sues DEC for answer on propane alternative – A Tioga County landowners group is pressing ahead with its fight to maneuver around New York’s hydrofracking ban.Fed up with state Department of Environmental Conservation delays on its application to drill for natural gas with propane instead of water, the group has sued the agency in State Supreme Court in Albany asking for a final determination on the proposal.”Having no response from the DEC for over eight months, Tioga Energy Partners has had enough,” said James Leonard, president of the New York chapter of the National Association of Royalty Owners.Tioga Energy Partners have been trying to push the alternative natural gas drilling method since 2015, months after the state banned hydrofracking, citing health and environmental concerns.Leonard said the DEC has been purposely dragging its feet on the the group’s liquefied propane fracking proposal, and the lawsuit was the only option to prompt a final determination from the state. In almost a year, Leonard said, the “DEC has not provided any substantive response” to its application to drill for natural gas using liquefied propane. The DEC has been unresponsive in Tioga Energy Partner’s attempt to get updates on the application review, he alleged.
New Jersey AG appeals PennEast pipeline eminent domain ruling — The New Jersey attorney general is taking further steps to try to block a controversial natural gas pipeline. The state filed an appeal Friday challenging a federal judge’s December ruling that PennEast could begin taking property by eminent domain. State Attorney General Gurbir Grewal initially challenged the ruling in early January with a motion for reconsideration and motion for stay. Grewal argues the state has “sovereign immunity” from eminent domain under the 11th Amendment. He has requested a hearing on the matter for later this month. Homeowners who live in areas where the $1.1 billion pipeline would go have opposed the project. PennEast says the pipeline will save natural gas consumers millions of dollars per year. The company still needs to secure various permits to move forward with the project.
Mariner East pipelines can keep flowing as PUC rejects shutdown request – The Pennsylvania Public Utility Commission on Thursday upheld a judge’s decision not to block operations of the controversial Mariner East pipelines after southeastern Pennsylvania residents contended they were unsafe. Administrative Law Judge Elizabeth Barnes denied an emergency request by seven Delaware and Chester county residents on Dec. 11 to block the startup of Sunoco Pipeline’s Mariner East 2 pipelines and to shut down the older Mariner East 1. The five-member Public Utility Commission unanimously affirmed the judge’s ruling. Commissioner David Sweet called it “thorough and well-reasoned” and said there was not sufficient evidence to reverse it. Mariner East 2 started service on Dec. 29. Sunoco used a 12-inch, 1930s-era pipeline that previously carried petroleum products as a link around unfinished sections of the new pipeline where regulators shut down construction after the project caused sinkholes and disrupted drinking water supplies. The $5 billion cross-state pipeline project is designed to move natural gas liquids, like ethane, propane and butane, from southwestern Pennsylvania’s shale gas wells to the Marcus Hook industrial complex and port near Philadelphia. The residents argued that the new and existing pipelines carrying highly volatile liquids through densely populated southeastern Pennsylvania are inherently dangerous, too shallow and close to homes, and that the company has not developed proper emergency management plans in case of a failure.
More, deeper wells planned for existing Marcellus site in Washington Township – CNX has applied to the state Department of Environmental Protection for a permit to drill four new wells to tap natural gas from Utica shale at an existing Marcellus shale well pad in Washington Township. The site is known as the Mamont South 1 Pad. It’s located near Evans Road, off of Route 286, in Washington Township on property owned by the Municipal Authority of Westmoreland County. The twist for the new application is that CNX is tapping both shale formations from the same well pad, which first was developed with five wells for Marcellus shale in 2014, according to Brian D. Aiello, a CNX spokesman. CNX applied to DEP in December to drill four new Utica shale wells on the same pad, he said. It’s unclear if any approval is needed by Washington Township since the proposed wells are on approved pad sites, according to township Supervisor Joseph Olszewski. Evans Road already is bonded by CNX and is in good condition, he said. “CNX can use it for overweight equipment and, if there is damage, we will assess any damages and they will pay for any damages,” Olszewski. CNX has been maintaining that section of road and it’s “been working out well,” he said. The Utica shale gas reserves reside deeper than Marcellus and, in Pennsylvania, sometimes they overlap, such as at the Mamont site in Washington Township. “We believe that area of Westmoreland County has significant potential in terms of what we call our “stacked pay” strategy, basically drilling multiple shale plays from the same pad,” Aiello said. “Stacked pay has many benefits including a reduced environmental footprint and improved operational efficiencies,” Aiello said. Other operators see value in such a strategy as well, according to the Marcellus Shale Coalition.
W.Va. Supreme Court To Hear Natural Gas Nuisance Case – The West Virginia Supreme Court is scheduled to hear arguments in an appeals case Tuesday that could have major implications for residents living near oil and gas operations.A group of Harrison County landowners who live near oil and gas sites operated by natural gas companies Antero Resources and Hall Drilling are asking the Supreme Court to require the companies to alter how they drill. They want relief from what they describe as near-constant loud noises, truck traffic and odors. The companies argue state law allows them to do whatever is “reasonably necessary” to extract mineral resources when they own or lease natural gas rights and requiring additional drilling stipulations would be burdensome. In October 2016, the West Virginia Mass Litigation Panel, which consists of seven circuit court judges that are appointed by the Chief Justice to resolve cases where many plaintiffs sue one defendant, ruled in favor of Antero and Hall Drilling. The landowners are appealing. The eventual ruling by the Supreme Court could have widespread impacts — hundreds of similar cases are pending in courts across the state. The case was slated to be heard last fall, but was delayed after attorneys representing the landowners asked Justice Evan Jenkins to recuse himself because of a potential conflict of interest. In the petition, the landowners’ legal team argued the “counsel of record” for defendant Antero Resources, Ancil Ramey, also recently represented Jenkins in a lawsuit that sought to invalidate his interim appointment to the Supreme Court.Ramey said his role in Antero case is “minor.” Jenkins ultimately declined to recuse himself. Two other justices, Tim Armstead and John Hutchison, have recused themselves.
Mountain Valley Pipeline starts the new year with new complications– When work began last February with tree-cutting, the plan was to have the Mountain Valley Pipeline completed by now. Instead, developers of the natural gas pipeline are facing what could be another setback for the project, which has already seen construction delays and cost overruns caused by legal challenges from opponents. The latest twist came last week, when the West Virginia Department of Environmental Protection reopened a public comment period for modifications to a combined state and federal permitting process that Mountain Valley must complete before it can dig trenches through streams and wetlands for its buried pipeline. With written comments now being taken through March 4, it appears that Mountain Valley will have to wait longer than expected before seeking what’s called a Nationwide Permit 12 from the U.S. Army Corps of Engineers. Such a permit – which clears the way for the 42-inch diameter steel pipe to cross through more than 1,000 waterbodies on its 303-mile route through West Virginia and Southwest Virginia – was issued by the Army Corps in December 2017. But the permit was struck down last year by the 4th U.S. Circuit Court of Appeals. Siding with the Sierra Club and other environmental groups, the court ruled that the Army Corps lacked the authority to bypass a requirement by West Virginia regulators that pipeline stream crossings must be completed within 72 hours to limit environmental harm. Admitting that it would take more than a month to burrow through four major rivers in West Virginia, Mountain Valley was forced to suspend work on all stream crossings until it could obtain a new permit.That process appeared to be simplified after West Virginia’s DEP suggested changes to its regulations that removed the 72-hour requirement for pipeline developers, as long as they used a more environmentally friendly method of stream crossings. After taking public comments, the agency said in November that it was preparing to send the proposed modifications to the Army Corps and the U.S. Environmental Protection Agency for review.
Mountain Valley Pipeline files response to state’s lawsuit – Widespread erosion during construction of the Mountain Valley Pipeline was caused by “extraordinary” rainfall and other uncontrollable forces of nature, attorneys for the company said Friday in response to a lawsuit filed by environmental regulators. In its first detailed reply to a legal enforcement action brought by the Virginia Department of Environmental Quality and the State Water Control Board, the company asked a judge to dismiss some of the claims. But the 28-page filing in Henrico County Circuit Court also indicated that Mountain Valley is interested in a “potential negotiated resolution” of a lawsuit that accuses it of violating environmental regulations more than 300 times. It was unclear to what degree a settlement has been discussed. A Mountain Valley spokeswoman did not immediately respond to questions. A spokeswoman for state Attorney General Mark Herring, who filed the lawsuit in December, said the office will answer the company’s filing in court. Long before construction of the massive buried pipeline began last spring, opponents argued that digging trenches for the 42-inch diameter steel pipe across rugged mountain terrain and through pristine steams was asking for environmental trouble. Inspections by DEQ have found that construction crews failed to prevent muddy water from flowing off pipeline construction easements, often leaving harmful sediment in nearby streams and properties.
Court filing asks judge to deny Mountain Valley’s request for injunction against tree-sitters — A federal judge should not act as an “enforcer” for the Mountain Valley Pipeline by using her power to remove two protesters from trees blocking the path of the controversial pipeline, supporters are arguing in court.U.S. District Court Judge Elizabeth Dillon was asked in a brief filed Wednesday to deny Mountain Valley’s request for a preliminary injunction, which the company says it needs to evict two people identified in court records only as “Tree-sitter 1″ and “Tree-sitter 2.”Since early September, two protesters have been living in tree stands about 50 feet above the forest floor on a steep mountainside in eastern Montgomery County, frustrating Mountain Valley’s efforts to complete tree-cutting.But Mountain Valley is “improperly seeking to enlist this Court to act as its enforcer in its dealings with persons opposing pipeline activities and construction,” Roanoke attorney John Fishwick wrote in a friend-of-the-court brief in support of the tree-sitters.Fishwick does not represent the actual protesters, who have kept to their perches rather than attend court proceedings and defend themselves against Mountain Valley’s civil action.As the attorney for two supporters of the tree-sitters – Floyd County attorney Tammy Belinsky and Virginia Tech professor Daniel Breslau – Fishwick was allowed to make arguments on their behalf.
Drilling in Harrison County is a nuisance for residents, lawyer says — Four families that live near gas drilling operations are disproportionately burdened by Marcellus Shale drilling, a lawyer for the families told West Virginia Supreme Court justices Tuesday morning. The Harrison County families have to deal with constant noise and traffic, Anthony Majestro, an attorney for them, told the Supreme Court. They can’t sleep because of Antero Resource Corp.’s bright lights, and they can’t sit on their porches because of the dust, he said. One resident said the bright lights make him feel like he’s living next to WVU’s Mountaineer Field, Majestro said. The question isn’t whether drilling is OK or not, Majestro said. “It’s not about whether the respondent should be allowed to do Marcellus Shale drilling. We don’t contend that our claims are the kinds of claims that would stop their drilling,” he said. Instead, he said, it’s about whether those landowners should have to bear costs and burdens without compensation perpetuated by Antero Resources, the state’s largest gas producer. “It’s the classic common-law nuisance that goes back four, five hundred years, back all the way to England,” Majestro said. The Supreme Court should affirm the lower court’s ruling that said Antero obtained property rights that were sufficient to allow these kinds of operations, said W. Henry Lawrence, who argued Tuesday on behalf of Antero.
US appeals court will not ease stay for 1.5 Bcf/d ACP natural gas pipeline – A federal appeals court said Friday it will not scale back a stay on a permit for the Atlantic Coast Pipeline, increasing prospects for delay of the 600-mile, 1.5 Bcf/d project, designed to move Appalachian gas to Mid-Atlantic markets. Setbacks to ACP’s construction timeline would likely delay pressure on Transcontinental Pipe Line Zone 5 prices. Company officials did not comment on the schedule Sunday, but Dominion Energy said it remained confident in the full completion of the pipeline given the “critical customer need and a route that has been exhaustively studied and permitted.” ACP in early December suspended most construction after the 4th US Circuit Court of Appeals stayed the US Fish and Wildlife Service’s biological opinion as well as the incidental take statement setting limits on harm to protected species. To soften the blow, the pipeline company sought emergency clarification December 7 that the stay’s application was narrower than it appeared. The court on Friday rejected that request. The decision added to the late-December rejection of another ACP attempt to put the project back on pace – a request to expedite briefing and oral argument in the case. Amid regulatory challenges, Dominion previously postponed its in-service target from mid-2019 to mid-2020 for portions of the project, while a late-2019 target remained for some segments. In a December 14 motion, the company said delay of up to a year was “all but certain” under the current oral argument schedule and “would exponentially increase” project costs. Oral argument is tentatively scheduled for the court’s March 19-21 session, and the stay is in effect pending the litigation. If it was unable to complete tree felling by mid-March, ACP had told the court that time-of-year environmental restrictions on tree felling could make the additional delay inevitable. In its December 7 motion for clarification, ACP requested that the stay be limited to four species in contention. By staying the entire biological opinion and incidental take statement, “the court effectively stays work on the entire project, well beyond construction in areas with any potential to affect these species,” ACP argued in the motion.
FERC opens 3 pipeline rate probes as Chatterjee tables PJM political spending complaint – Dive Brief:
- The Federal Energy Regulatory Commission opened investigations into the rates charged by three interstate natural gas pipelines on Wednesday to determine if they are “substantially over-recovering their costs of service.”
- FERC opened the inquiries after asking pipelines in July 2018 to detail their rates of return following the passage of federal tax cuts in 2017 and changes to FERC’s tax allowance policies. FERC also found nine gas companies had complied with the agency’s request and terminated those inquiries without investigation.
- FERC on Thursday canceled a planned vote at its monthly open meeting on a political spending complaint lodged against grid operator PJM, and also declined to vote on a liquefied natural gas facility it tabled last month. The delays likely indicate a deadlock among sitting regulators on the issues, but Chairman Neil Chatterjee declined to comment on internal deliberations.
Offshore Service Spending to Outpace Onshore Shale – Spending on the offshore service sector will outpace spending on the onshore shale sector this year, according to Rystad Energy. One reason for this – while onshore shale spending is likely to remain flat this year due to current oil prices, the offshore service sector is expected to grow by four percent this year. “Many would expect offshore spending to be cut as drastically as shale, but offshore budgets were at a 10-year low last year, after four years of intense cost focus, and from that level you don’t need much additional activity or inflation to drive up the market,” Audun Martinsen, Rystad Energy head of oilfield services research, said in an email to Rigzone. With the decline of oil prices in fourth quarter of 2018 and a more bearish outlook for 2019, companies have drastically cut shale budgets to compensate the anticipated revenue loss. Martinsen pointed to the fact that the number of fracked wells per day dropped from average 50 to 44 while frack service pricing continued to decline in 4Q 2018. He expects the same – more or less – in 2019. Offshore spending will see an increase, fueled by exploration and greenfield projects, Rystad Energy forecasts. Additionally, operational expenses (OPEX) budgets will increase due to cost inflation, more fields coming on stream and a backlog of work that needs completion. Rystad Energy research finds that if the price of Brent crude were to reach $70 per barrel, the shale industry could have 14 percent growth. “It seems that the names that will be able to deliver the best revenue growth are the service companies exposed to the offshore subsea market and MMO,” Martinen said. “This is a clear switch from 2018, when it was the shale names that were market share winners in the global service market.”
Trump plans to relax Obama rules for oil companies put in place after BP disaster – The Trump administration is expected to give BP and other big oil companies more power to self-regulate their offshore drilling operations, years after investigators found that lax regulatory oversight was one of the leading culprits behind the BP Deepwater Horizon disaster, the worst environmental catastrophe in US history. The move to relax new rules that were put in place by the Obama administration after the BP disaster, which killed 11 workers, spewed 4m barrels of oil into the Gulf of Mexico, and cost BP $65bn, comes as the White House is seeking to open offshore oil and gas drilling to the vast majority of US coastal waters, including in the Arctic. The proposed revised rules, which most experts believe will be finalised despite heavy opposition from environmental groups, include a change that would allow oil companies to select third-party companies to evaluate the safety of their equipment. Under previous rules, those entities had to be approved by the government agency that oversees offshore drilling, without any input from industry. A separate rule on oil production safety systems that has already been finalized would also strike requirements that were put in place after the BP disaster that forced companies to get independent verification of the safety measures and equipment they use on offshore platforms, as well as a rule that required professional engineers to certify the safety of drilling equipment for new wells.
Delayed by shutdown, US offshore drilling rule changes likely to be challenged by states – Work on controversial revisions to a US offshore drilling safety rule is currently being held up by the ongoing partial government shutdown, but when ultimately finalized, the changes will be challenged in court by multiple states, sources said. The revisions, which make changes to the Blowout Preventer Systems and Well Control rule finalized in 2016 in response to the Deepwater Horizon explosion and spill, were initially proposed by the Department of the Interior’s Bureau of Safety and Environmental Enforcement in April.The proposed revisions have been under review at the White House since December 13, but sources said the officials in the White House’s Office of Information and Regulatory Affairs in charge of that review have been furloughed by the shutdown, which entered its 25th day Tuesday. Sources said, depending on when the shutdown ends, it could take weeks for that review to be completed and then some weeks more if Interior needs to make additional changes.The proposed revisions to the offshore safety rule come as the Trump administration is working on expanding oil and natural gas drilling into federal Atlantic, Arctic and Eastern Gulf of Mexico waters. Interior was expected to release its proposed five-year offshore leasing plan for 2019 through 2024 by mid-January, but these plans have also been delayed indefinitely by the government shutdown, sources say.Opponents of the well control rule revisions have criticized the administration for weakening offshore safety regulations as it looks to expand offshore drilling operations. “It’s almost like a never mind rule,” said David Hayes, who helped write the original rule as deputy Interior secretary during the Obama administration, in an interview with the Platts Capitol Crude podcast. “We’re going to go back to the way it was and not require better performance from the blowout preventers that everyone agrees are the last line of defense from an out-of-control well in the offshore” environment.
US recalls workers from furlough for oil, gas work (Argus) – President Donald Trump’s administration is bringing employees it sent home for the government shutdown back to work to prepare for offshore lease sales and to open new waters to drilling. The US Bureau of Ocean Energy Management (BOEM), in an revised contingency plan, says it is taking 40 workers off furlough to conduct lease sales, issue permits for seismic surveys and take the next step toward finishing a plan that would open more than 90pc of federal waters to oil and gas development. The decision represents the latest effort by the Trump administration to avoid slowing down its energy agenda during a partial government shutdown in its 24th day. The US Bureau of Land Management has continued to process oil and gas drilling permits and hold meetings to open land in Alaska to oil and gas development. That approach has raised red flags for environmentalists who say the administration is crossing the line on what activities can continue without appropriations from the US Congress. But it has softened the shutdown’s effect on oil and gas companies hoping to gain a foothold in new federal areas before the end of the first term of the Trump administration. BOEM in its contingency plan cited the need to achieve the administration’s “America First energy strategy” to justify why it has exempted staff to work on offshore leasing plan that would open nearly all federal waters to drilling. It says 10 employees will work on the next step in that plan, which was expected in mid-January. BOEM said it would designate more workers as exempt after today to complete work for an oil and gas lease sale in the US Gulf of Mexico scheduled in March. The agency said failure to hold that sale, and to prepare for another lease sale later this year, would have a “negative impact” on government revenues and negatively affect investment in the Gulf. BOEM is also exempting staff to process permits required to conduct seismic oil and gas surveys in the US Atlantic.
Despite Shutdown, BOEM Resumes Work on Offshore Drilling Plan – The Bureau of Ocean Energy Management (BOEM), the permitting agency for offshore development in federal waters, has recalled 40 furloughed employees to work on the Trump administration’s proposed offshore oil and gas leasing plan. The majority of the agency – including the departments that handle offshore wind development – will remain shut. The closure of BOEM has significant implications for the wind industry, according to trade group Business Network for Offshore Wind. “There are a number of big, important offshore wind projects moving through the BOEM approval process, and we can’t afford to have them disrupted in terms of their coordination and timing,” said Liz Burdock, the group’s CEO and president, speaking to Bloomberg. “We are not able to hold meetings with BOEM because they’re not able to work.”Six public hearings scheduled for the $2 billion Vineyard Wind project off Martha’s Vineyard have already been pushed back due to the shutdown, and the timeline for rescheduling them is uncertain. Federal tax credits for wind developments will expire this year, so a lengthy delay could impose a large financial penalty on wind farm operators, according to Business Network for Offshore Wind. Separately, BOEM has redesignated 40 of its furloughed employees as exempt from the shutdown’s closure requirements, which will allow them to return to work on the National Outer Continental Shelf Program – the master five-year policy plan for oil and gas drilling in federal waters. The first draft of this plan, which was released in January 2018, drew controversy over proposed leasing activity off the Atlantic and Pacific coasts.
US Interior’s offshore work may violate law: House chairman – The US Interior Department’s decision to have roughly 40 federal employees work during the partial government shutdown on plans to expand oil and natural gas production in federal waters is likely a violation of US law, the chairman of the House Natural Resources Committee said Wednesday. While the Department of Justice is unlikely to prosecute a case against Interior, such a violation could be tested if Interior’s offshore lease sales or seismic permitting are challenged in court. US Representative Raul Grijalva, a New Mexico Democrat, said that this work may violate the Antideficiency Act, a statute which prohibits agencies from expending federal funding without congressional approval. No one has ever been prosecuted in violation of this law, which dates back to the 19th century. According to a January 8 update of shutdown plans at Interior’s Bureau of Offshore Energy Management, the agency said it was recalling about 40 employees to work on a decision allowing seismic testing in the Atlantic, development of the agency’s offshore lease sale plan for 2019 through 2024, and work on two upcoming sales in the Gulf of Mexico. “Failure to hold these sales would have a negative impact to the Treasury and negatively impact investment in the US Offshore Gulf of Mexico,” BOEM said in the update. Grijalva said the push to finish this offshore work during the partial government shutdown shows the administration’s focus on oil and gas development over all other work. “It’s continued unabated regardless of whatever condition the parks might be in, who’s furloughed, who’s not being paid,” Grijalva said in an interview. “It just strikes me as ironic and glaring that this one function continues.”
Court blocks offshore oil testing permits during shutdown – A federal court on Friday blocked the Trump administration from issuing any permits to conduct seismic testing for offshore oil and natural gas drilling during the partial government shutdown. Judge Richard Gergel of the District Court for South Carolina issued the order as part of an ongoing challenge by environmental groups and Democratic states to the administration’s November move toward allowing the testing. Justice Department attorneys representing the Interior Department’s Bureau of Ocean Energy Management (BOEM) had asked Gergel to pause the case during the shutdown because they could not write filings. Gergel granted that pause, but said that the same logic means BOEM should be prohibited from granting any permits until the government reopens. He noted that last week, Interior asked furloughed employees to return to work in order to process the seismic testing applications. “It requires little imagination to realize that the returning BOEM employees could act on the pending applications and seismic testing could commence during the pendency of the stay,” he wrote in his order. He ruled that all federal agencies are prohibited from taking action to promulgate permits, otherwise approve, or take any other official action” on the applications at issue. The November action gave five companies permission to potentially harm or harass marine species when they do their testing. It is a necessary step before the BOEM can issue testing permits. Federal attorneys had told the judge previously that the BOEM would not issue testing permits during the shutdown. But the agency later updated its shutdown plan to bring in employees to work on the permits, and attorneys told the court that the permits might be issued as early as March 1. Companies want to test the ocean floor in the Atlantic to see how much oil or natural gas is underneath. The Trump administration has proposed allowing drilling in the Atlantic for the first time since the 1980s, but hasn’t allowed any drilling yet.
Feds seek penalties against Shell Offshore over 2016 oil spill – The federal government has filed a suit against Shell Offshore Inc. over a May 2016 oil spill in the Gulf of Mexico. The United States of America filed a complaint on Jan. 8 in the U.S. District Court for the Eastern District of Louisiana against Shell Offshore Inc. citing the Clean Water Act. According to the complaint, the U.S. Coast Guard and the Louisiana responded to an oil spill that started May 11, 2016. The suit states the defendant spilled more than 1,900 barrels of crude oil into the waters of the Gulf of Mexico from a transfer pipeline at Shell’s Green Canyon Block 248 offshore system. The response efforts ended on May 16, 2016, the suit states. “Despite the alarms and sustained pressure loss, Shell continued to actively pump oil through the cracked pipeline for at least another seven and a half hours. This was due in substantial part to Shell’s failure to provide adequate training for its control room operators,” the suit states. The plaintiff seeks civil penalties of up to $1,848 per barrel of oil discharged, or if the violation resulted from gross negligence or willful misconduct, up to $5,432 per barrel discharged; injunctive relief; costs; such other and further relief as the court deems just and proper. It is represented by the U.S. Department of Justice in Washington, D.C. and the United States Attorney for the Eastern District of Louisiana in New Orleans.
With support from DeSantis, Florida lawmaker files fracking ban in House – With the idea getting support from Gov. Ron DeSantis, a House Republican has filed a proposal to ban the oil- and gas-drilling process known as “fracking” in Florida. Rep. Heather Fitzenhagen, R-Fort Myers, filed the bill (HB 239) on Thursday, the same day DeSantis released a series of environmental proposals that included opposition to fracking. Sen. Linda Stewart, D-Orlando, filed a similar proposal (SB 146) last month to try to ban fracking. The bills are filed for consideration during the legislative session that starts March 5. Environmental groups and some lawmakers have long wanted to block potential fracking in Florida, but legislation has not passed. During the 2018 session, a Senate version was approved by two committees, while a House version was never heard. Fracking, in part, involves injecting water, sand and chemicals underground to create fractures in rock formations, allowing natural gas and oil to be released. While supporters say fracking increases production and holds down energy costs, opponents argue it threatens water supplies and can cause environmental damage.
Oil, Gas Drilling Method ‘Fracking’ Faces Ban Under Proposed Florida Bill – The drilling procedure commonly known as “fracking” could be banned in Florida under a proposed bill. The general bill was filed Thursday by Republican Rep. Heather Fitzenhagen, who represents Fort Myers. The measure is supported by Republican Florida Gov. Ron DeSantis, who was inaugurated on Tuesday. DeSantis on Thursday signed an order seeking to fulfill his campaign promise tomake the environment a priority by confronting Florida’s blue-green algae and red tide crisis, among other issues. DeSantis also announced he would take “necessary actions” to oppose all off-shore oil and gas activities in Florida. The practice of fracking has long been criticized by environmental activists as a dangerous method to extract fossil fuels. Organizations warn of the release of toxic chemicals possibly poisoning the land and groundwater. Fracking has been linked to generating tremors and earthquakes, as well. House Bill 239 would ban “advanced well stimulation treatment” – meaning all methods of injecting fluids into a rock formation.
Walz: Decision on proceeding with Line 3 lawsuit will be his (AP) – Gov. Tim Walz said Friday that he and his new administration will be “actively engaged” on contentious natural resources issues, including Enbridge Energy’s plan to replace its aging Line 3 oil pipeline across northern Minnesota. Speaking to reporters at an annual Department of Natural Resources conference, Walz said he has asked his team to review the lawsuit that was filed by the outgoing administration of Gov. Mark Dayton that challenges the decision by the independent Public Utilities Commission to approve the project. Walz said he wants to understand why the Commerce Department felt the process was insufficient and that it needed to turn to the courts. “The decision will stop with me, but it will be informed by all of the stakeholders involved,” the governor said. Commerce said in its appeal that Enbridge did not introduce, and the commission did not properly evaluate, the kind of long-range oil demand forecast required by law. The PUC stood by its decision, saying its approval was supported by the law and a vigorous public review process. Walz said he’s grateful for Dayton’s work as governor, but he’ll bring a new leadership style, pattered on the style Walz used when he was in Congress, building coalitions from the beginning. He acknowledged he’s inheriting some “pretty touchy issues,” but pointed out that he has a new DNR commissioner in Sarah Strommen, a new head of the Minnesota Pollution Control Agency and that he’ll get to appoint a new PUC commissioner. “You can expect to see us actively engaged, not turning away from these,” he said.
Can U.S. LPG Export Terminals Keep Up? – U.S. production of natural gas liquids is projected to increase by 17% this year, and by another 10% in 2020, according to RBN’s forecast. These gains will result in similar increases in the output of propane and normal butane – two NGL purity products generally referred to as LPG – and, with U.S. demand for LPG expected to stay relatively flat, most of the incremental volumes will be sent to export terminals for shipment to foreign buyers. The question is, will the nine U.S. marine terminals that are equipped to send out LPG have enough capacity to handle the much-higher flows? Today, we continue our series with a review of four smaller export terminals along the Gulf and East coasts. This is the third and penultimate episode in our series in which we’ve been discussing the U.S.’s flip from net LPG importer to net exporter seven years ago and the challenges presented by fast-growing propane/butane export volumes. As we said in Part 1, waterborne LPG exports soared to an average of more than 1.1 MMb/d in 2018, with about 92% of those volumes being sent out of the half-dozen LPG terminals in coastal Texas and Louisiana. The rest of the exports-by-ship are flowing through a total of three smaller terminals in the Mid-Atlantic region and Pacific Northwest. We concluded Part 1 with a review of the Gulf Coast’s – and the U.S.’s – largest LPG export facility: the Enterprise Hydrocarbon Terminal (EHT; dark blue dot and lettering in Figure 1), which is located on the Houston Ship Channel and whose capacity is in the midst of being expanded to 720 Mb/d from the current 545 Mb/d. According to our NGL Voyager report, EHT sent out an average of 447 Mb/d of LPG last year, or about 40% of total U.S. LPG exports by ship.
Saudi Arabia Eyes Investment Into U.S. Gas – Saudi Arabia is nearing a deal to invest in U.S. liquefied natural gas, write the Journal’s Sarah McFarlane and Summer Said. Saudi Arabian Oil Co., known as Aramco, has narrowed its focus to a shortlist of at least four U.S. LNG projects and intends to announce a deal in the first half of this year, people familiar with the matter said. Companies with projects being considered include Tellurian Inc., a Houston-based LNG developer known for its intention to ship gas from its planned Driftwood terminal in Louisiana, said sources. In addition, San Diego-based Sempra Energy, which is developing five LNG projects between the U.S. and Mexico, has had discussions with Aramco concerning its Port Arthur project in Texas, according to sources. Any such investment would mark a sea change in the energy flows between the U.S. and Saudi Arabia. America’s shale revolution has broken years of dependence on Middle Eastern oil, to the extent that the International Energy Agency expects the U.S. to become a net energy exporter by 2023.
Here’s why Abu Dhabi petrochemicals chief has his eye on North American shale – While North American shale may be competition for OPEC members, some crude-exporting countries in the Arabian Gulf are simultaneously taking advantage of the commodity’s ability to fuel lucrative investments beyond oil. For the United Arab Emirates’ Musabbeh al-Kaabi, chief executive of Abu Dhabi’s Mubadala Petroleum and Petrochemicals, the shale revolution has the made North American gas and petrochemicals industry very attractive, bringing competitively-priced gas feedstock to the market. The petrochemicals firm is a major component of Mubadala Investment Company, Abu Dhabi’s state-owned holding company. It operates as a sovereign wealth fund with assets of more than $226 billion, and is aimed at diversifying the emirate’s economy.”We as an investor made big investments in the last 18 months, north of $12 billion dollars, and some of these big investments are happening in North America,” al-Kaabi told CNBC’s Hadley Gamble during the Atlantic Council Energy Forum in Abu Dhabi.This was for two simple reasons, the CEO said. “It is a big market and it is enjoying a highly competitive feedstock. So we like the business in that part of the world because of these two reasons.” Feedstock refers to raw material, such as natural gas, used in petrochemical production. Gas dominate’s the company’s business, and al-Kaabi has previously highlighted North America as the focus of a strategic shift when it comes to petrochemicals thanks to the shale revolution. “Other parts of global energy I would say, the energy industry, the price would be set by the high cost producers going forward,” al-Kaabi added. “And who are the high cost producers nowadays? The shale producers. And we will keep monitoring what is happening in that part of the world.”
Market Edges Higher As Winter Is Forecast To Return – Highlights of the Natural Gas Summary and Outlook for the week ending January 11, 2019 follow. The full report is available at the link below.
- Price Action: The February contract rose 5.5 cents (1.8%) to $3.099 on a 25.6 cent range ($3.166/$2.910).
- Price Outlook: The market ended the streak of new weekly lows as weather forecasts not only became less bullish but turned bullish with below normal temperatures now forecast. While winter is now half over, demand can still be impressive and as a reminder, on January 10, 2014 prices traded to $3.953 before soaring to $6.493 on February 24, 2014. While we do not expect that type of price action, higher prices may be in store if temperatures remain below normal through February. For daily updated storage projections, subscribe to our joint publication with RBN Energy. CFTC data has not been updated due to the US government shutdown. Aggregated CME futures open interest rose to 1.301 million as of January 11. The current weather forecast is now cooler than 7 of the last 10 years. Pipeline data indicates total flows to Cheniere’s Sabine Pass export facility were at 3.3 bcf. Cove Point is net exporting 0.8 bcf. Corpus Christi is exporting 0.001 bcf. Cameron is exporting 0.000 bcf.
- Weekly Storage: US working gas storage for the week ending January 4 indicated a withdrawal of (87) bcf. Working gas inventories fell to 2,614 bcf. Current inventories fall (153) bcf (-5.5%) below last year and fall (481) bcf (-15.6%) below the 5-year average. The report was accompanied by a 4 bcf reclassification in the Mountain region that resulted in a total withdrawal of (91) bcf.
- Storage Outlook: The EIA weekly implied flow was (1) bcf from our EIA storage estimate. This week’s storage miss is back within our tolerance. Over the last 5 weeks, the EIA has reported a total withdrawal of (373) bcf compared to our (374) bcf estimate. 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 fell (0.8)bcf/d to 81.6 bcf/d. US production fell. Canadian imports rose. LNG imports rose. LNG exports fell. Mexican exports fell. The US Baker Hughes rig count was unchanged +0. Oil activity decreased (4). Natural gas activity increased +4. The total US rig count now stands at 1,075 .The Canadian rig count rose +108 to 184. Thus, the total North American rig count rose +108 to 1,259 and now exceeds last year by +44. The higher efficiency US horizontal rig count rose +3 to 948 and rises +143 above last year.
- Demand Trends: Total demand rose +7.4 bcf/d to +94.2 bcf/d. Power demand rose. Industrial demand rose. Res/Comm demand rose. Electricity demand rose +955 gigawatt-hrs to 74,073 which trails last year by (19,258) (-20.6%) and trails the 5-year average by (8,088)(-9.8%%).
- Nuclear Generation: Nuclear generation fell (544)MW in the reference week to 93,431 MW. This is (2,016) MW lower than last year and (1,370) MW lower than the 5-year average. Recent output was at 93,019 MW.
The heating season has begun. With a forecast through January 25 the 2018/19 total cooling index is at (1,677) compared to (1,506) for 2017/18, (1,308) for 2016/17, (1,320) for 2015/16, (1,621) for 2014/15, (1,836) for 2013/14, (1,572) for 2012/13 and (1,553) for 2011/12.
Natural gas prices spike 13 percent on forecasts for long, severe cold – Natural gas prices spiked on Monday as the market gained confidence that the severe cold gripping the United States will persist longer than previously thought, driving up heating demand and taxing gas stockpiles.Front-month Henry Hub natural gas futures for February rose more than 13 percent on Monday. The contract hit a session peak at $3.539 per million British thermal units, its highest level since Dec. 27.The contract was last up 12.7 percent at $3.493 per mmBtu. Updated forecasts show below-average temperatures persisting over the next two weeks, with the cold snap drifting eastward from the Midwest toward the East Coast. Traders were anticipating the cold would linger, but weather models available last week didn’t give them the confidence to take long positions in natural gas futures heading into the weekend, according to Jacob Meisel, chief weather analyst at Bespoke Weather Services. “The forecast has turned significantly colder,” he said. “It’s really the magnitude of the cold and the confidence in severity longer term that’s changed over the weekend.” “There is surprisingly strong agreement even late in the week two forecast.” Natural gas prices have been falling since the middle of December, following a spike above $4 per mmBtu in the fall. Hotter-than-usual late summer temperatures and a surprisingly cold fall increased demand for cooling and heating last year, causing natural gas stockpiles to fall to their lowest level in over a decade.
US EIA lowers spot gas forecasts for 2019 on robust production, injections – – The Energy Information Administration Tuesday lowered its spot natural gas price forecasts in 2019, predicting that production growth will keep pace with demand and export growth, and that inventory builds will outpace the five-year average. The agency, in its January Short-Term Energy Outlook, lowered its forecast for Q1 Henry Hub natural gas spot prices by 57 cents to $3.03/MMBtu, while the Q2 forecast was trimmed 13 cents to $2.73/MMBtu. The full-year 2019 price estimate also fell 22 cents to $2.89/MMBtu, while the new 2020 estimate sees spot prices averaging $2.92/MMBtu. The agency bumped up its natural gas consumption estimates in the US by 1.46 Bcf/d to 99.4 Bcf/d for the first quarter of 2019, and by 0.76 Bcf/d to 71.44 Bcf/d for Q2. “EIA forecasts power sector consumption of natural gas to remain largely unchanged in 2019 and then rise by 3.3% in 2020 because of continuing increases in natural gas-fired electric generation capacity,” the agency said. It also raised the consumption estimate for the full year 2019 by 1.08 Bcf/d to 82.65 Bcf/d, and forecast consumption will average 83.55 Bcf/d in 2020. Production is expected to build on the records set in 2018. “[P]ermian and Appalachian regions will drive record US production over the next 24 months,” EIA Administrator Linda Capuano said. The agency raised by 0.05 Bcf/d to 96.33 Bcf/d its natural gas marketed production estimate for the US in Q1 and by 0.08 Bcf/d to 97.23 Bcf/d for Q2. The full-year 2019 estimate rose by 0.19 Bcf/d to 97.28 Bcf/d, and 2020 levels were put at 99.68 Bcf/d. While inventories were forecast to reach 1.405 Tcf at the end of March 2019, 15% below the five-year average for that time, EIA expected injections would exceed the average rate, as production outpaces consumption in late March through October. That would bring inventories to 3.758 Tcf at the end of October 2019, just above the five-year average.
How fears of a US recession could impact spending in the US natural gas midstream sector – (Platts podcast) S&P Global Platts senior natural gas writer Harry Weber and Americas natural gas managing editor Joe Fisher discuss the outlook for the US midstream sector as fourth-quarter 2018 earnings reporting season begins, from the appetite for further major pipeline projects to the markets that will be served by increasing gas production to the impact LNG export growth will have on the industry.
Weekly Natural Gas Storage Report – Storage Deficit Widens Going Into February – EIA reported a storage draw of 81 Bcf for the week ending Jan 11. This compares to the -90 Bcf we projected and consensus average of -82 Bcf. The -81 Bcf was considerably smaller than the five-year average of -203 Bcf and last year’s -183 Bcf. As you can see, this week’s EIA natural gas storage report was a hideous one, especially when you compare it to the average and last year. The weather set-up for the report was a very bearish one as you can see below: As you can see, natural gas storage deficit to the 5-year average is expected to decline back to -600+ Bcf by the start of February, thanks to a much more bullish second-half January outlook. Heating demand is expected to increase to the highest level this winter and the colder-than-normal weather looks to last into February. Based on our estimates, EOS has now been revised down to 1.2 Tcf again with the bullish weather backdrop. A sustained cold in February would see EOS revise lower, which would push natural gas prices even higher. Our fundamental models show February contracts to trade up to $3.8 and March to trade up to $3.50, based on the current projection and outlook. We remain long UGAZ and believe that natural gas prices today are discounting the bullish weather too much as the market continues to question the 1) duration of the bullish weather and 2) overly sensitive to HDD changes for January. In our view, we believe the bullish weather is sustainable given the weather “set-up” is especially favorable for the bulls. The Alaska and Greenland ridging pattern remains in place allowing for a more durable bullish weather outlook into February. We think this set-up presents a good opportunity to remain long natural gas.
US to add 216.5 Bcf of working gas storage capacity by 2022: report – Various midstream companies plan to add more than 200 Bcf of working natural gas storage capacity at 17 sites in the US over the next four years due to the rise of LNG export terminals and gas-fired power generation, according to a report released Monday. The US is slated to add 216.5 Bcf of working gas storage through 2022 at a cost of $1.2 billion, according to a report released Monday by the UK firm GlobalData. “The ever growing demand for natural gas in the US is driving the growth of the underground gas storage industry in the country,”. “The proposed natural gas-fired power plants and the LNG liquefaction terminals are also aiding the underground gas storage industry growth.” If the projects do manage to come online, it would increase total working gas capacity in the US to about 4.9 Tcf. The US Energy Information Administration currently estimates 4.7 Tcf of working gas capacity. No new significant storage fields have entered service over the past five years. However, many of these planned projects have already faced substantial delays, so it is possible much of this additional storage capacity may not come online by 2022. The proposed projects are scattered geographically, but the majority would involve salt-dome formations. Unlike depleted oil and gas fields or aquifers, salt-dome facilities allow for greater flexibility in switching from injections to withdrawals. This allows players to meet peak demand periods for power generation or for delivery to LNG export terminals more easily. About 12% of all current US storage capacity is contained in salt caverns. The largest proposed storage facilities include the Magnum Gas Storage Project in Utah, Falcon Gas Storage’s MoBay Storage Hub in Alabama and Chestnut Ridge Storage’s Junction Natural Gas Storage facility in Pennsylvania.
Open season gauges interest in improved access to US, Canadian barrels in Louisiana – Phillips 66 Partners, Harvest Midstream and PBF Logistics plan to develop a pipeline they expect to provide three Louisiana refineries with improved access to price-advantaged domestic crudes, they said. The companies on Monday launched an open season for the ACE pipeline system, serving intrastate Louisiana. With completion and startup expected by late 2020, the 400,000 b/d pipeline would transport crude from the St. James storage hub to refineries in Belle Chasse, Meraux, and Chalmette, the companies said. An option exists to add a delivery destination in Clovelly, Louisiana, the storage hub for the Louisiana Offshore Oil Port, they added. The pipeline system will include a newbuild segment to connect the St. James hub to the CAM pipeline, which currently transports crude from the Louisiana Offshore Oil Port to all three refineries. Harvest Midstream plans to contribute its existing CAM pipeline to the ACE system. Refineries potentially benefiting from increased access to both light sweet and medium to heavy sour crude as a result of the new line include Phillips 66’s 247,000 b/d Alliance refinery in Belle Chasse, Valero’s 135,000 b/d Meraux refinery and PBF’s 189,000 b/d Chalmette Refining. The ACE line would mean improved access to light sweet barrels drawn from St. James for all three regional refineries. Valero Meraux and PBF Chalmette mainly process medium to heavy sour barrels, with light sweet domestic barrels making up the balance of the crude slate. Phillips 66’s Alliance, in contrast, mainly runs light sweet crude with offshore medium sour grades and some imported heavy sour grades making up the remainder of the crude slate.Permian Basin crudes are priced at a wide discount to Louisiana Light Sweet crude. Midland WTI has averaged at an $11.96/b discount to LLS so far in January, S&P Global Platts data shows. Pipeline constraints are likely still keeping Midland WTI prices under pressure, but the discount to LLS has narrowed from $20.75/b in August as more capacity has come online.
US Crude Oil Exports Continue to Grow – U.S. crude oil exports have soared due to a combination of:
- rising domestic crude oil production
- high but flat domestic demand
- a law change in December 2015 that allowed sales beyond just neighbor Canada
Since the shale revolution started in 2008, U.S. crude production has increased almost 125 percent to around 11.2 million barrels per day (MMbpd). Yet, this light, tight oil boom has not been a great match for the massive 18.6 MMbpd U.S. refining system. U.S. refineries are generally configured to process the heavier crudes imported from longtime suppliers Canada, Mexico and Venezuela. So today, 65 percent of U.S. crude oil production has a very high 40 degree API gravity or above. This has left huge amounts of surplus shale oil available for export. This mismatch between what the U.S. is producing and what it is typically built to process also explains why the country still imports a significant amount of oil, taking in an average of 8 MMbpd in late 2018. Since January 2018, higher prices have helped increase U.S. crude production nearly 20 percent. U.S. crude exports therefore more than doubled year-over-year to average 1.9 MMbpd in 2018. The rise in production, augmented by takeaway constraints in West Texas that have depressed local prices, has offered a key advantage for U.S. exporters by keeping WTI prices in check. In contrast, mounting global demand and geopolitical concerns (e.g., U.S. sanctions returning to Iran) have pressured Brent, the international benchmark, to the upside. Rising from nothing prior to 2016 to 510,000 bpd in June 2018, China has accounted for 20 percent of U.S. crude exports in recent years. But a U.S-China trade war that officially kicked off that very month has China implementing a 25 percent tariff on U.S. crude. By August, purchases from the U.S. had dropped to zero. For China, similar quality West African oil is a practical replacement for American crude. But for the United States, an alternative market for China is a much harder find. India could help but its oil market is just a third the size of China’s, and India has bought just 10 percent of the U.S. crude that China has.
First U.S. crude cargoes head to China since trade breakthrough: sources (Reuters) – Three cargoes of U.S. crude are heading to China from the U.S. Gulf Coast, trade sources said on Monday, the first departures since late September and a 90-day pause in the two countries’ trade war that began last month. The vessels left Galveston, Texas, last month and are scheduled to arrive at Chinese ports between late January and early March, according to shipbrokers and vessel tracking data. The shipments mark a change since Chinese buyers largely began avoiding U.S. oil during the trade dispute that flared last summer. “It looks like China has resumed purchasing U.S. crude,” one U.S.-based shipbroking source said. The person, who declined to be identified because he was not authorized to speak publicly about the matter, said the destination data could yet change. China is the world’s biggest crude importer and became a top buyer of U.S. crude after Washington lifted a 40-year ban on shipments in late 2015. It imported 325,000 barrels per day (bpd) of U.S. crude in the first nine months of 2018, customs data showed. Beijing has also resumed purchases of some U.S. soybeans for delivery this year. But China’s 25 percent tariff on U.S. soybean cargoes remains in place. The supertanker Alboran carrying about 2 million barrels of oil recently rounded South Africa’s Cape of Good Hope and is due to arrive in China late this month, said brokers, citing fixture data. The Almi Atlas and the Manifa, two other vessels carrying 2 million barrels of crude, are expected to reach China in late February or early March. The two ships are currently located off Brazil, according to Refinitiv Eikon vessel tracking data. The cargoes mark the first shipments of U.S. crude to China since U.S. President Donald Trump in December said China would begin taking more American products.
U.S. refiners scramble as White House eyes Venezuela sanctions (Reuters) – U.S. refiners are bidding up prices for scarce types of crude oil needed for their most sophisticated plants as the United States reconsiders harsher sanctions on Venezuela that could further reduce imports of the country’s oil. Trump administration officials in recent days met with U.S. oil company executives to lay out potential actions in response to the Jan. 10 inauguration of Venezuelan President Nicolas Maduro in an election it considered illegitimate. Among other steps, U.S. officials have recognized the opposition-run Venezuelan congress as the only legitimately elected authority. But the proposals that would most affect the energy industry involve banning U.S. exports of refined products or limiting oil imports – a move that, until now, the White House has not taken even after sanctioning individuals and barring access to U.S. banks. “It’s more serious than I’ve heard before,” said a refining industry executive familiar with the White House discussions. “They are setting the table to pull the trigger if they have to.” U.S. refiners have few supply alternatives if the Trump administration were to cut off crude imports from that country. Supplies of the heavy oils preferred by Gulf Coast refiners have been harder to secure in recent months because of cutbacks and production curbs in Western Canada, Mexico and Venezuela. One type of U.S. heavy oil, called Mars, traded at a $6.80 per barrel premium to U.S. crude futures on Thursday, the strongest in nearly five years and up from a $4.50 per barrel premium on Tuesday, a U.S. oil broker said. U.S. oil companies that depend on Venezuelan oil have opposed past proposals that would halt imports and did so again this week, said several people close to the talks. Two big refiners, Phillips 66 and PBF Energy, cut their dependence on the South American country last year, according to U.S. Energy Information Administration data. Latin American advisors have warned the administration that oil sanctions could backfire by making the United States appear too involved in the Venezuelan political crisis, said a person familiar with talks among the White House, the National Security Council and oil firms.
It May Not Be Just OPEC And Russia That Is Cutting Production – January 1st of 2019 marks the start of another crude oil production cut by OPEC and non-OPEC oil producing nations. An agreement was made and announced in Early December to reduce production by 1.2 million barrels per day (bpd) in order to “stabilize” rapidly falling crude prices. WTI crude futures fell almost 45% from early October to their recent lows on December 24th and OPEC and its allies were determined to stop the selloff. It’s interesting to note that 11% of the fall in the price mentioned above happened after the production cut announcement on December 7th. Clearly, the cut wasn’t going to be enough short-term. Since the lows on Christmas Eve, however, WTI crude has rallied over 10%. Part of that rally has to do with a WSJ article revealing that Saudi Arabia is looking to drive Brent Crude prices back up to the mid-$80 range. According to the article they intend to make a big splash in January, preparing deeper production cuts than required as part of the OPEC+ agreement. People forget that compliance during the last production cut averaged 116% of promised cuts and most of that was done by the Saudi’s. There is also evidence of a potential slowdown in U.S. shale production. The rate of hydraulic fracturing began to decline in the last four months of 2018. According to Rystad Energy, the average number of fracking jobs declined to 44 per day in November 2018, down from an average of between 48 and 50 for the five-month period between April and August 2018. Rystad Energy’s research fit well with that of the Dallas Fed, which reported last week that drilling activity began to slow in the Permian Basin in Texas in the fourth quarter. Shale tends to slow with falling prices, so this is not a surprise, but if demand picks up at all, prices may spike and more quickly than the market is expecting. Maybe not a rush to $80, but high $60’s/low $70s could be in the cards by late February.
Chesapeake to cuts rigs from 18 to 14 in 2019 – Chesapeake Energy has reported estimated average fourth-quarter 2018 production will be between 462,000 and 464,000 barrels of oil-equivalent per day (Boe/d), Kallanish Energy reports. It also said Q4 2018 estimated average oil production was between 86,000 and 87,000 barrels per day (Bpd). The company said it intends to cut capital spending in 2019, but expects to grow production due to improved efficiencies and its focus on high-margin oil assets expected to provide financial benefits. It will reduce the number of drilling rigs by 22% in 2019, to 14 from the 18 rigs now under contract. Rig costs have been reduced, Chesapeake said. Chesapeake said it has reduced its debt by $1.8 billion from year-end 2017, to roughly $8.2 billion at year-end 2018. Chesapeake is improving its margins while reducing debt and improving its sustainable cash flow, CEO Doug Lawler said, in a statement. He noted the company generated more than $2 billion in net proceeds through its divestment of its Utica Shale assets in Ohio. The company lost production with the Utica sale to Encino Acquisitions Partners, but that was replaced by growing production in late 2018 from the company’s assets in the Eagle Ford Shale in South Texas and the Powder River Basin in Wyoming. The Utica produced 10% of the company’s oil production in 3Q 2018. Chesapeake is also proceeding with its proposed $4 billion merger with WildHorse Resources. Shareholders of both firms will vote on the merger Jan. 31. Chesapeake said it intends to operate four rigs in the WildHorse acreage in 2019. It is also proceeding with its Austin Chalk and Upper Eagle Ford appraisal programs, with results likely released by April 1.
WildHorse to Lay Off Staff After Chesapeake Acquisition – WildHorse Resources Management Company, which is being acquired by Chesapeake Energy Corporation, is laying off all employees at its Houston headquarters, according to a letter dated Dec. 13, 2018 sent to the Texas Workforce Commission (TWC). According to the TWC, 94 employees will lose their jobs on the date of the closing of the Chesapeake deal, expected to happen between Feb. 1 and Feb. 14. If the closing date is prior to the date that is 60 days after Dec. 13, 2018, (or prior to Feb. 11), then affected employees that have remained through the closing date will be provided supplemental payment and benefits during the period beginning on the date that immediately follows the closing date and Feb. 11, the letter states. The Houston office of WildHorse will be closed and all layoffs will be permanent. Affected employees will not be able to retain their jobs by displacing or bumping another employee.
Chevron Capex Highlights Permian — Chevron Corp. will spend about half its capital budget on projects that yield quick returns over the next three years, underscoring the importance of shale as it prepares for growing uncertainty in how the world consumes energy. The U.S. oil giant will spend about $9 billion to $10 billion a year on “short-cycle investments” through 2022, primarily focused on the Permian Basin, the world’s biggest shale oil region, the San Ramon-based company said in a presentation on its website Friday. The Permian is on course to make up about one in five barrels the super major pumps worldwide. Big Oil was slow to join the U.S. shale boom, focusing on mega offshore projects while watching independent wildcatters work out the technology before dipping their toes in. But now they’re investing heavily, attracted by the ability to ramp up production quickly and potentially reduce it if oil prices crash. That’s a particularly useful trait when the future of oil and gas consumption is unclear, with electric vehicle usage growing and governments clamping down on greenhouse gas emissions. “Most of our assets are competitive when tested against aggressive scenarios” such as the International Energy Agency’s sustainable development model, Chevron said. “Our portfolio is resilient and flexible.” Oil and natural gas production increased by about 7 percent last year compared with a year earlier, Chevron said, in line with analysts’ expectations. The company also said “organic” capital-projects spending exceeded its target by 5 percent in 2018.
US oil and gas rig count drops 11 to 1127, ninth consecutive week of drops – The US oil and rig count dropped by 11 to 1,127, the ninth consecutive week of decreases as oil prices continued to hover in the low $50s/b, S&P Global Platts Analytics said Thursday. The losses all came from oil-directed rigs, which fell 11 to 886, while gas-oriented rigs were unchanged at 220, Platts data for the week ended January 16 showed. The typical two- to three-month lag between oil prices and rig activity may have now caught up with the domestic rig count, as oil prices began falling from levels in the mid-$70s/b in October. Rig counts also fell in most of the eight large domestic marquee plays, although the Permian appeared to be the featured exception in gaining three rigs to 481. The Permian in now down 18 rigs since its recent peak of 499 in mid-November. The Haynesville Shale, chiefly a dry gas play in East Texas and Northwest Louisiana, was up one rig to 63. But the DJ Basin in Colorado was down four rigs to 32, while the Eagle Ford Shale in South Texas and the SCOOP/STACK play in Oklahoma were each down three rigs in the past week to 88 and 103, respectively. The Marcellus Shale, mostly sited in Pennsylvania, was down two rigs to 60, while the Utica Shale largely in Ohio was down one rig to 16. The Eagle Ford has showed the longest streak of rig declines in the last several weeks – a total of 13 from 101 rigs in the first week of December, Cavey said. Prior to October of 2018, all signs pointed towards production growth in the Eagle Ford as WTI crude prices reached their highest since late 2014 at roughly $75/b, he said in a written analysis in Platts’ January Southeast/Gulf Oil and Gas Production Monitor. At the same time, shale production in that basin managed to grow a bit, reaching 1.37 million b/d in December 2018, 100,000 b/d higher than the prior year’s exit rate. “The half-cycle internal rate of return for a typical well in the Eagle Ford is currently 27%.” That means the average producer is making money, but their margins have become increasingly slim with IRRs dropping nearly 33 percentage points since October of last year, he added. “As a result, shale oil production in the Eagle Ford is forecast to remain largely flat and grow merely 32,000 b/d exit-to-exit in 2019,”
US Drops 25 Oil and Gas Rigs This Week – The United States dropped a whopping 21 oil rigs this week, marking the third consecutive week of declines and the biggest drop since early 2016, according to data compiled by Baker Hughes, a GE Company. In addition to the oil rig decline, gas rigs dipped by four. The states who saw the bulk of the declines were Texas and Oklahoma, who lost 11 and 10 rigs, respectively. California lost three rigs, Kansas and Louisiana each lost two and Colorado and Pennsylvania each lost one. The following states all added one rig: Alaska, New Mexico, North Dakota, Ohio, West Virginia and Wyoming. In regard to basins, the Permian saw the deepest declines this week, dropping seven rigs. The Granite Wash dropped three rigs, while the Mississippian lost one. Rig gains included Cana Woodford (five) and the Ardmore Woodford, Eagle Ford, Haynesville and Marcellus all added one rig. This week’s total rig count is 1,050. It’s still 114 higher than the rig count one year ago, which was 936.
US Oil Rig Count Plummets Most In 3 Years After Production Hits Record High – After surging 200k b/d in the last week to a new record for US crude production, Baker Hughes reports that the US oil rig count has plunged by 21 in the last week – the biggest drop since Feb 2016. Is this the turn for the Permian? Perhaps, but, as OilPrice.com’s Nick Cuningham notes, while low oil prices are beginning to slow the growth of U.S. shale, in the years ahead oil and gas drilling could be curtailed by a different problem: a shortage of water. Water is a crucial ingredient in the fracking process, and drillers use copious volumes of it. The problem for the U.S. oil industry is that so much of the output growth expected over the next half-decade or so depends very heavily on the Permian basin, where water is increasingly scarce. Water already accounts for about 15 percent of the cost of a shale well, according to analysts at Morgan Stanley. “In the Permian, total spending on water is expected to double over the next 5 years, to $22B, with E&Ps on avg using 50 barrels (bbls) of water for each lateral foot completed,” the investment bank wrote in a new report. “Assuming 10k lateral feet per well, this implies that the ~5,500 existing Permian well permits will require ~2.75 billion bbls of water to complete.”That’s a lot of water in an area that doesn’t have a lot of it. “Given the sizeable water need, we believe drought and water scarcity present long-term risks to shale economics, particularly in the Permian, a core area of growth in a drought-prone region,” Morgan Stanley warned.It’s worth pausing and noting that the warning is not coming from an environmental group, or even a local community organization opposed to a drilling presence. It’s coming from a major Wall Street investment bank, which says that drilling economics in the world’s hottest shale basin could be upended because of water scarcity.It’s a rather ironic development. Greenhouse gas emissions from oil and gas drilling are fueling climate change, which in turn could make the most desirable oil and gas play increasingly costly due to growing water problems.
New U.S. Oil And Gas Drilling To Unleash 1,000 Coal Plants’ Worth Of Pollution By 2050 – HuffPost – Amid mounting calls to phase out fossil fuels in the face of rapidly worsening climate change, the United States is ramping up oil and gas drilling faster than any other country, threatening to add 1,000 coal plants’ worth of planet-warming gases by the middle of the century, according to a report released Wednesday. By 2030, the U.S. is on track to produce 60 percent of the world’s new oil and gas supply, an expansion at least four times larger than in any other country. By 2050, the country’s newly tapped reserves are projected to spew 120 billion metric tons of carbon dioxide emissions into the atmosphere. That would make it nearly impossible to keep global warming within the 2.7 degrees Fahrenheit above pre-industrial averages, beyond which United Nations scientists forecast climate change to be catastrophic, with upward of $54 trillion in damages. The findings ― from a report authored by the nonprofit Oil Change International and endorsed by researchers at more than a dozen environmental groups ― are based on industry projections collected by the data service Rystad Energy and compared with climate models used by the United Nations’ Intergovernmental Panel on Climate Change (IPCC), the world’s leading climate research body. The report casts a new light on the impact of the U.S. fracking boom and calls into question the Trump administration’s stance that China, which surpassed the U.S. as the world’s largest emitter of carbon dioxide in 2007, remains the biggest impediment to halting warming. Nearly 90 percent of new U.S. oil and gas drilling through 2050 is expected to depend on hydraulic fracturing, or fracking, the controversial technique that blasts bedrock with chemical- and sand-laced water, creating cracks that release previously inaccessible fuels. Upward of 60 percent of the emissions enabled by new U.S. drilling would come from two major fracking hot spots ― the Permian Basin, a massive field stretching from Texas to New Mexico; and the Appalachian Basin, encompassing most of Pennsylvania, West Virginia and Ohio. Continued extraction in the Permian Basin alone would use up 10 percent of the emissions that remain in the entire world’s carbon budget to keep warming within 2.7 degrees Fahrenheit.
Big win for oil and gas industry: Colorado Supreme Court reverses Appeals Court ruling in Martinez case – In a win for the oil and gas industry, the Colorado Supreme Court on Monday reversed a lower court ruling that said the Colorado Oil and Gas Conservation Commission should give more weight to the public health, safety and the environment when considering new drilling. However, the win could turn out to be a lull before the next political face-off that has become more common as drilling has ramped up in the state’s more populous areas. As industry representatives welcomed the court’s decision, saying it upholds the law’s recognition of multiple interests, legislators and Gov. Jared Polis said the ruling highlights the need for changes to better protect the public. “The bottom line is we need to make sure that health and safety are a priority and reform of the (Colorado Oil and Gas Conservation Commission) is a beginning,” said Sen. Mike Foote, D-Lafayette. “We are working on a bill to make sure health and safety are prioritized.” Last week, newly inaugurated Gov. Jared Polis said in his first State of the State address that he would work to give communities more say in how oil and natural gas are developed. Polis has set a goal of moving Colorado’s electric grid to entirely renewable sources by 2040, although he concedes it’s more of an aspirational goal. “While I’m disappointed by today’s ruling, it only highlights the need to work with the legislature and the Colorado Oil & Gas Conservation Commission to more safely develop our state’s natural resources and protect our citizens from harm,” Polis said in a statement.
‘Shameful’: Colorado Supreme Court Denounced for Siding With Big Oil Profits Over Public Health in Youth-Led Suit – In a move green groups and youth climate leaders denounced as a gift to the fossil fuel industry at the expense of public health, the Colorado Supreme Court on Monday reversed a lower court decision and ruled that the state’s regulators do not have to consider environmental and health impacts before approving new oil and gas projects.“We will continue the fight for our Earth and our future, despite the mountains we need to climb and the setbacks that we will overcome. Regardless of the court’s decision in our case, the fight will continue.” – Emma Bray“It is so disappointing for the youth and the people of Colorado to hear the decision from the Colorado Supreme Court today,” said Xiuhtezcatl Martinez, an 18-year-old plaintiff in the youth-led suit against the Colorado Oil and Gas Conservation Commission (COGCC).”To know that the judges in the highest court of my state believe that the interests of the oil and gas industry come before the public health, safety, and welfare of my fellow Coloradans is shameful,” Martinez added. “But I want you all to know that this fight for climate justice is far from over. My fellow plaintiffs, youth around the world, and I will continue to stand up for our right to a healthy future.” Emma Bray, a 19-year-old plaintiff from Denver, said in a statement the ruling will not stop the growing youth movement for bold climate solutions. “Not a single person, company, or corporation can silence the young generation’s voices,” Bray declared. “We will continue the fight for our Earth and our future, despite the mountains we need to climb and the setbacks that we will overcome. Regardless of the court’s decision in our case, the fight will continue.”
With Colorado High Court Setback, Fracking Activists Look To Continue Statehouse Fight – Environmental activists here were dealt a blow Monday when the Colorado Supreme Court ruled against a closely watched case that would have required the state to prioritize health and environmental concerns in oil and gas permitting. But with a newly Democratic legislature and governor in the state promising to take another look at the fracking debate, environmentalists are optimistic that they can pursue a successful strategy in the statehouse. “This decision really validates everything that we’ve been saying, that this state is not prioritizing public health and safety, and that regulations are not sufficient,” said Anne Lee Foster of Colorado Rising, a group opposed to the hydraulic fracturing drilling technique known as fracking. “We’ve shown that this is a real issue impacting Coloradans every day, and we’re going to keep fighting until the end.” “It’s in the hands of the legislators now,” she added. Monday’s decision caps a five-year legal fight brought by six youth activists from Boulder County. The activists, led by Xiuhtezcatl Martinez, filed a petition with the state’s oil and gas regulatory body in 2013 asking that new permits be suspended until a comprehensive scientific study could show that new activity would be safe. When the petition was denied, the activists sued and ultimately won a favorable decision in the Martinez case in the state’s Appeals Court last spring. But Monday’s Supreme Court ruling overturns that interpretation, leaving existing policy in place. The state, the court found, was right to continue to interpret permits by weighing “cost-effectiveness and technical feasibility” against adverse effects on health and the environmental. The case was closely watched along Colorado’s Front Range, where the fracking boom has put wells near playgrounds, parks and schools (Extraction Oil and Gas infamously installed a fracking site just 1,360 feet from the largely minority Bella Romero Academy in Greeley.) Concerns about worsening air quality and health effects, such as increased cancer risks, have led to lawsuits and community actions, including an unsuccessful ballot measure in November to increase well setbacks, requiring that they be located at least 2,500 feet from occupied buildings.
Weld County oil and gas spill report for Jan. 13 – The following spills were reported to the Colorado Oil and Gas Conservation Commission in the past two weeks. Information is based on Form 19, which operators must fill out detailing the leakage/spill events. Any spill release that may impact waters of the state must be reported as soon as practical. Spills and leaks typically are found during routine maintenance on existing wells, though some actual “spills” do occur among the 23,000-plus wells in the county.
- • KP KAUFFMAN COMPANY INC, reported Jan. 8 a historical flowline spill in Frederick, near Weld County roads 16 and 15. Less than a barrel each of oil and produced water spilled. Crews found the spill while cleaning a non-reportable release caused by high line pressure in a flowline. Historical contamination is being excavated and disposed of at a landfill.
- • AKA ENERGY GROUP LLC, reported Jan. 7 a gas compressor station spill about 1 mile west of Gilcrest, near Weld roads 42 and 27. Between one and five barrels of condensate and less than a barrel of produced water spilled. A third-party truck driver transferred condensate to the incorrect tank battery, which was already full. Impacted soil will be disposed of at a landfill.
- • DCP OPERATING COMPANY LP, reported Jan. 7 a pipeline spill about 2 miles north of Fort Lupton, near Weld 20 and U.S. 85. Between one and five barrels of condensate spilled. A six-inch gas gathering pipeline developed a leak.
- • BONANZA CREEK ENERGY OPERATING COMPANY LLC, reported Jan. 4 a historical tank battery spill about 4 miles southeast of Kersey, near Weld roads 44 and 46. More than five barrels of oil spilled. The release was initially reported in 2009, but was never closed. A loadline froze overnight and failed at the production tank, releasing oil into the earthen containment berm. The oil was vacuumed up and the impacted soil was disposed of at a landfill.
- • HIGHPOINT OPERATING CORPORATION,reported Jan. 4 a well spill about 2 miles west of Hereford, near Weld roads 136 and 77. About four and a half barrels of produced water spilled. The liner came loose from the polish rod, spilling produced water to the pad surface..
- • CONFLUENCE DJ LLC, reported Jan. 2 a tank battery spill about 2 miles south of Hudson, near Weld roads 8 and 45. About 260 barrels of oil spilled inside containment. A drain line valve on the back of the oil tank blew out.
- • WHITING OIL & GAS CORPORATION, reported Jan. 2 a tank battery spill about 8 miles northeast of Keota, near Weld roads 110 and 127. About 30 barrels of produced water spilled into lined containment. The cause is being investigated and has been associated with a 4-inch tee on the produced water loadout line.
- • PDC ENERGY INC, reported Dec. 31 a tank battery spill about 6 miles northeast of Kersey, near Weld roads 64 and 61. An unknown amount of oil and between five and 100 barrels of produced water spilled. A water vault valve failure released the produced water and oil inside containment.
Democrat: Keystone XL developer should pay into cleanup fund (AP) – South Dakota lawmakers should require the Keystone XL pipeline’s developer to pay into a state oil spill cleanup fund and impose more regulations on so-called man camps, the state Senate Democratic leader said Friday. Sen. Troy Heinert, a member of the Rosebud Sioux Tribe, said that the state and legislators should sit down with the tribes to hear their concerns. The proposals come a day after Rosebud President Rodney Bordeaux addressed the Legislature, saying the pipeline gives his people great anxiety. “We know that a lot of the resistance is going to come near tribal land,” Heinert said of the pipeline that would go through South Dakota. “Nobody wants violence … on any side, but nobody wants to be, you know, run over by private security forces either.” The project is being delayed by a federal court that found the Trump Administration didn’t fully consider the environmental effects when it approved the permit for the 1,184-mile (1,900 kilometer) pipeline, intended to ship up to 830,000 barrels a day of Canadian crude through Montana and South Dakota to Nebraska, where it would connect with lines to carry oil to Gulf Coast refineries. A hearing on the proposed pipeline is scheduled for Monday in Montana. Heinert said he would “just as soon see it not built.”
Jury awards Boone County landowner $250,000 in Dakota Access pipeline lawsuit — A Boone County jury this week awarded a property owner who sued over the construction of an oil pipeline through her property $250,000 following a nearly weeklong trial in which she challenged the pipeline’s use of eminent domain. The jury returned its judgment in the case against Dakota Access on Wednesday, saying the $250,000 was the difference in the “fair and reasonable value of the property,” before it was taken through eminent domain in July 2016, and the value of the property after it was taken. Judith Anne Lamb, as trustee of the Judith Anne Lamb Revocable Trust, filed the lawsuit in 2016 as construction on the pipeline was beginning. Its construction, which was completed in 2017, was the focus of protests from activists across Iowa, including Boone and Story counties. Lamb and her husband, Richard, live in the Iowa City area but own about 150 acres in Boone County, just west of Ames. Telephone messages left for attorneys for Lamb and Dakota Access were not returned. Lamb claimed the construction of the pipeline damaged the land and decreased its value. In court documents, Lamb said that because of a multitude of opportunity for commercial use for the land, an initial evaluation in July 2016 showing the land’s value at just over $90,000, was just a fraction of its actual value. She said the land had a value of about $950,000. At the center of the debate leading up to and during its construction was the use of eminent domain to take land needed to bury the pipeline, with opponents arguing the project didn’t meet the requirement of public benefit to use eminent domain. Opponents also argued the environmental risks associated with its construction and eventual operation were too great, and that the construction of the pipeline would cause long-term damage to valuable farmland.
Permits revoked for 40 idled natural gas wells near Buffalo — A state regulatory board revoked a company’s permits Thursday for 40 natural gas wells near Buffalo that have been idle for the past seven years while the company has struggled financially. The state Board of Minerals and Environment, a nine-member citizen panel appointed by the governor, took the action during a meeting in Pierre. The board also directed the state Department of Environment and Natural Resources to calculate and make a report at the board’s next meeting on Feb. 21 on the maximum civil penalty that may be assessed against the company, Spyglass Cedar Creek LP, of Houston, Texas. The maximum penalty could be in the millions of dollars. Discussion at the meeting indicated that the board may legally assess penalties of up to $500 per day, starting from the issuance of a notice of violation on July 10, for each regulatory violation at every one of the 40 wells. The violations include unproductive and unplugged wells, inadequate signage, missing reports and logs, missing or inadequate well gauges, and insufficient reclamation at well sites. Board Chairman Rex Hagg, of Rapid City, expressed preliminary support for a maximum penalty. “I think when you look at the record in its entirety on this matter, I don’t think it gets much more egregious, absent some major environmental leak or problem,” Hagg said.
Explosion reported at Watford City salt water disposal site — Emergency personnel responded to an explosion at an oil field salt water disposal site southeast of Watford City on Thursday. Karolin Jappe, McKenzie County’s emergency manager, said there was one man on site at the time of the incident. The man was not injured. The incident, which took place at a White Owl Energy Services site, was reported at 12:15 p.m. Jappe said the cause of the explosion and fire is unknown. “It’s unusual to have (fires) at a salt water disposal in the winter,” she said. “Usually it’s in the summer when lightning hits it. We can have four to five per summer.”
North Dakota seeing seasonal dip in oil production – Oil and gas production in North Dakota retreated a bit in November after hitting all-time highs during the previous month. North Dakota, the nation’s second-largest oil producing state after Texas, pumped out 1.38 million barrels per day in November, down 1.2 percent from October. Natural gas production fell 1.5 percent in November to 2.52 million MCFs per day. (An MCF is 1,000 cubic feet of gas.) “This is the marginal drop in production I warned people about with winter coming on and lower oil prices,” said Lynn Helms, director of North Dakota’s Department of Mineral Resources. Oil prices dropped rapidly in November, while the state experienced about 15 days of below-average temperatures and above-average precipitation. Oil production in North Dakota tends to slow somewhat as winter weather sets in. Despite falling oil prices, “the industry remains cautiously optimistic,” Helms said. “They have not backed down on the rig count.” The number of oil rigs currently operating in North Dakota is 68, up from 67 in December and 64 in November. A rising rig count indicates operators are drilling more new wells. West Texas Intermediate (WTI), the benchmark U.S. crude oil price, hit a nearly four-year high of $76 in October. But oil production rose while fear spread about a weakening global economy, sending WTI below $50 per barrel by the last half of December and into early January. The price has since rallied to $52. North Dakota oil trades at a discount price to WTI and is currently at about $37 a barrel.
Boom Ahead For Pacific Northwest LPG Exports? – LPG export terminals along the Gulf Coast account for more than nine of every 10 barrels of propane and normal butane that are shipped from the U.S. to foreign buyers. That makes perfect sense, given the terminals’ proximity to major NGL production areas like the Permian, the Eagle Ford and SCOOP/STACK, and to the world-class fractionation hub in Mont Belvieu, TX. But, increasingly, LPG terminals on the East and West coasts, are growing in significance. On the Atlantic side, Marcus Hook, near Philadelphia, is enabling more and more volumes of Marcellus/Utica-sourced propane and butane to reach overseas markets. And, as we discuss in today’s blog, West Coast exports are on the rise as well, with Petrogas’s Ferndale terminal in Washington state providing a straight shot across the Pacific to Asia for propane and butane fractionated in Western Canada, plus a good bit more LPG export capacity under development in British Columbia. This is the fourth and final episode in this series on rising LPG export volumes and the race to develop new export terminal capacity to handle still-higher volumes of propane and normal butane – two NGL purity products generally referred to as LPG – into the early 2020s. We set the stage in Part 1, where we noted that the U.S. flipped from being a net importer to a net exporter of LPG in 2012, and that waterborne LPG exports subsequently soared to more than 1.1 MMb/d (in 2018). The vast majority of those volumes – about 92% of last year’s total – are being sent out of the half-dozen LPG terminals in coastal Texas and Louisiana. The rest of the exports-by-ship are flowing through a total of three smaller terminals in the Mid-Atlantic region and Pacific Northwest. We concluded Part 1 with a review of the Gulf Coast’s – and the U.S.’s – largest LPG export facility: the Enterprise Hydrocarbon Terminal (EHT), which is located on the Houston Ship Channel and whose capacity is in the midst of being expanded to 720 Mb/d from the current 545 Mb/d. According to our NGL Voyager report, EHT sent out an average of 447 Mb/d of LPG last year, or about 40% of total U.S. LPG exports by ship.
Art Berman- Exposing The False Promise Of Shale Oil – (podcast & transcript) Art Berman, geological consultant with over 37 years experience in petroleum exploration and production, returns to the podcast this week to debunk much of the hopium currently surrounding America’s shale oil output. Because the US is pinning huge hopes on its shale oil “revolution”, so much depends on that story being right. Here’s the narrative right now:
- The US, is the new Saudi Arabia
- It’s the swing producer when it comes to influencing the price of oil
- The US will be able to increase oil production for decades to come
- New technology is unlocking more oil shale supply all the time
But what if there’s evidence that runs counter to all of that? We’re going to be taking a little victory lap on this week’s podcast because The Wall Street Journal has finally admitted that shale oil wells are not producing as much as the companies operating them touted they would produce — which is what we’ve been saying for years here at PeakProsperity.com, largely because we closely follow Art’s work:The Wall Street Journal did some research and they got the general point that the wells are not as good as advertised.But what they missed is just how much farther off many of these reserves are than even the discounted reserves that they’ve reported.Bottom line: if the understatement is only 10%, that’s a rounding error and it’s not that much of an issue to the average person. But I’ve been trying for a decade to get the number that I independently develop to get anywhere close to the published numbers. In most cases, I can only get near 60% or 70% of them. So, the gap, I think is much more substantial.The reason that The Wall Street Journal didn’t get it more right is because they don’t do any independent research and of course they didn’t talk to me, they didn’t talk to Dave Hughes, they didn’t talk to people who actually do the work, and so they’re getting one side of the story. Click the play button below to listen to Chris’ interview with Art Berman (52m:56s).
‘Realistic’ new model points the way to more efficient and profitable fracking – A new computational model could potentially boost efficiencies and profits in natural gas production by better predicting previously hidden fracture mechanics. It also accurately accounts for the known amounts of gas released during the process. “Our model is far more realistic than current models and software used in the industry,” said ZdenÄ›k Bažant, Professor of Civil and Environmental Engineering, Mechanical Engineering, and Materials Science and Engineering at Northwestern’s McCormick School of Engineering. “This model could help the industry increase efficiency, decrease cost, and become more profitable.” Despite the industry’s growth, much of the fracking process remains mysterious. Because fracking happens deep underground, researchers cannot observe the fracture mechanism of how the gas is released from the shale. “This work offers improved predictive capability that enables better control of production while reducing the environmental footprint by using less fracturing fluid,” said Hari Viswanathan, computational geoscientist at Los Alamos National Laboratory. “It should make it possible to optimize various parameters such as pumping rates and cycles, changes of fracturing fluid properties such as viscosity, etc. This could lead to a greater percentage of gas extraction from the deep shale strata, which currently stands at about 5 percent and rarely exceeds 15 percent.”
US oil output to average 12 million bopd in 2019 – U.S. crude oil production will average 12.1 million barrels per day (MMbpd) in 2019 and 12.9 MMbpd in 2020, with most of the growth coming from the Permian region of Texas and New Mexico. That’s according to the U.S. Energy Information Administration’s (EIA) latest short-term energy outlook, which estimates that U.S. crude oil production averaged 10.9 MMbpd in 2018. The EIA’s latest outlook forecasts that U.S. dry natural gas production will average 90.2 billion cubic feet per day (Bcf/d) this year and 92.2 Bcf/d in 2020, with increases in the Appalachia and Permian regions “driv[ing] the forecast growth”. U.S. dry natural gas production averaged 83.3 Bcf/d in 2018, the EIA highlighted. U.S. crude oil and petroleum product net imports are estimated to have fallen from an average of 3.8 MMbpd in 2017 to an average of 2.4 MMbpd in 2018, according to the EIA’s January outlook. The organization forecasts that net imports will continue to fall to an average of 1.1 MMbpd in 2019 and to less than 0.1 MMbpd in 2020. In the fourth quarter of 2020, the EIA forecasts the United States will be a net exporter of crude oil and petroleum products, by about 0.9 MMbpd.
Surging oil output will push US towards energy independence in 2020, Dept of Energy says – The U.S. will make major strides towards energy independence in the next two years as oil production and exports hit new highs, according to the Department of Energy. U.S. oil production, already at an all-time high this year, will increase by another 2 million barrels per day by 2020, the agency’s statistics bureau projects. The same year, the nation will start exporting more crude oil and fuel than it imports, the Energy Information Administration said in in its latest forecast. American drillers pumped an average 10.9 million bpd in 2018, breaking the record going back to 1970. EIA sees U.S. output averaging 12.1 million bpd this year and 12.9 million bpd in 2020. “According to the January outlook, the Permian region of Texas and New Mexico will continue to push U.S. production into record territory over the next 24 months, approaching 13 million barrels per day some time in 2020,” EIA Administrator Linda Capuano said in a statement. Most of the growth is coming from shale fields like the Permian, where frackers use advanced drilling methods known as hydraulic fracturing to free oil and natural gas from rock formations. The surge in U.S. production is making the country less reliant on foreign oil. In 2018, net imports of oil and petroleum products fell from 3.8 million bpd to 2.4 million bpd. EIA forecasts net imports will dwindle to 1.1 million bpd next year and just 100,000 bpd in 2020. In the final three months of 2020, EIA thinks the U.S. will become a net exporter by about 900,000 bpd. The U.S. already ships out more natural gas than it imports. Next year, gas production will jump another 8 percent to a new all-time high at 90.2 billion cubic feet per day, EIA projects. Growth in 2020 is seen slowing, with gas output hitting 92.2 Bcf per day. By 2020, EIA thinks natural gas will generate 37 percent of the country’s electric power, up from 35 percent last year. Meanwhile, coal’s share of electric power generation will slip from 28 percent to 24 percent during the same period. That will help contribute to a further drop in U.S. coal production.
STEO highlights: US oil output to hit 13 million b/d in 2020 despite slower growth – – US oil production is on track to hit 12 million b/d in March and 13 million b/d in October 2020, but the growth rate will slow considerably from recent levels in response to lower forecast WTI prices and ongoing Permian pipeline constraints, the Energy Information Administration said Tuesday. EIA expects the spread between WTI-Cushing and Midland wellhead prices to widen this year, which will slow drilling activity growth in Texas and New Mexico, but that growth will start to accelerate on a monthly basis into 2020 after new pipeline capacity comes online later this year. US oil production is forecast to average 12.07 million b/d in 2019 and 12.86 million b/d in 2020, EIA said in its monthly Short-Term Energy Outlook, which included 2020 projections for the first time. EIA said the US produced 11.8 million b/d in December, a staggering 1.76 million b/d increase from December 2017. US output averaged 10.93 million b/d in 2018.The US will become a net oil exporter in Q4 2020, EIA said, with total exports of crude and refined products exceeding total imports by 870,000 b/d.Other highlights of the Short-Term Energy Outlook:
- ** EIA forecast Brent crude prices to average $60.52/b in 2019 and $64.76/b in 2020, down from the 2018 average of $71.19/b.
- ** WTI crude is forecast to average $54.19/b this year and $60.76/b in 2020, down from $65.06/b in 2018.
- ** Global oil markets will be relatively balanced in 2019-20 as US output growth more than offsets declines from the OPEC-led output cuts, EIA said.
- ** Permian production will account for 600,000 b/d of total US growth in 2019 and 500,000 b/d in 2020, EIA said. It sees Permian output hitting 4.8 million b/d by end-2020, about 1 million b/d higher than in December 2018.
- ** EIA expects Bakken output to rise to 1.4 million b/d in 2019 and 1.5 million b/d in 2020, as growing natural gas takeaway constraints slow growth. The Bakken produced about 1.3 million b/d in 2018.
- ** Eagle Ford output is forecast to rise by 90,000 b/d to 1.4 million b/d in 2019 and then fall slightly in 2020.
- ** US offshore oil production is expected to average 1.9 million b/d in 2019 and 2.2 million b/d in 2020, up from 1.7 million b/d in 2018, when 11 new projects came online. This year, EIA expects six new projects to start, followed by another 12 in 2020.
- ** Alaska’s production is expected to remain flat at 490,000 b/d in 2019 and 2020.
US will ‘reinforce its leadership’ as the world’s top crude producer in 2019, IEA says – The level of crude output from the U.S. will once again be a major factor this year, the International Energy Agency (IEA) said its closely-watched report on Friday, with the energy giant on track to reaffirm its position as the world’s leading crude producer. The IEA report comes shortly after OPEC and non-OPEC producers officially implemented a fresh round of supply cuts. Alongside Russia and nine other nations, top oil exporter Saudi Arabia struck a deal with the rest of OPEC in December to keep 1.2 million barrels per day (b/d) off the market from the start of January. “While the other two giants voluntarily cut output, the U.S., already the biggest liquids supplier, will reinforce its leadership as the world’s number one crude producer,” the Paris-based IEA said Friday. “By the middle of the year, U.S. crude output will probably be more than the capacity of either Saudi Arabia or Russia.” International benchmark Brent crude traded at around $61.69 Friday morning, up 0.8 percent, while U.S. West Texas Intermediate (WTI) stood at $52.56, almost 1 percent higher. Brent crude has fallen almost 30 percent since climbing to a peak of $86.29 in early October last year, while WTI is down more than 31 percent over the same period. The collapse in oil prices was exacerbated by concerns about oversupply, as well as a stock market slump amid worries over rising U.S. interest rates. That prompted OPEC and non-OPEC producers to throttle back output at the start of 2019, in an effort to try to put a floor under falling oil prices. The IEA has previously touted the “growing influence” of the U.S. in global oil markets, saying such a dramatic rise in crude output could soon challenge the market share of OPEC kingpin Saudi Arabia and non-OPEC heavyweight Russia. U.S. crude production has soared in recent months, rising by more than 2 million b/d to an unprecedented 11.9 million b/d. The IEA said Friday that its estimates for global oil demand growth in 2018 and 2019 remained unchanged at 1.3 million b/d and 1.4 million b/d, respectively. The group said the impact of higher oil prices in 2018 was “fading,” which should help to offset cooling economic growth over the coming months.
The US oil boom is only getting started – Remember that brief moment in late 2018 when the U.S. became a net exporter of crude oil and petroleum products combined? It was just a preview of what’s to come late next year, according to the Energy Information Administration’sfirst detailed 2020 market forecast. “EIA forecasts that net imports will continue to fall to an average of 1.1 million [barrels per day] in 2019, and to less than 0.1 million b/d in 2020,” per EIA’s outlook published Tuesday. “In the fourth quarter of 2020, EIA forecasts the United States will be a net exporter of crude oil and petroleum products, by about 0.9 million b/d,” they found. That factoid is a sign of the country’s re-emergence as a global oil powerhouse and increasingly prominent exporter as domestic production has surged. Crude oil production is already at record levels of roughly 11.5 million barrels per day and climbing. EIA sees U.S. crude output averaging 12.1 million daily barrels this year and 12.9million in 2020, cracking the 13 million mark late in the year. “Steady growth from non-OPEC countries, including the United States, headlines the forecast for global crude oil production through 2020. We expect the United States to remain the world’s largest producer,” EIA administrator Linda Capuano said in a statement alongside the the report. Here is where I’m contractually obligated to note that the U.S. will still remain very tethered to the whims of global markets, and net exports doesn’t – and, logistically, shouldn’t – mean the country won’t still import lots of crude.
Feature: Europe to see big rise in US crude oil imports in Feb – The volume of US crude oil arriving into Europe, which has been rising of late, will pick up sharply in February, pressuring values for North Sea and Mediterranean grades. “There are a lot of US barrels coming over and landing in February, more than [has been seen in the past couple of months] due to Asia not pulling as much in the near future due to turnarounds,” a crude trader said. “It is going to massively affect the balance of crude and affect North Sea and Urals.” Trading and shipping sources estimated that 800,000-850,000 b/d of US crude will arrive into Europe in February, with the majority headed to Northwest European refineries, although a sizeable volume will go to Mediterranean destinations. While the main crude grade continued to be light, sweet WTI Midland, sources said naphtha-rich Eagle Ford and medium sour Mars have also been offered to refineries. Earlier this month, three VLCCs were said by sources to have been placed on subjects to ship US crude to Europe. US crude rarely moves to Europe in VLCCs, and the trend only started on December 24 when the VLCC Olympic Lady left Corpus Christi Lightering for Rotterdam. Indeed, European refiners typically prefer Aframax-size cargoes and, to a certain extent, Suezmaxes which offer more flexibility than the larger VLCCs. The Brent-WTI spread — assessed at $8.55/b at the London close Wednesday– has been less of a factor as it has largely remained within an $8.00-$10.50/b range since early September, S&P Global Platts data showed. Platts assessed the route at Worldscale 115 Wednesday, down from a peak at w192.50 late last year. The arrival of US crude has affected Kazakhstan’s CPC Blend and Russia’s Urals crude, which have started to see an impact on demand for February cargoes, trading sources said. In Northwest Europe, medium sour Urals — which differs in quality from most of the US grades, with WTI Midland not considered as a direct competitor — has remained near multi-year highs even as the fuel oil crack has lost some of its previous strength, leading some refineries to consider running a sweeter crude slate. Meanwhile, CPC Blend in the Mediterranean has been facing headwinds from the Turkish straits delays, traders said. With US cargoes not facing those issues, some buyers have increased their US crude intake in February. As a result, CPC Blend will likely command lower prices in February. Urals in Northwest Europe was assessed at a 15.5 cents/b premium to the Mediterranean Dated strip Wednesday, while CPC Blend was assessed at a 70 cents/b discount to the Mediterranean Dated strip. In the North Sea, barrels clearing to the East were helping make space for US barrels, traders said. “It seems an armada of crude is coming in in February and March from the US,” a source said.
Changes in marine fuel sulfur limits will put temporary upward pressure on diesel margins – The January 2019 Short-Term Energy Outlook (STEO), released at noon today, for the first time includes analysis of the effect that upcoming changes to marine fuel sulfur specifications will have on crude oil and petroleum product markets. Beginning January 1, 2020, the International Maritime Organization’s (IMO) new regulations limit the sulfur content in marine fuels used by ocean-going vessels to 0.5% by volume, a reduction from the previous limit of 3.5%. The change in fuel specification is expected to put upward pressure on diesel margins and modest upward pressure on crude oil prices in late 2019 and early 2020. EIA’s analysis indicates that the price effects that result from implementing this new standard will be most acute in 2020 and will diminish over time. Residual oil – the long-chain hydrocarbons remaining after lighter and shorter hydrocarbons such as gasoline and diesel have been separated from crude oil – currently comprises the largest component of marine fuels used by large ocean-going vessels, also known as bunker fuel. Marine vessels account for about 4% of global oil demand. Removing sulfur from residual oils or upgrading them to more valuable lighter products such as diesel and gasoline can be an expensive and capital-intensive process. Refineries have two options with regard to residual oils: invest in more downstream units to upgrade residual oils into more valuable products or process lighter and sweeter crude oils in order to minimize the production of residual oils and the sulfur content therein. EIA forecasts that the implementation of the new IMO fuel specification will widen discounts between light-sweet crude oil and heavy-sour crude oil, while also widening the price spreads between high- and low-sulfur petroleum products. In the January STEO forecast, Brent crude oil spot prices increase from an average of $61 per barrel (b) in 2019 to $65/b in 2020 with about $2.50/b of this increase being attributable to higher demand for light-sweet crude oils priced off of Brent. The expected increased premium on low sulfur fuels will likely mean higher diesel fuel refining margins, which EIA forecasts will increase from an average of 43 cents per gallon (gal) in 2018 to 48 cents/gal in 2019 and 65 cents/gal in 2020. Motor gasoline margins averaged 28 cents/gal in 2018 and are expected to increase slightly to an average of 29 cents/gal in 2019 and 33 cents/gal in 2020.
The Shale Oil Revolution Actually Reflects A Nation In Decline – Chris Martenson – Here in the opening month of 2019, as the US consumes itself with hot debate over a border wall, far more important topics are being ignored completely.Take US energy policy. In the US press and political circles, there’s nothing but crickets sounding when it comes to serious analysis or any sort of sustainable long-term plan.Once you understand the role of energy in everything, you can begin to appreciate why there’s simply nothing more important to get right.Energy is at the root of everything. If you have sufficient energy, anything is possible. But without it, everything grinds to a halt.For several decades now the US has been getting its energy policy very badly wrong. It’s so short-sighted, and rely so heavily on techno-optimism, that it barely deserves to be called a ‘policy’ at all. Which is why we predict that in the not-too-distant future, this failure to plan will attack like a hungry wolfpack to bite down hard on the US economy’s hamstrings and drag it to the ground. America’s energy policy blunders are nowhere more obvious than in the shale oil space, where it’s finally dawning on folks that these wells are going to produce a lot less than advertised.Vindicating our own reports — which drew from the excellent work of Art Berman, David Hughes and Enno Peters’ excellent website — the WSJ finally ran the numbers and discovered that shale wells are not producing nearly as much oil as the operators had claimed they were going to produce:Fracking’s Secret Problem – Oil Wells Aren’t Producing as Much as Forecast: Thousands of shale wells drilled in the last five years are pumping less oil and gas than their owners forecast to investors, raising questions about the strength and profitability of the fracking boom that turned the U.S. into an oil superpower.(Source) The main conclusion of this analysis is that US shale producers have overstated their well output by 10% collectively. And as much as 50% for certain individual companies. These numbers are easy to collect and analyze. While it’s a great thing to finally have the WSJ show up here, many years later than the independent analysts cited above, they still didn’t get close to the actual truth. In actuality, the shale plays are going to produce roughly half of what is currently claimed by shale operators. Instead of a -10% collective hit to production, we should be ready for something closer to -50%. Not only does that “raise questions” about the role of the U.S. as an oil superpower, it ought to raise alarm bells about its entire energy strategy.
Trump administration expands oil drilling despite shutdown – Three weeks into the longest US government shutdown in history, many important government services have been paused – but the Trump administration has continued efforts to expand oil drilling. Despite the shutdown directive, which has seen national park staff furloughed and the parks suffering from neglect, the interior department has continued processing oil drilling permits and applications. It has also moved forward with a controversial plan to increase drilling in the Arctic National Wildlife Refuge and the National Petroleum Reserve-Alaska (NPR-A). According to a “contingency plan” for an interior department agency, the Bureau of Land Management, approved last year, employees exempt from furloughs include those “working on selected energy, minerals and other associated permit activities for which the bureau charges a processing fee”.As a result, workers in New Mexico and Wyoming have continued to process oil and gas drilling applications.In Alaska, the Trump administration is rolling out a contentious plan to overwrite Obama-era protections and expand the oil and gas leasing in two controversial areas, the wildlife refuge and the NPR-A. Since the shutdown began, the interior department moved forward with previously scheduled public meetings to educate stakeholders and provide opportunities for comment and discussion. Conversely, the same type of meetings scheduled by the department for an 800-megawatt wind farm project being built off the coast of Massachusetts, were canceled. Oversight officials have begun to investigate the agency. “Asking people to comment on two major development processes in the Arctic with huge potential environmental and human consequences without anyone in the agency able to answer questions defeats the purpose of the public participation process,” chairman of the House Committee on Natural Resources, Raúl M Grijalva wrote in a letter to the acting secretary of the interior, David Benhardt on 7 January. He added that the move gave “the strong impression that BLM is simply trying to check the boxes and end the comment periods as soon as possible, not engage in a meaningful dialogue with impacted communities or stakeholders”.
Alaska regulators review BP wells after oil, gas leak – State oil and gas regulators are reviewing the mechanical integrity of BP wells in northern Alaska after a well released gas and a small amount of oil in a manner that appears similar to a 2017 leak, officials said. The leak at the well on the North Slope began Dec. 6 and was stopped after two full days, BP in Alaska spokeswoman Megan Baldino told the Anchorage Daily News. “BP immediately reported the incident in accordance with state and federal laws,” Baldino said. No one was injured, and BP is investigating the spill, Baldino said. The spilled oil was confined to the immediate well-house area and did not impact tundra, she said. The well apparently rose suddenly, or “jacked up,” said Tom DeRuyter, on-scene coordinator for the state Department of Environmental Conservation. Equipment on top of the wellhead hit the top of the well house, damaging a valve seal and causing the leak, he said. The oil and gas release last month appears to be a “failure event” similar to the uncontrolled release of well fluids in 2017, said Hollis French, chair of the Alaska Oil and Gas Conservation Commission, in a letter to Janet Weiss, head of BP in Alaska. In April 2017, a wellhead and valve assembly jacked up, striking the roof of the well house and causing an oil and gas release, DeRuyter said.
Alaska officials probing BP oil, gas wells at Prudhoe Bay after spill (Reuters) – Regulators in the U.S. state of Alaska will investigate all of the oil and natural gas wells operated by BP Plc at its Prudhoe Bay oil field after the release of a small amount of crude oil and gas from a well that had earlier been shut. The Alaska Oil and Gas Conservation Commission (AOGCC) has scheduled a Feb. 7 hearing “to assess the mechanical integrity of Prudhoe Bay wells operated by BP Exploration (Alaska), Inc.,” the agency said in a notice issued on Friday. Last month’s leak occurred at one of 14 wells that BP had shut in 2017 following a much bigger release oil and gas then. The most recent failure, detected on Dec. 7, released natural gas and about two gallons of crude oil, said Megan Baldino, spokeswoman for BP Exploration (Alaska) Inc. The gas release was brought under control two days later, she said. There was no oil released to the tundra and no one was injured, she said. There are 1,780 Prudhoe Bay wells, said Baldino, adding that the company is cooperating with the AOGCC’s investigation. “BP is investigating the incident to determine the cause. We are cooperating with AOGCC’s request for more information,” she said in an email on Monday. The earlier failure, in April 2017, caused crude oil to spray over a roughly 1 acre (0.4 hectare) area and caused natural gas to vent for days before it was brought under control. That well failure was linked to permafrost thaw. The normally frozen soil thawed, triggering movement that pushed the well up 3 to 4 feet (1.2 meters), breaking a pressure gauge that previously regulated the site, according to regulators. That sparked a North Slope-wide well review ordered by the AOGCC. In the end, BP identified and shut the 14 wells that because of an outdated and flawed design. In the aftermath of that incident, AOGCC officials concluded that the permafrost thaw was the result of the wells’ design flaw, not to climate change.
Snow removal equipment strikes pipe, causes spill in village (AP) – A heavy equipment operator plowing snow in a Yukon River village struck a fuel pipe that spilled diesel. The Fairbanks Daily News-Miner reports an estimated 3,000 gallons (11,356 liters) of diesel hit the ground in the village of Beaver. The spill is about the volume of 10 pickup truck bed tanks. The Alaska Department of Environmental Conservation says the village drinking water well and the Yukon River are about 600 feet (183 meters) from the spill area. The spill was discovered Tuesday at the Beaver Cruikshank School tank farm, a fuel oil storage facility. The Yukon Flats School District is listed as the party responsible for the spill. State environmental staff made plans to travel to the site Friday. Beaver is 110 miles (177 kilometers) north of Fairbanks.
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