US oil, products exports rising again as international markets command premium prices

after slipping a bit on Monday, oil prices moved steadily higher the rest of the week and approached a two and a half year high in closing up for the first time in four weeks....after initially trading as high as $57.78 a barrel on Monday, US light sweet crude for January delivery fell 14 cents for the day to end at $57.16 a barrel, as the EIA forecast that US crude production from shale would grow by 94,000 barrels a day during January, negating upward price pressure from the North Sea pipeline outage and a Nigerian oil worker's strike that drove international oil prices 18 cents higher...with international prices up 59 cents on Tuesday on the cutoff of North Sea supplies, US oil prices also rose, with the expiring January WTI contract closing 30 cents higher at $57.46 a barrel on bullish overseas news and expectations that US crude stockpiles data would show a fourth consecutive large weekly drawdown of US crude supplies...now trading oil contracts for February, which had closed Tuesday up 34 cents to $57.56 a barrel, that front month US crude price rose 53 cents to close at $58.09 a barrel on Wednesday, after the EIA data indicated an even larger-than-expected drop in US crude oil inventories...U.S. crude futures for February then rose for a third straight day on Thursday to settle up 27 cents at $58.36 a barrel, their second highest level of the year, on a follow-thru on the previous day's news of falling crude inventories...US crude prices then tacked on another 11 cents in thin pre-holiday trading on Friday, on a promise from Russian Energy Minister Alexander Novak that OPEC and Russia would exit their output cuts smoothly to avoid creating any new oil surplus, closing the week with a 2% gain at $58.47 a barrel, the highest weekly close since November 24th and the second highest close since June 22nd, 2015...

at the same time, international oil prices, as represented by trading in February contracts for North Sea Brent crude, were up every day during the past week, rising over $2 or 3.2% during the week to close to $65.25 a barrel, its highest price in more than two years...that means the premium of international oil prices over US prices is again approaching 12%, a premium that encouraged weeks of record high US oil exports just two months ago...in like manner, premiums for LNG in Asia and Europe saw a record spread over the benchmark price for US natural gas as set at the Henry Hub in Louisiana this week...with the price of LNG delivered to Japan, Korea and Malaysia averaging $10.85 per mmBTU early this week, LNG delivered to northeast Asia was $8.11 per mmBTU higher than the US price, while the UK's natural gas price climbed to as high as $8.83 per mmBTU over the US price...with US natural gas for January delivery hitting a cycle low of $2.598 per mmBTU on Thursday before closing the week at  $2.667 per mmBTU, US natural gas suppliers could be in a position to triple what they get from domestic natural gas customers, even after paying for liquefaction and transportation costs, if they could export larger quantities of that gas today...with the weekly Natural Gas Storage Report from the EIA indicating that US natural gas supplies are now 5% below their level of the same week of a year ago, our domestic stocks are not yet really threatened, but that will certainly be something to watch as the wave of new US LNG export capacity additions starts to come online in the 2nd half of next year..

The Latest US Oil Data from the EIA

this week's US oil data from the US Energy Information Administration, covering details for the week ending December 15th, showed that our oil exports jumped back to near record levels while our refineries ran at an above normal pace for this time of year, which meant we again had to pull quite a bit of oil out of storage to meet those needs...our imports of crude oil rose by an average of 471,000 barrels per day to an average of 7,834,000 barrels per day during the week, while our exports of crude oil rose by an average of 772,000 barrels per day to average 1,858,000 barrels per day, which meant that our effective trade in oil worked out to a net import average of 5,976,000 barrels of per day during the week, 301,000 barrels per day less than the net imports of the prior week...at the same time, field production of crude oil from US wells rose by 9,000 barrels per day to another record high of 9,789,000 barrels per day, which means that our daily supply of oil from our net imports and from wells totaled an average of 15,765,000 barrels per day during the reporting week...  

during the same week, US oil refineries were using 17,063,000 barrels of crude per day, 111,000 barrels per day more than they used during the prior week, while at the same time 873,000 barrels of oil per day were being withdrawn from oil storage facilities in the US....hence, this week's crude oil figures from the EIA seem to indicate that our total supply of oil from net imports, from oilfield production, and from storage was 425,000 fewer barrels per day than what refineries reported they used during the week...to account for that disparity, the EIA needed to insert a (+425,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the data for the supply of oil and the consumption of it balance out, a metric that is labeled in their footnotes as "unaccounted for crude oil"...

further details from the weekly Petroleum Status Report (pdf) show that the 4 week average of our oil imports slipped to an average of 7,432,000 barrels per day, 6.2% less than the 7,921,000 barrels per day average imported over the same four-week period last year....the 873,000 barrel per day decrease in our total crude inventories came about on a 928,000 barrel per day withdrawal from our commercial stocks of crude oil, which was slightly offset by a 55,000 barrel per day addition of oil to our Strategic Petroleum Reserve, likely a return of oil that was borrowed from the Reserve during the post Hurricane Harvey emergency...this week's 9,000 barrel per day increase in our crude oil production came by way of a 15,000 barrel per day increase in output from wells in the lower 48 states, which was partially offset by a 6,000 barrels per day decrease in output from Alaska....the 9,789,000 barrels of crude per day that were produced by US wells during the week ending December 15th was yet another new record high for US output, 11.6% more than the 8,770,000 barrels per day we were producing at the end of 2016, and up 16.1% from the recent output nadir of 8,428,000 barrels per day produced during the last week of June 2016...

US oil refineries were operating at 94.1% of their capacity in using those 17,063,000 barrels of crude per day, up from 93.4% of capacity the prior week, and the highest capacity utilization on record for the 2nd week of December....the 17,063,000 barrels of oil that were refined this week were 3.7% less than the record 17,725,000 barrels per day that were being refined at the end of August, but 2.4% more than the 16,658,000 barrels of crude per day that were being processed during week ending December 16th, 2016, when refineries were operating at 91.5% of capacity, and 10.4% above the 10-year seasonal average for this time of the year... 

even with the increase in the amount of oil being refined, gasoline output from our refineries was slightly lower, as it decreased by 64,000 barrels per day to 10,065,000 barrels per day during the week ending December 15th, after rising last week on slower refining....that decrease meant our gasoline production was 0.8% lower than the 10,150,000 barrels of gasoline that were being produced daily during the week ending December 16th of last year...at the same time, our  refineries' production of distillate fuels (diesel fuel and heat oil) fell by 41,000 barrels per day to 5,206,000 barrels per day....however, that was still 1.6% more than the 5,122,000 barrels per day of distillates that were being produced during the the same week a year ago....     

with the relatively small decrease in our gasoline production, our gasoline inventories at the end of the week rose by 1,237,000 barrels to 227,783,000 barrels by December 15th, their sixth increase in a row...that was despite an increase of 335,000 barrels to 9,426,000 barrels per day in our domestic consumption of gasoline, while our exports of gasoline also rose by 73,000 barrels per day to 804,000 barrels per day, and while our imports of gasoline inched up by 4,000 barrels per day to 487,000 barrels per day....however, with significant gasoline supply withdrawals in 15 out of the prior 21 weeks, our gasoline inventories are still down by 6.0% from their pre-summer high of 242,444,000 barrels, and down fractionally from last December 16th's level of 228,736,000 barrels, even as they are roughly 4.1% above the 10 year average of gasoline supplies for this time of the year...    

meanwhile, with the small drop in our distillates production, our supplies of distillate fuels rose by 769,000 barrels to 128,845,000 barrels over the week ending December 15th, in just the fifth increase in distillates supply in sixteen weeks...that was as the amount of distillates supplied to US markets, a proxy for our domestic consumption, fell by 454,000 barrels per day to 3,926,000 barrels per day, even as our exports of distillates rose by 338,000 barrels per day to 1,550,000 barrels per day, while our imports of distillates rose by 231,000 barrels per day to a 33 week high of 380,000 barrels per day...even after this week’s increase, our distillate inventories were still 16.1% lower at the end of the week than the 153,515,000 barrels that we had stored on December 16th, 2016, and roughly 5.4% lower than the 10 year average of distillates stocks at this time of the year…

finally, with the week's increase in our oil exports and the increase in our refining, our commercial crude oil inventories fell for the 30th time in the past 37 weeks, decreasing by 6,495,000 barrels, from 442,986,000 barrels on December 8th to a 26 month low of 436,491,000 barrels on December 15th....while our oil inventories as of December 15th were thus 10.1% below the 485,449,000 barrels of oil we had stored on December 16th of 2016, and 3.5% lower than the 452,477,000 barrels of oil that we had in storage on December 18th of 2015, they were still 23.0% greater than the 354,733,000 barrels of oil we had in storage on December 19th of 2014, when the buildup to an oil glut in the US was just getting started... 

This Week's Rig Count

US drilling activity increased for the sixth time in seven weeks but for just the 9th time out of the last 21 weeks during the week ending December 22nd, but just barely...Baker Hughes reported that the total count of active rotary rigs running in the US increased by 1 rig to 931 rigs in the week ending on Friday, which was also 278 more rigs than the 653 rigs that were deployed as of the December 23rd report in 2016, while it was still less than half of the recent high of 1929 drilling rigs that were in use on November 21st of 2014....

the number of rigs drilling for oil was unchanged at 747 rigs this week, which was still 224 more oil rigs that were running a year ago, while the week's oil rig count remained far below the recent high of 1609 rigs that were drilling for oil on October 10, 2014...at the same time, the number of drilling rigs targeting natural gas formations rose by 1 rig to 184 rigs this week, which was still only 55 more gas rigs than the 129 natural gas rigs that were drilling a year ago, and way down from the recent high of 1,606 natural gas rigs that were deployed on August 29th, 2008...

drilling activity in the Gulf of Mexico was unchanged at 19 rigs this week, which was down from the 24 rigs that were drilling from platforms in the Gulf of Mexico a year ago...with no other offshore drilling elsewhere, the national offshore count was also at 19 rigs this week, but a year ago there was also a rig drilling offshore from Alaska, for a national total of 25 offshore rigs...

this week's count of active horizontal drilling rigs was unchanged at 801 horizontal rigs this week, but it was still up by 275 rigs from the 526 horizontal rigs that were in use in the US on December 23rd of last year, but down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014...meanwhile, the vertical rig count was up by 4 rigs to 64 vertical rigs this week, but that was still down from the 69 vertical rigs that were working during the same week last year....on the other hand, the directional rig count was down by 3 rigs to 66 rigs this week, which was still up from the 58 directional rigs that were deployed on December 23rd of 2016...

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 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 December 22nd, the second column shows the change in the number of working rigs between last week's count (December 15th) and this week's (December 22nd) count, the third column shows last week's December 15th active rig count, the 4th column shows the change between the number of rigs running on Friday and the equivalent Friday 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 for the 23rd of December, 2016...              

there appears to be a few unexplained disparities between the state rig counts from those in the major basins this week....first, note that the central Oklahoma Cana Woodford saw a 4 rig increase, despite the state count being down by a single rig...that would suggest that a net of 4 rigs drilling conventional wells were pulled out of the state, since the only other basin in Oklahoma to show a change was the Mississippian on the Kansas border....then, noting the 4 rig increase in New Mexico, it's possible 3 of those were in the Permian, since the west Texas districts that include the Permian in that state were down by 2 rigs, while drilling in the Dallas area Barnett shale increased by two rigs...also note that all the basin count changes involve oil rigs; the single natural gas rig addition was in an "other" unnamed basin...and in addition to the changes in the major producing states shown above, Alabama also added a rig this week and now has two; that's also the same number of rigs they had active as of December 23rd 2016...

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Fracking opponents in Brookfield seek longer comment period, public hearing - Opponents of proposed plans to install additional fracking-waste injection wells in Trumbull County have sent a letter to the Ohio Department of Natural Resources, Division of Oil and Gas, seeking a 60-day extension of the time for submission of public comments. They urge the deadline be moved from Dec. 25 to Feb. 25, 2018. To have a deadline for comment on Christmas day is unreasonable, the letter said. The letter, dated Dec. 11, was sent via electronic mail to James Zehringer, director of ODNR, and Richard Simmer, chief of the Division of Oil and Gas, by several residents of Brookfield and the Northeastern Ohio region, who also seek a public hearing on the matter. The letter says that additional fracking-waste injection wells in the region of Trumbull County “will greatly exacerbate the potential environmental downside of drilling waste deposal wells, in the form of groundwater pollution and exhaustion of available solid waste disposal facilities.” Construction of a fracking waste injection site in Brookfield began on about Nov. 13, 2017, but it’s not a “done deal,” say opponents, who also say that additional ODNR permits are required for the company, Highland Field Services, to fully operate an injection fracking waste well – much of it to come from out of state if the wells are eventually approved.

Ohio injection well opponents seek longer comment period, public hearing - Opponents of proposed plans to install additional fracking-waste injection wells in Trumbull County, Ohio, have sent a letter to the Ohio Department of Natural Resources’ (ODNR) Division of Oil and Gas, seeking a 60-day extension for public comments.  They urge the deadline be moved from Dec. 25, to Feb. 25, 2018, the Youngstown Vindicator newspaper reports. To have a deadline for comment on Christmas Day is unreasonable, the letter said. The letter, dated Dec. 11, was sent to James Zehringer, director of ODNR, and Richard Simmer, chief of the Division of Oil and Gas, by several residents of Brookfield and northeastern Ohio, who also seek a public hearing on the matter, the Vindicator reported. The letter states additional fracking-waste injection wells in the region of Trumbull County “will greatly exacerbate the potential environmental downside of drilling waste deposal wells, in the form of groundwater pollution and exhaustion of available solid waste disposal facilities,” Kallanish Energy learns. Construction of a waste injection site in Brookfield began in mid-November, but it’s not a “done deal,” say opponents, who also told the Vindicator additional ODNR permits are required for the company, Highland Field Services, to fully operate an injection fracking waste well – much of the waste to come from out of state if the wells are eventually approved.

Wayne forest oil-gas auction nets $944K - Athens NEWS -- Around 50 environmental activists hailing from multiple Ohio counties rallied at the U.S. Forest Service’s Athens District Headquarters Thursday afternoon to protest the scheduled auction of oil-and-gas leases on the Wayne National Forest on the same day.  The online auction took place in spite of the protest. According to a news release issued by the BLM on Friday, the agency’s Eastern States quarterly oil-and-gas lease sale resulted in competitive bids for more than 1,184 available acres in Ohio and Louisiana, bringing in around $1.015 million. Of those acres, 350 were offered in the Wayne’s Marietta Unit, all in Monroe County north of Marietta.The Marietta Unit sale netted $944,000 of the total, which according to the BLM will be split between the state of Ohio and the federal government. Much of the Ohio portion ends up going to counties under the Payment in Lieu of Taxes program that compensates counties that lose property tax revenue as a result of federal land ownership within the county. The money is supposed to be used for local schools and roads.A big part of those payments in counties with substantial oil-and-gas drilling activities comes from revenue derived from mineral extraction, including oil and gas. Opponents decry the environmental degradation resulting from oil-and-gas drilling/fracking, storage and transmission on public lands, including pollution to streams and rivers, wildlife and vegetation, among other adverse effects. They also cite the negative impacts that fossil-fuel extraction and burning have on climate change.

Agreement reached on West Virginia fracking landfill | Columbus Ledger-Enquirer: Environmentalists have reached an agreement with Antero Resources to monitor for radioactivity and bromide around its landfill in northern West Virginia that takes the waste from recycled groundwater used in hydraulic fracturing for natural gas. It settles an appeal of by the West Virginia Rivers Coalition and West Virginia Highlands Conservancy of the permit for the landfill, which takes salt byproducts from Antero's adjacent wastewater recycling facility. Both are located on 447 acres (181 hectares) in Ritchie and Doddridge Counties. The groups say the permit allows discharging stormwater runoff and associated pollutants into tributaries of the Hughes River upstream within 5 miles (8 kilometers) of Harrisville's public water system intake.

Second court challenge filed over water quality certification for Mountain Valley Pipeline (Roanoke Times) A group of landowners, conservation groups and a member of the Virginia House of Delegates brought a court challenge Monday to a state board’s finding that a natural gas pipeline would pose no danger to the streams and creeks that lie in its path. The petition for review, filed in the 4th U.S. Circuit Court of Appeals, marks the second time the State Water Control Board has been sued over its Dec. 7 decision to issue a water quality certification for the Mountain Valley Pipeline. Del. Sam Rasoul, D-Roanoke, is listed as the first of 16 petitioners who contend the board lacked adequate information on which to find a “reasonable assurance” that the 303-mile long buried pipeline would not contaminate the waters of Western Virginia. Like a similar challenge filed Dec. 8 by the Sierra Club and three other environmental organizations, the brief petition does not detail the grounds on which a challenge will be based. But in a statement announcing the court filing, the petitioners pointed to the different way in which the water board handled a permit sought by Mountain Valley and a second one that was granted the following week for the Atlantic Coast Pipeline, a similar project in Central Virginia. Although the water board gave approval for the Atlantic Coast Pipeline, which is backed by Dominion Energy, it took the unusual step of delaying the effective date until several environmental impact reports are completed. No such condition was made for the Mountain Valley Pipeline. “It makes no sense,” said Mara Robbins, a n organizer with the Blue Ridge Environmental Defense League, one of the petitioners in the second court challenge. “They delayed the ACP permitting until erosion and sedimentation reports are complete. Many of the issues presented were identical. Yet the permits for the ACP were delayed and the ones for the MVP were not? They need to go back to the drawing board and get this right.” 

Atlantic Coast Pipeline wants to start cutting down trees - Though it still lacks several key approvals, the Dominion Energy-led Atlantic Coast Pipeline project has asked federal regulators to allow workers to begin cutting down trees along some portions of the 600-mile route in West Virginia, Virginia and North Carolina. Dominion made the request with the Federal Energy Regulatory Commission last week. Opponents are urging the commission to reject it, noting that permits for the project are missing or unfinished, as are effective water quality certifications from Virginia and North Carolina and stormwater plan approval from West Virginia. Requests for reconsideration and stays by FERC are likewise still pending, among other objections raised in a filing submitted by the Southern Environmental Law Center in Charlottesville on behalf of more than a dozen conservation groups. “At this point, it is unknown whether Atlantic will obtain all of the necessary approval and permits to move forward with its project,” the document says. “The commission must reject Atlantic’s attempts to cut corners and pre-empt state authority by denying the company’s premature request.” Dominion says the workers will stay away from wetlands and waterways, will refrain from using heavy equipment, and will not remove stumps or roots that could lead to soil erosion. The cut timber will stay onsite until all other approvals have been obtained. And the chainsaw-wielding contractors will only cut trees on property that the company has secured access to via easement agreements with owners, said Dominion, which also has begun eminent domain proceedings against some landowners. “We want to get as much of this work done as possible within the federal tree-felling window in order to protect migratory birds or bats or other sensitive species,” said Aaron Ruby, a Dominion spokesman. “FERC has a well-established process for authorizing this activity and we’re following the process.” 

Judge Sides with Big Oil in Maine Pipeline Case - In a case that has national ramifications, a federal judge has ruled against the city of South Portland, Maine, in its latest effort to stop the coastal town from becoming a destination for Canadian tar sands oil.  The case centers around an existing pipeline owned by oil companies ExxonMobil, Shell, and Suncor. The Portland Montreal Pipeline currently moves refined oil from South Portland to Montreal, Canada. However, since Canada is awash in oil and currently exports over three million barrels a day to the U.S., there is very little demand there for U.S. oil. As a result, the pipeline is not operating close to full capacity. The oil companies that own the Portland Pipe Line Corporation (PPLC) now want to reverse the pipeline’s direction to bring Canadian tar sands oil to South Portland, where it would be exported. In 2014, the city of South Portland passed the Clear Skies Ordinance, banning the export of crude oil from the city. This ordinance was designed to protect local air quality because the plans to bring tar sands oil to South Portland require building two smokestacks on the waterfront,  located adjacent to residential areas. These pollution control towers would burn off the toxic volatile components of the tar sands oil mixture.  In 2013, prior to the city passing the Clear Skies Ordinance, residents of South Portland gathered the 4,000 signatures required to place a measure on the ballot, which would allow voters to decide whether or not they wanted to allow tar sands oil in their community. That’s when the oil industry started paying attention. The American Petroleum Institute ended up spending over $750,000 to help defeat the ballot measure, which lost by fewer than 200 votes.

Gas-fired power generation in New England this winter and next - This winter will be the last go-round for ISO New England’s Winter Reliability Program, under which the electric-grid operator in the natural gas pipeline-challenged region provides financial incentives to dual-fuel power plants if they stockpile fuel oil or LNG as a backup fuel. This coming spring, a long-planned “pay-for-performance” regime will go into effect, and gas-fired generators that can’t meet their commitments to provide power during high-demand periods — such as the polar vortex cold snaps that hit the Northeast in early 2014 — will pay potentially significant penalties. Today, we discuss the pitfalls that the pipeline capacity-challenged region may encounter as its power sector becomes increasingly gas-dependent. The NATGAS Permian Report is a weekly natural gas fundamentals analysis focusing entirely on the key market drivers within the Permian basin. The report contains details and forecasts around natural gas production, demand, and pricing. It offers a summary of pipeline outflows and capacities from the Permian to neighboring regions, outlining the key shifts in flows to the West, MidCon, and Texas intrastate markets. Bostonians and other New Englanders pride themselves on their winter hardiness. They scoff at doomsday nor’easter forecasts from the Weather Channel. They think nothing of putting on five layers of L.L. Bean clothing to watch Tom Brady and the Patriots play in subzero temperatures at Gillette Stadium. That New England hardiness and inventiveness may come in handy. As we’ve said in a number of blogs [I’m (Not) Shipping Up to Boston and Don’t Give Up On Us, among others], in the past few years the region’s power sector has been shutting down coal and oil-fired generation units and nuclear plants, and building new natural gas-fired combined-cycle and peaking units to replace their capacity. At the same time, New Englanders have been among the fiercest opponents of new gas pipelines and gas-pipeline expansions that would enable considerably more gas from the nearby Marcellus and Utica production regions in Pennsylvania, West Virginia and Ohio to flow into Connecticut, Rhode Island and Massachusetts in particular.

New US FERC chairman promises 'fresh look' at gas pipeline approval policies -- Under increased scrutiny and heightened environmental opposition, the US Federal Energy Regulatory Commission will take a comprehensive "fresh look" at its policies for reviewing and approving natural gas pipeline projects, the new head of the agency said Thursday. Chairman Kevin McIntyre, who took his seat at the commission December 7, announced at the commission's open meeting that it was time to take a look at FERC's longstanding policy statement on the issuance of pipeline certificate orders.The policy, which has been in place since 1999, is more than ripe for review, given the tremendous changes to the natural gas industry since the policy was instituted, all of the commissioners on the panel agreed."Without prejudging anything and without intending to forecast a policy direction, ... it's a matter we believe of good governance to take a fresh look at this area and to give all stakeholders and the public an opportunity to weigh in on" whether changes to the existing policy are warranted, McIntyre said.The format and scope of the review have yet to be determined, but could take the form of a notice of inquiry, a call for a technical conference or a number of other formats available to the commission. "I guarantee, whatever it is, it will be open and transparent and thorough, and it will invite the views of all stakeholders to ensure we are doing everything we can to accurately and efficiently assess pipeline applications that we receive and process," McIntyre said.

Henry Hub spread to Asia, Europe at record high - The price spreads between Henry Hub and benchmark gas markets in Asia and Europe are at three-year highs in December and could continue to widen in the coming weeks. The netback to Henry Hub from Platts JKM, the benchmark price for spot LNG delivered to northeast Asia, was assessed Monday at $8.11/MMBtu. The netback from the UK's NBP market climbed as high as $8.83/MMBtu in mid-December, although that netback has narrowed in recent days. Still, those spreads have offered offtakers of US LNG the best margin yet for export profits. Including transportation costs, liquefaction losses and shipping outlays, Platts Analytics estimates the arbitrage profit on those netbacks at roughly $4.25/MMBtu to Asia and $3.65/MMBtu to Europe. Attractive export margins for US LNG come as a combination of factors have conspired to lift gas prices in Asia, Europe, the Middle East and India. In northeast Asia, strong gas demand in China this winter has even seen the country's independent buyers bidding for cargoes in an effort to capture profits with downstream sales into the domestic gas market. In Japan and South Korea, a recent influx of colder temperatures is also helping to keeping gas demand and LNG prices elevated in the region. The JKM was assessed Tuesday up 5 cents to $10.85/MMBtu for front-month, February-delivered cargoes, S&P Global Platts data shows. In Europe too, gas prices are sharply higher this winter, owing to higher demand for gas-fired generation. More recently, prices have seen additional support from colder temperatures and a series of supply disruptions caused by an Austrian gas hub explosion and temporary production outages in the North Sea and in Norway.

USGC crude exports pick up as LOOP Sour-Dubai spread widens -- Tumbling differentials for US Gulf Coast medium sour crudes as part of an end-of-year selloff are opening arbitrage opportunities for those grades to move across the Atlantic Ocean or head east, S&P Global Platts data show. The Platts LOOP Sour-Dubai spread, used to measure the arbitrage for US Gulf Coast sour grades to Asia, has gradually widened in recent weeks and ended last week at its widest value since mid- to late-November. On Friday, the 10-day moving average spread was $1.63/b, with LOOP Sour less than Dubai. The spread has widened six of the past nine trading days since reaching of 82 cents/b on December 5, Platts data showed. Platts data suggests the cost to move crude from the USGC to the West Coast of India is about $2.30/b compared with $2.60/b to Singapore and $3/b to China. Recent Platts fixture reports show a number of companies fixing or looking to fix crude tankers out of the Gulf Coast. Last week, Shell, BP, Unipec, Petrochina and Swiss Oil fixed eight tankers with a combined 1.02 million mt of capacity. By comparison, five ex-USGC tankers with a combined 620,000 mt of capacity were heard fixed in over a week one month ago, Platts data shows. Unipec had the largest fixture, fixing a to-be-named VLCC at an as-yet unknown rate to move crude to Singapore. Platts assessed the dirty VLCC Caribbean-Singapore route at $3.9 million Friday. 

The last leg of the Dakota Access Pipeline is nearing construction   - Pipeline operator Energy Transfer Partners received two major permits this week—the most recent on Thursday—for its Bayou Bridge Pipeline in Louisiana. This 163-mile long crude oil pipeline, owned in part by Phillips 66, carries the same oil that runs through Energy Transfer Partners’ more notorious Dakota Access Pipeline. Unhappy opponents of the project are gearing up for nonviolent direct action. “The Houma Nation and all those south of the proposed Bayou Bridge pipeline route deserve the right to clean water for drinking, for bathing, for fishing, for life.” The Bayou Bridge Pipeline brings the crude oil from North Dakota’s Bakken Formation to an oil export terminal hub in St. James Parish, Louisiana. If the pipeline is built, roughly 480,000 barrels of oil are expected to travel through it a day. Pipeline critics are especially worried about an oil spill on nearby wetlands.Now that the Louisiana Department of Environmental Quality issued the water quality certification Tuesday and the Army Corps of Engineers approved the pipeline’s right of way Thursday, the pipeline’s construction is almost certain to begin—and soon. It’s already secured the state’s coastal use permit and approval of the St. James Parish Council. Just a couple hurdles remain in the pipeline’s way.“This moves us to the final step of the permitting process, which is a permit from the Atchafalaya Levee District and approval from the Coastal Protection Restoration Authority, both of which we anticipate receiving shortly,” pipeline reps wrote on a Facebook post Thursday.  An indigenous-led camp launched in June to begin mobilizations against the project. So far, they’ve mostly done prayerful walks and collaborative art projects. This recent—and unsurprising—move now throws camp members into action-mode as they prepare for nonviolent direct action, and that includes civil disobedience.

U.S. Bank Quietly Joins $4B Deal With Dakota Access Owner After Declaring End to Oil and Gas Pipeline Loans -- At a shareholder meeting this past spring, U.S. Bank announced it would be the first large American bank to completely stop issuing loans for oil and gas pipeline construction projects. Environmental groups, indigenous activists and divestment advocates hailed U.S. Bank's announcement as a triumph. Yet that triumph—and the bank's commitment—seems less sure with the news that U.S. Bank has entered into a new $4 billion loan deal with the company behind the contentious Dakota Access pipeline (DAPL).  For months, the bank had been under fire for financing the Dakota Access pipeline by providing over a quarter billion dollars worth of funding to its builder, Energy Transfer Partners (ETP). Environmentalists famously dropped a banner calling on U.S. Bank to divest from DAPL at the New Years 2017 Minnesota Vikings and Chicago Bears football game. The language of the bank's new policy seemed blunt. "The company does not provide project financing for the construction of oil or natural gas pipelines," U.S. Bancorp, parent company of U.S. Bank, wrote in its April 2017 Environmental Responsibility Policy. Divestment advocates cheered. "We applaud this progressive decision from U.S. Bank," an Honor the Earth representative said in a statement, as the bank's new policy made headlines . Some advocates remained skeptical, however, pointing out that the line of credit extended to Energy Transfer Partners wouldn't be covered by that language, because it could be considered a loan for the company as a whole, not the more specific "project financing." And U.S. Bank's CEO told shareholders that his bank wouldn't end its existing Energy Transfer Partners deal, saying that instead it would "fulfill that contract and commitment." "We know there are always loopholes through which banks will try to pass off responsibility," Rachel Heaton of Mazaska Talks and a Muckleshoot Tribe member told Yes Magazine , "but we will continue to resist until these banks completely divest from all pipeline and fossil fuel corporations and incorporate the Free, Prior, and Informed Consent of Indigenous peoples into their corporate lending structures."

Trump halts funding for offshore drilling safety study | TheHill: The Trump administration has paused its funding for a major study meant to improve how regulators enforce offshore oil and natural gas drilling safety. The congressionally chartered National Academies of Sciences, Engineering and Medicine said Thursday that the Interior Department’s Bureau of Safety and Environmental Enforcement (BSEE) sent a stop-work order for the study earlier this month. The National Academies had already gathered a committee of researchers for the study and conducted a meeting on the matter in October.“The National Academies are grateful to the committee members for their service and disappointed that their important study has been stopped,” it said in a statement. BSEE told the National Academies that it would decide within 90 days whether to resume funding. BSEE requested the study in 2016 as part of an ongoing effort to implement lessons learned from the 2010 Deepwater Horizon disaster and oil spill in the Gulf of Mexico. BSEE spokesman Gregory Julian said the pause will allow the agency to evaluate whether the National Academies study is duplicating efforts already underway to improve its inspections. “As BSEE moves forward with implementing a risk-based inspection program to strengthen and improve its existing inspection program, the [National Academies] study was paused by BSEE to allow time to ensure that there are no duplicate efforts,” he said. 

Keane Group buying new fracking fleets - Houston's Keane Group said it is spending $115 million to order three new fracking fleets to prepare for a busy 2018, especially in West Texas' booming Permian Basin. The hydraulic fracturing company, said the new fleets will add about 150,000 hydraulic horsepower to give Keane about 1.3 million horsepower, including 800,000 dedicated to the Permian. Keane, which trades under the stock ticker "FRAC" on the New York Stock Exchange, focuses on well completion and pressure pumping services, especially the fracturing, or fracking, of underground shale rock to release oil and gas. "Supply-and-demand fundamentals for U.S. oil and gas well completions remain highly constructive for quality completions service providers," said Keane Chairman and CEO James Stewart. "Favorable conditions have continued to improve throughout the year, and robust 2018 capital budgets announced by producers in recent weeks have amplified and validated the growing demand for our services, which remains in excess of supply." Keane redeployed all of its idled fracking fleets this year after the end of a more than two-year bust in oil prices. Now, Keane is expanding its fleet to prepare for growing activity levels. Keane went public early this year after expanding in 2016 through the acquisition of Calgary-based Trican Well Services' pressure pumping business.

Tellurian plans US gas pipelines; seeks to boost Permian, Haynesville takeaway -- LNG developer Tellurian proposed Monday building two additional natural gas pipelines to move increasing output of shale supplies in the Permian and Haynesville shale plays to the US Gulf Coast and boosting the access to cheap feedgas for its planned Driftwood export terminal in southwest Louisiana. The announcement comes as the Houston-based company tries to convince investors and LNG buyers in Asia, Europe, the Middle East and Latin America that its liquefaction facility will be a low-cost, high-return option among the dozen or so terminals eyeing a startup early in the next decade. While none of the second wave of US projects has taken a positive final investment decision this year, Tellurian is aiming to prove commercial viability in 2018, at the same time as it will be soliciting shipper interest in its proposed 2 Bcf/d Permian Global Access Pipeline and 2 Bcf/d Haynesville Global Access Pipeline. The company's previously proposed 4 Bcf/d Driftwood Pipeline is proceeding through the regulatory process. Together, the three pipelines are projected to cost $7.3 billion. "The Tellurian Pipeline Network would serve the approximately 8 Bcf/d of incremental natural gas demand expected by 2025 in southwest Louisiana," CEO Meg Gentle said in a statement. While traditionally an oil play, the Permian in West Texas and southeastern New Mexico has been seeing a surge in associated gas being lifted, and producers are increasingly looking for takeaway options to move those supplies to the coast, where the resources are in high demand for both domestic use and exports.

Kinder Morgan to move ahead with $1.7 billion pipeline -  Houston's Kinder Morgan said Thursday it's ready to move forward with its $1.7 billion gas pipeline from West Texas to the Corpus Christi area after signing Apache Corp. as a major customer. The project, expected begin operation by October 2019, is meant to capitalize on the shale boom in West Texas' Permian Basin. While companies are primarily drilling for oil, a lot of associated natural gas also is produced from the shale rock - even more than initially projected. The goal is to transport the gas to hubs near Corpus Christi and Houston, where it can then be shipped to power plants for electricity generation, to liquefied natural gas export terminals, or to Mexico, which is buying more American natural gas for its power generation. The 500-mile project is 50 percent owned by Kinder Morgan. Two other pipeline companies, Targa Resources of Houston and DCP Midstream, a joint venture of Houston's Phillips 66 and Calgary-based Enbridge, each hold 25 percent stakes. Construction is expected to start in the first quarter of 2018. 

Nebraska regulators deny TransCanada request on Keystone XL route (Reuters) - Nebraska regulators on Tuesday denied TransCanada Corp’s request to amend its route application for the proposed Keystone XL pipeline through the U.S. state, a potential setback for the company as it seeks to head off legal challenges. The Nebraska Public Service Commission (PSC) issued an approval for the line in late November, removing what appeared to be the last big regulatory obstacle for the long-delayed project, which has been backed by U.S. President Donald Trump. But the commission’s approval was not for the route TransCanada had singled out in its application. Instead, the commission approved an alternative route that shifts it closer to an existing pipeline right-of-way down the eastern side of the state, a move opponents of the pipeline have said violates state statutes. TransCanada filed a motion last month with the commission seeking permission to retrospectively amend the route application, a move that a company official said was intended to prevent lawsuits that could delay the project. The commission on Tuesday voted 5-0 against the motion. TransCanada said in a statement that it would review the decision to determine next steps for Keystone XL, but added that it believed the project remained economically viable. “It is important to remember that this project has widespread support within the U.S. and Canadian federal governments, as well as state officials in Montana, South Dakota and Nebraska,” the company said.

Nebraska upholds Keystone XL approval, sparking likely court battle - Nebraska regulators on Tuesday upheld their decision to allow TransCanada to build the stalled 830,000 b/d Keystone XL crude pipeline, albeit on an alternative route. The state Public Service Commission order denied requests by TransCanada and pipeline opponents to reconsider the November 20 approval. TransCanada could not immediately be reached for comment. Lawyers for Nebraska landowners opposed to the project said Tuesday's denial represents "the absolutely worst decision possible for TransCanada and the best possible outcome for landowners and the protection of their property rights." "The PSC process is now over and the appeal process of the PSC decision can now begin and run all the way through the courts, with TransCanada's own denied motion for reconsideration foretelling its likelihood of success on appeal," the Domina Law Group said. TransCanada said earlier in December that the alternative route would not likely increase the estimated $6.3 billion project cost. Still, the company has yet to make a final investment decision. The PSC voted last month for the company's "mainline alternative" -- not the more direct route that TransCanada preferred. The approved route in eastern Nebraska heads east sooner toward the existing Keystone pipeline and parallels it for 96 miles. 

High levels of benzene released at Weld County oil and gas site -- Anadarko Petroleum has self-reported the release of high levels of a cancer-causing chemical at a tank battery site in Dacono near Weld County Roads 10 and 15. According to a report provided to COGCC, the state agency responsible for regulating the industry, the oil and gas operator discovered the contaminated ground water and soil while trying to dig up an old pump in early December. Anadarko had to remove 200 barrels of tainted ground water, and lab tests found benzene 900 times the amount allowed by the state. Benzene is a natural part of crude oil and gasoline, but is known to cause cancer. "It's hard to argue the fact that you have extremely high levels of benzene -- well what causes it, it's not farming wheat," Tom Eubanks said. Eubanks flies his remote-control model planes at an airstrip right next to the oil and gas site where the contaminated ground water was found. For several days, he said he watched crews haul out the toxic water and soil. "I saw a string of three dump trucks come in here and then haul dirt out and they made three trips in one day. And then the second day they were still hauling dirt out," Eubanks explained. According to the report, the operator also removed nearly 10,000 cubic feet of polluted soil -- enough to fill 383 hot tubs. "I think that doesn't surprise me one bit," Eubanks said. A spokeswoman for Anadarko said the company is in the process of removing a tank battery at the site and that's how they discovered the toxic ground water, something the operator and COGCC both said is not uncommon while doing this kind of work. The big question that remains is are the nearby water wells safe? 

Colorado's Extraction Oil & Gas to spend up to $840M drilling, fracking next year -Denver’s Extraction Oil & Gas Inc., which works solely in Colorado, says it expects to spend between $770 million and $840 million in capital expenditures in 2018.   Extraction’s Chairman and CEO Mark Erickson called the 2018 spending plan “modestly smaller” than this year’s plan, but said the company expects to grow its production 75 percent next year compared to this year.  For 2018, the company said it plans to drill up to 175 horizontal wells during the year that will have an average lateral length of 1.8 miles.   Outside of drilling and fracking on new and existing wells, Extraction said it expects to spend between $120 million and $150 million on other expenditures — and pay for those activities by selling assets considered non-strategic.   The company said it’s working on financing infrastructure projects related to its planned operations in Broomfield and Hawkeye, which is in Adams and Arapahoe counties.

North Dakota oil output jumped more than 78,000 b/d in October: state -  North Dakota oil production averaged nearly 1.19 million b/d in October, up more than 78,000 b/d from September and the highest average output since August 2015, bolstered by the OPEC supply cut agreement and global economic growth, the state Department of Mineral Resources reported Friday.October's average output was still roughly 42,000 b/d below the all-time monthly output record set in December 2014, but was the highest month-to-month  increase in state history, according to Lynn Helms, the state's top oil and gas regulator. Statewide natural gas production averaged more than 2.06 Bcf/d, up from 1.95 Bcf/d in September and a new all-time high, the state agency said. There were also an all-time high of 14,250 producing wells in North Dakota in October, up 51 from September, the agency said.

Residents report nosebleeds and headaches after new leak at Aliso Canyon natural gas facility - LA Times: Southern California Gas Co. late Monday reported a leak at the Aliso Canyon natural gas storage facility during a routine operation to pressurize equipment after maintenance. In a community alert, the company said the leak occurred about 4:55 p.m. and didn’t pose any health risks, though it did produce a noticeable odor.But Andrew Krowne, a Northridge resident who developed a cellphone application for those within 18 miles of the facility to report health issues, said 34 people reported symptoms including headaches, nosebleeds, and burning of the eyes and throat. The leak was shut off within about 50 minutes and residents were notified about 7:40 p.m., according to the utility’s alert. Article continues belowSince Krowne’s app became available in October, more than 150 users have reported 2,200 symptoms, he said. The facility is the site of the largest methane leak in U.S. history. Starting in 2015, a ruptured well spewed tens of thousands of tons of gas, forcing roughly 8,000 families in the northwest San Fernando Valley from their homes. Many complained of health issues that included cancer, nausea and nosebleeds. The blowout, which at its peak more than doubled the methane emissions of the entire Los Angeles Basin, took more than four months to plug. It sparked a political firestorm, with residents and elected officials demanding that the facility be shut down. “It has no business being around homes,” Krowne said. 

California Cities Are Suing Oil, Gas And Coal Companies Over Climate Change — The city of Santa Cruz and Santa Cruz County announced Wednesday the filing of separate lawsuits in state court against 29 oil, gas and coal companies seeking damages related to the companies’ impact on global climate change. The jurisdictions will join the cities of San Francisco and Oakland, the counties of Marin and San Mateo, and San Diego County’s city of Imperial Beach in filing lawsuits to hold specific fossil fuel companies accountable for contributing to more frequent crises like wildfires, droughts and strong storms. The Santa Cruz County and city officials believe that the defendants have been aware of their role in extensive pollution for nearly 50 years. The city of Santa Cruz’s final complaint document states, “Defendants’ historical and current fossil fuel extraction and production records are publicly available in various fora. These include university and public library collections, company websites, company reports filed with the U.S. Securities and Exchange Commission, company histories and other sources.” What sets Santa Cruz County and the city’s lawsuits apart from the others is that they are the first to call out not just the detriments of sea level rise, but disruptions to the hydrologic cycle caused by fossil fuel pollution. The lawsuits each cite a variety of peer-reviewed studies and agencies like the National Oceanic and Atmospheric Administration and NASA. Santa Cruz County will be hit especially hard by 2030, when an expected sea level rise of 4 inches would put 850 buildings and assets valued at $742 million in danger, according to their lawsuit. The city of Santa Cruz’s lawsuit states the city has spent millions of dollars to offset flooding and storm damage. Main roadways are a serious concern in the event of 4 inches of sea level rise since portions may need to be fortified or completely replaced because of coastal erosion.. 

Wall Street Returns To U.S. Shale With A Bang -- Investors have grown wary of U.S. shale after years of disappointing returns, and they have pressed shale companies to rein in reckless drilling practices. But with money still pouring into the shale sector, there’s no sign yet that Wall Street is withholding investment in the industry.Shale executives have gone to great lengths in recent months to reassure investors that they are pursuing a more conservative strategy, foregoing aggressive drilling plans to prioritize profits. Despite what could be a seismic shift in the shale sector, Big Finance continues to shower shale companies with money.According to a series of interviews conducted by Reuters with industry experts, there is no shortage of capital interested in shale drilling. “If you’ve got the rocks, you can get the money,” Buddy Clark, co-chairman of the energy practice group at law firm Haynes Boone, told Reuters.Private equity is taking on a larger role in the shale industry as traditional banks pare back lending. Since 2014, investors have funneled $200 billion to private equity firms that have a focus on energy, according to the WSJ, citing data from Preqin. Armed with cash and hungry for yield, private equity firms have injected $20.26 billion into energy deals so far this year, more than 36 percent higher than in 2016, Reuters says. The latest example of that trend came from Warburg Pincus LLC, which just a few days ago announced a $780 million investment into ATX Energy Partners. ATX will use the money to purchase assets from larger oil producers, but notably, ATX is a new venture without any drilling assets to date.  Reuters reports that new financial instruments are popping up, servicing the needs of shale drillers and filling the void that traditional lending has left. “The upstream industry has been really creative in how it pursues financing of late,” Charlie Leykum, founder of private equity firm CSL Capital Management LLC, told Reuters. These instruments include Drillcos, which give investors more control over cash flow until certain returns are met.

US crude oil production could be more than Saudi Arabia in January - graphs -- The Dec 8, 2017 weekly EIA oil production report was that US production was at 9.78 million barrels per day. The US may end December with 9.9 million barrels per day. Rystad Energy’s comprehensive well data for the United States shows that domestic oil production could pass 9.9 million barrels per day in December 2017. U.S. shale production is expected to rise for a 13th consecutive month to a new record in January, the U.S. Energy Information Administration said on Monday.January output is forecast to increase by 94,000 bpd to 6.41 million bpd, according to the EIA’s monthly drilling productivity report.This could put US production at 10.1 million barrels per day. US Crude oil production will be over 10 million barrels per day in January and this will be more than Saudi Arabia. The US will likely add 1 million barrels per day in 2018 and will pass Russia’s 11 million barrels per day.On an all liquids basis US production will be over 15 million barrels per day and should go beyond 16 million barrels per day.

Saudi Arabia Reportedly Looking At U.S. Shale Assets To Diversify Aramco - Saudi Arabia is reportedly looking at natural-gas assets in Texas shale basins and is in talks with a U.S. liquefied natgas producer as it looks to break into U.S. shale. Saudi Arabia is reportedly looking at natural-gas assets in Texas shale basins and is in talks with a U.S. liquefied natgas producer as it looks to break into U.S. shale. State-run oil giant Saudi Aramco is in early negotiations with Tellurian to buy a stake or some of its natural gas. The report also said Armaco has asked about assets in the Permian and Eagle Ford shale formations. If the company starts production in the U.S., it would be the first time it had any output from outside the kingdom. It also would come after three years of struggles to cool shale's growth, which has upended markets that Saudi Arabia once swayed as the swing producer. But the kingdom's domestic energy needs may be prompting an embrace of its U.S. rivals. Investing in shale would give Saudi Arabia access to the U.S. industry's ability to quickly start and stop production projects and use that knowledge back at home. "Saudi Arabia has a lot of shale, a lot of tight gas," said Jim Krane, an energy analyst at Rice University's Baker Institute for Public Policy. "Aramco needs to get to the gas because Saudi Arabia is very short on natural gas. The only way to get to it without imports is to tap into shale." Saudi Aramco won't be the first Middle Eastern country to invest in U.S. shale; the UAE's Mubadala sovereign fund has invested in a private equity firm in U.S. shale, the report said. 

U.S. tax overhaul likely to spur spending by refiners, pipeline cos - (Reuters) - U.S. refiners and pipeline companies are likely to embark on a capital spending spree in the next year, fueled by a provision in the recently-passed U.S. tax bill that rewards investment in new projects, said energy industry lobbyists and analysts. On Wednesday, Congress gave final approval to the biggest overhaul of the U.S. tax code in 30 years, the first major legislative victory for President Donald Trump since he took office. The bill contains a bonus depreciation provision that allows all companies to immediately write off the full costs of capital improvements, instead of depreciating the new asset over time. The immediate expensing of capital costs will make less financially-attractive projects more viable and free up capital for stock buybacks and increased dividends. The benefit begins to phase out in 2023, which means companies could look to advance projects to take advantage. "Every major refining company has a list of projects they want to get approved that are ranked by profitability and risk," said Charles Kemp, vice president of Houston-based energy consultancy Baker & O'Brien Inc. The bill, he said, will motivate companies to look further down those lists, "and noticeably increase capital budgets." The U.S. energy industry has emerged as one of the winners of the historic tax package passed this week. The S&P Oil and Gas Refining Marketing Index is up 27 percent this year, and hit a record this week on optimism over the bill's passage. In addition to lower corporate rates, the net effect of the immediate write-off provision will boost the present value of capital investments by roughly 4 to 10 percent, Kemp said. That essentially makes projects more profitable, more quickly. Moving up projects could be advantageous for refiners and pipeline operators such as Valero and Energy Transfer Partners, as they spend billions yearly to expand plants and build pipelines to move increasing volumes of petroleum. All refining and pipeline companies contacted by Reuters declined to comment on the implications of the tax package, though some expressed support for the reform in general. Refiners have already started evaluating capital projects to determine whether marginal ones have become profitable and whether any can be advanced into the five-year window, said two refining lobbyists based in Washington D.C., "We have a lot of north and south pipelines, but not a lot east and west. And there's a lot of demand for exports, so we will see a real uptick in capital investment to meet that demand." 

GOP Tax Bill: How the Environment Lost - The Republican tax bill , which is likely headed to President Donald Trump 's desk in the next few days, has major repercussions for our precious environment.   While the electric vehicle industry and the wind and solar sector can breathe a little easier that the sweeping legislation preserves their tax credits, fossil fuel producers are likely cheering the opening of the Arctic National Wildlife Refuge (ANWR) to oil and gas drilling.  The controversial provision, a proposal from Senator Lisa Murkowski (R-Alaska), would auction off an area known as the “ biological heart " of the Arctic Refuge that's home to crucial wildlife habitats, including one-third of all polar bear denning habitat in the U.S. and one-third of the migratory birds that come to the Arctic Refuge. It is also considered sacred to the indigenous Gwich'in people, who sustain themselves from the caribou that migrate there.  Oil drilling in the refuge has been sought by conservative lawmakers for decades despite opposition from 70 percent of Americans. "Congress has committed the ultimate sellout of America's public lands with such a devious and shortsighted action in one of the wildest places left in the world," said Jamie Rappaport Clark, president and CEO of Defenders of Wildlife . "Shame on those who supported this abhorrent assault on our natural legacy." Proponents of arctic drilling say the plan would help pay for the massive tax cuts, with Murkowski insisting that her rider would raise “more than $1 billion within 10 years and it will likely raise over $100 billion for the federal Treasury" over time. But critics contend that with oil prices below $60 a barrel, it's not even certain that oil companies would want to open up one of Earth's most remote and harshest areas, nor would drilling raise enough revenue to offset the massive deficit forecasts created by the tax bill.  Notably, the renewable energy sector did not escape the widely unpopular bill's effects scot-free, as it includes the Base Erosion Anti-Abuse Tax (BEAT) program that would "undermine our capacity to use renewable energy tax credits, which have value only if they can be monetized," according to a letter addressed to the Senate from clean energy trade groups.

Factbox: Oil, natural gas industry wins big in tax bill - Congress this week passed a sweeping tax overhaul package that includes major wins for the domestic oil and natural gas industry.The legislation was approved by the House and Senate Tuesday, but needed technical corrections from the House on Wednesday. President Donald Trump is expected to sign the bill into law by early January.The bill opens up hundreds of acres in Alaska, off limits for decades, to drilling; maintains tax breaks for producers, including some industry lobbyists concede were not a priority; and calls for millions of acres to be sold from government oil stocks. Upstream, downstream breaks. The bill keeps numerous oil and gas industry-friendly tax breaks in place, including deductions for intangible drilling costs, percentage depletion, or amortization of geological and geophysical costs. A earlier House version of the bill had proposed eliminating a credit for producing oil and natural gas from marginal wells and an enhanced oil recovery credit. Industry groups were not fighting the change since those credits were so rarely used, but congressional negotiators kept them in anyway.  The refining industry successfully lobbied to keep manufacturing depreciation and interest deductions in place in the bill, and last-in, first-out accounting practices preferred by refiners will remain. Senator John Cornyn, Republican-Texas, also included language that allows income from publicly traded partnerships, including master limited partnerships, to qualify for a 23% pass-through deduction, a change pushed for by refiners. The bill will allow development in the Coastal Plain of the Arctic National Wildlife Refuge, a 1.5 million-acre section in northwestern Alaska currently off limits to drilling without congressional approval and an environmental impact study. The bill requires the US Interior Department to hold at least two areawide lease sales offering a minimum of 400,000 acres each within 10 years.

Drilling in Arctic Refuge Gets a Green Light. What’s Next?  --  President Trump on Wednesday was poised to sign the new tax bill, passed by Congress, which lifts a decades-old ban on oil and gas drilling in the Arctic National Wildlife Refuge in northeastern Alaska.  Both supporters and opponents say it could be years before the first lease sale, a precursor to any drilling. The new legislation requires that the Department of Interior conduct one sale within four years and a second within seven. But there are many steps that must be taken before those sales can be held, and the process is not completely clear. Lawsuits and other actions by opponents of drilling could slow things, both before and after any lease sales.The Interior Department will have to identify lands in the 1.5 million acres of the refuge along the coastal plain, known as the 1002 area, for leases. Once the department comes up with a list of options, there will be at least one comment period in which the public will have a chance to be heard. One question mark is whether new seismic studies will be undertaken. Such studies can reveal underground formations that have high oil development potential, and the only ones that were done in the refuge are more than three decades old. Based on the old studies, the United States Geological Survey has estimated that the 1002 area contains from 5 to 16 billion barrels of oil. David W. Houseknecht, a senior research geologist with the survey, said the agency was about to re-analyze the data using improved software in hopes of reducing the uncertainty of that estimate. But new studies using modern three-dimensional technology could produce even better estimates. The Interior Department in September proposed allowing new studies, but it is unclear whether oil companies, if allowed, would undertake them, or whether the Interior Department would wait for them to be done before conducting a sale. Oil companies have bid on drilling leases in other areas with less-than-ideal information.

The Alaskan senator who just opened America's largest wildlife refuge to drilling wants to study ocean acidification - Alaska Senator Lisa Murkowski has spent decades seeking oil. Specifically, oil that lies beneath the tundra of the Arctic National Wildlife Refuge (ANWR). With this week’s passage of a GOP tax bill containing a provision to open ANWR to drilling, she’s finally achieving her goal.  But you know what else Murkowski wants to do? Study climate change. On Tuesday, Murkowski’s office announced that the Senator was co-sponsoring a bill that would direct the National Oceanic and Atmospheric Administration to assess the vulnerability of coastal communities to ocean acidification. The Coastal Communities Ocean Acidification Act of 2017 was a bi-partisan effort, crafted in concert with Senators Maria Cantwell (D-WA), Susan Collins (R-ME), Gary Peters (D-MI), and Sheldon Whitehouse (D-RI). A version of the same bill was introduced to the House in May. There’s no indication of when the bill might get a vote in either chamber.  “Alaska’s culture and economy thrive on so many resources that come from the ocean,” Murkowski said in a statement. “This proactively addresses a very real issue and will help us all gain a deeper understanding of how ocean acidification is affecting our coastal and subsistence communities throughout Alaska.” For Murkowski, toeing the line between industry and the environment is nothing new.In stark contrast many of her GOP colleagues, the Republican Senator routinely acknowledges that climate change is real and a threat. At the same time, she has pushed for more offshore and onshore drilling throughout the state, and championed exports of natural gas and crude oil. But in a year when “both sides” has become our internet meme stand-in for humanity’s rapidly-decaying ability to form a consensus reality, Murkowski’s pivot to ocean acidification—the very same week that her dreams of sucking black gold from America’s largest wildlife refuge received a Congressional stamp of approval—feels a bit on the nose.

Federal report finds ‘huge’ increase in North Slope oil -- The Trump Administration Friday heralded a "huge" increase in the North Slope's oil potential as it released an updated geological assessment of a large region that factors in big, recent oil discoveries and other new data. The area assessed centers around the giant National Petroleum Reserve in Alaska, and is estimated to contain a mean of 8.7 billion barrels of undiscovered oil that can be produced using existing technology.That is a sharp jump from a 2010 assessment of the same area that pegged the estimate at 1.5 billion barrels, the Interior Department said Friday. "New discoveries have changed our geologic knowledge of the area – and these assessments show that the North Slope will remain an important energy hub for decades to come in order to meet the energy needs of our nation," Interior Secretary Ryan Zinke said in the prepared statement.In recent years following the U.S. Geological Survey's 2010 assessment, ConocoPhillips has announced the Willow discovery within the reserve's boundaries. Just to the east on state land, Spanish multinational Repsol and other oil companies are pursuing the large Pikka discovery. Those two discoveries alone could produce some 220,000 barrels of oil daily, the companies have said. That amount would sharply boost the roughly 550,000 barrels of oil flowing through the trans-Alaska pipeline.

A Dam(n) Big Fracking Problem - More than half of 48 dams that oil and gas companies built in recent years without first obtaining the proper permits had serious structural problems that could have caused many to fail. And now, the BC Oil and Gas Commission, which appeared to be asleep at the switch in allowing the unlicensed dams to be built in the first place, is frantically trying to figure out what to do about them after the fact. Information about the unprecedented, unregulated dam-building spree is contained in a raft of documents that the commission released in response to freedom of information requests filed by the Canadian Centre for Policy Alternatives. The documents obtained by the CCPA, along with other materials recently posted on the OGC’s website, reveal that 28 of at least 48 unlicensed dams on Crown (meaning public) lands had significant structural flaws or other problems belatedly identified by commission staff.All the dams were built to trap fresh water used by energy companies drilling and fracking for gas in northeast B.C. In some fracking operations in the region, companies are pressure-pumping the equivalent of 64 Olympic-size swimming pools of water underground to break open gas-bearing rock formations, triggering earthquakes in the process.The OGC paved the way for the construction of the dams by granting companies numerous permits under the Land Act to use public lands to “store water.”But in approving the applications, commission personnel failed to ask basic, critical questions: How did companies intend to store the water? In tanks? In pits? Behind dams?Since the OGC didn’t ask, the companies didn’t disclose that they planned to build dams — lots of them. Nor did they disclose that in many cases the water sources for their dams would be creeks and other water bodies that the companies were not entitled to draw from because

Canada oil producers exhaust options as pipelines, railroads fill - (Reuters) - Canadian oil producers are running out of options to get crude to market as pipeline and rail capacity fills up, driving prices to four-year lows and increasing the risk of firms having to sell cheaply until at least late 2019.   This will drive down the profit margins for the oil sands industry, already struggling to compete with cheaper and abundant supplies from U.S. shale. A number of foreign oil majors have left Canada’s oil sands to invest in more profitable U.S. shale plays, selling over $23 billion in Canadian assets this year alone.  Canada’s oil sands output is still growing - but only as projects under construction are completed and smaller expansions come online. Oil firms are not commissioning large new projects because they cannot build them profitably with oil in the $50s a barrel.  The deeper discount on crude means next year could be just as tough for Canadian producers from a price perspective as 2017, even though international crude prices have strengthened.  “We have a build-up of supply and that’s only going to get worse next year. We are adding more and more pressure into a constrained export system,” The volume of crude in storage has hit record levels in western Canada and heavy crude is trading near its widest discount to U.S. crude CLc1 since December 2013, driven by increased supply and a leak on TransCanada Corp’s Keystone export pipeline last month. The discount on Canadian heavy crude blew out to as much as $28 a barrel below the West Texas Intermediate benchmark, pushing the outright price of Canadian barrels to less than $30. Many traders and analysts expect the discount to be wider in 2018 than the negative $12 a barrel year-to-date average as oil supply rises. Canada’s oil sands output is forecast to climb by 315,000 barrels per day next year and 180,000 bpd in 2019 to 3.2 million bpd, according to RBC Capital Markets, which described the growth as “unprecedented” and said exports will materially exceed pipeline capacity in early 2018.

Canada's Trans Mountain crude pipeline oversubscribed by 35% in January - Kinder Morgan Canada will limit crude oil nominations on its Trans Mountain pipeline system by 35% in January, meaning the line will carry 65% of nominated volumes, the company said Thursday.January volumes on the Trans Mountain mainline system are expected to be 264,285 b/d, down from 309,604 b/d in December, Kinder Morgan said in an email.Exports from the Westridge Dock, near Vancouver, are expected to be 76,491 b/d, compared with 78,917 b/d in December. Throughput on the Puget Sound pipeline is expected to be 118,200 b/d, compared with 148,368 b/d in December. The Trans Mountain pipeline ships Canadian crude from Edmonton, Alberta, to the Westridge export terminal in Burnaby, British Columbia, and on to the connected Puget Sound pipeline to Seattle-area refineries.

Before building a $400 million pipeline, make sure your neighbors are on board - A chunk of Sempra Energy’s natural gas pipeline sits in the dirt behind a community center in the village of Loma de Bacum in northwest Mexico. Guadalupe Flores thinks it would make a great barbecue pit. “Cut it here, lift the top,’’ he says, pointing to the 30-inch diameter steel tube. “Perfect for a cook-out.’’ It would be an expensive meal. The pipeline cost $400 million, part of a network that’s supposed to carry gas from Arizona more than 500 miles to Mexico’s Pacific coast. It hasn’t done that since August, when members of the indigenous Yaqui tribe – enraged by what they viewed as an unauthorized trespass their land – used a backhoe truck to puncture and extract a 25-foot segment. They left the main chunk about a mile from the community center, perpendicular to the rest of the pipeline, like a lower-case t. The impact extends far beyond Loma de Bacum and its 4,500 residents. Arizona’s gas exports to Mexico have plunged 37 percent since the shutdown, hitting an eight-month low in December. Mexico’s state utility is having to burn fuel oil instead to generate power, raising costs. It’s not an isolated case. Mexico’s opening of its energy industry has succeeded in attracting capital, but it’s also been beset by territorial or environmental disputes, often involving the country’s myriad indigenous groups. When protest turns into sabotage, there’s a risk that investors will be put off from future phases, like an extensive shale development. It’s also grist to the mill of the leftist frontrunner for next year’s presidential election, who’s vowing to reverse some of the reforms.The Yaquis of Loma de Bacum say they were asked by community authorities in 2015 if they wanted a 9-mile tract of the pipeline running through their farmland -- and said no. Construction went ahead anyway. 

Venue of last resort: the climate lawsuits threatening the future of big oil -  In early October, 22 state and federal judges hailing from Honolulu to Albany got a crash course in scientific literacy and economics. The three-day symposium was billed as a way to help the judges better scrutinize evidence used to defend government regulations.But the all-expenses-paid event hosted by George Mason University’s Law & Economics Center in Arlington, Virginia, served another purpose: it was the first of several seminars designed to promote “skepticism” of scientific evidence among likely candidates for the 140-plus federal judgeships Donald Trump will fill over the next four years. The lone science instructor was Louis Anthony Cox Jr, a risk analyst with deep industry ties whose recent appointment as chair of the US Environmental Protection Agency’s clean air scientific advisory committee drew condemnation in public-health circles. Since 1988, Cox has consulted for the American Petroleum Institute, a lobby group that spent millions to dispute the cancer-causing properties of benzene, an ingredient in gasoline, and is now working to question the science on smog-causing ozone. He’s also testified on behalf of the chemical industry and done research for the tobacco giant Philip Morris.For a $4,000 honorarium, Cox delivered two closed-door lectures at George Mason: “a primer on the scientific method” followed by a session aimed at “understanding what science can and cannot do”. Included in his presentation were slides urging judges to be wary of EPA science on fine particles – a pollutant he has been researching for API. Based in George Mason’s Antonin Scalia Law School, the Law & Economics Center espouses a free-market approach to policy. A 2013 investigation by the Center for Public Integrity found that the libertarian thinktank hosted more judicial conferences than any other university program in the country, fueled by conservative and big-business donors. Over the past two years, roughly $4.5m of $18.6m in contributions to the Law & Economics Center came from oil and gas interests, including Koch Industries, ConocoPhillips, ExxonMobil and API, which represents more than 650 corporations.

Adapt Or Die: Oil Majors In The New World - The world’s biggest public oil company is facing a challenge: it needs to continue to grow in a world that is drastically different from what it used to be, back when Exxon reigned supreme and the world had insatiable hunger for its oil. That time is now behind us.Today, we have the Paris Agreement on climate change, a major drop in large new oil discoveries on a global level, sanctions against two of the countries with the biggest oil reserves in the world, and, of course, a shift from oil to gas and renewable energy.All of these are potential headache inducers for Exxon, and this is reflected in the movement of its stock price and analyst price targets, according to a Bloomberg article. While the shares of the company still trade at a premium to its peers, this premium is shrinking, Kevin Crowley writes, as the giant struggles to keep up with the changing times.For starters, it is finding it hard to replace its reserves—a problem shared by most large oil companies after the oil price crisis dried up funding for new discoveries. The situation is made worse by U.S. sanctions against Russia and Venezuela, sanctions that specifically target the oil industry and prevent Exxon from taking advantage of their still-abundant resources.So, Exxon is actively seeking oil elsewhere. The company recently spent US$1.2 billion on exploration blocks in the pre-salt zone of the Brazilian continental shelf, which is widely believed to be the new hotspot for the oil industry. Exxon also recently announced oil discoveries offshore Equatorial Guinea and Guyana, so it is by no means sitting idly by, waiting for the sanctions to expire so it can return to Russia. Exxon is also expanding into gas and LNG: just yesterday the company announced the completion of a deal with Italian Eni for the acquisition of a 25-percent interest in a prolific gas block in Mozambique. Exxon will be responsible for building and operating all LNG facilities at the site, which holds an estimated 85 trillion cu ft of gas.

Oil Discoveries At Lowest Point Since The 1940s - The oil industry discovered the least amount of oil in 2017 in almost eight decades, breaking the previous record low set in 2016. The global oil industry has discovered less than seven billion barrels of oil equivalent so far this year—a drop-off from the 8 billion boe discovered last year. Last year’s total was the lowest since the 1940s. The 2017 figure is down by more than half from the 15 billion boe discovered in 2014-2015, and down sharply from the 30 billion boe discovered in 2012. The plunge is the result of a third consecutive year of relatively low upstream exploration budgets. So many oil companies slashed their spending on exploration when the market downturn began in 2014, and they have yet to restore that spending to anything close to pre-2014 levels. “We haven’t seen anything like this since the 1940s,” Sonia Mladá Passos, Senior Analyst at Rystad Energy, said in a statement. “The discovered volumes averaged at ~550 million barrels of oil equivalent per month. The most worrisome is the fact that the reserve replacement ratio in the current year reached only 11 percent (for oil and gas combined)—compared to over 50 percent in 2012.” The reserve-replacement ratio measures the volume of oil that is discovered relative to what is produced in a given year. The idea being, the industry needs to discover 100 percent of what it produces in order to avoid a decline in reserves. Rystad Energy says that 2006 was the last year in which the industry posted a reserve-replacement ratio above 100 percent. The implication is that the world is burning through oil at a faster rate than the industry is discovering new reserves.

The world's largest oil and gas companies are getting greener after fighting with shareholders for months - The world's largest oil-and-gas companies are going green. At least that's what they're saying.   Companies like Exxon Mobil — which counts Secretary of State Rex Tillerson among its former CEOs — and Shell have pledged to reduce their emissions, and have publicly adopted plans to disclose risks climate change poses to their core businesses.  After bowing to shareholder pressure, Exxon said in an SEC filing earlier this month that it would report the "impacts" that climate change and environmental policies have on the company. The disclosure would include implications of the 2 degrees Celsius warming limit set by the Paris Climate Agreement in 2015, as well as how the company is positioning its business for a "lower-carbon future."  Shell, one of Exxon's largest competitors, is taking its climate commitment a step further. The oil-and-gas conglomerate announced earlier this month a pledge to reduce its net carbon emissions 20% by 2035, and 50% by 2050.   A whopping 63% of the Exxon's shareholders supported the proposal for the company to disclose how climate change will affect its business, though Exxon initially rejected the proposal in May.   Vanguard, the world's largest provider of mutual funds, is one the largest shareholders in Exxon. In November, Vanguard announced that it would push companies it holds shares in to disclose climate risks.   But some in the climate community are still skeptical that the shift will be meaningful.  "ExxonMobil is still investing aggressively in developing future reserves under the assumption that economies worldwide will continue to rely heavily on fossil fuels,"

Exporting Fracking: 8 Countries Ripe For Tight Oil Drilling Outside The U.S. - What are the prospects for tight oil outside the US?   If U.S. tight oil can emerge so quickly to disrupt the market, perhaps other plays out there might have the same effect. Our Upstream analyst teams closely monitor the progress of multiple unconventional oil and gas plays all over the world. We predict that tight oil plays across eight countries will contribute to global supply by the late 2020s. Algeria, Colombia, China, Egypt and Mexico each have an embryonic tight oil industry, and shouldn’t have much impact in that period. Argentina, Canada and Russia are rather more advanced.  Argentina has the most growth potential over the next decade. The Vaca Muerta has a resource of 2-3 billion bbls of oil (as wells as 9.5 bn boe of gas) on the third of the play that has been tested so far either by horizontal or vertical drilling. The remaining two-thirds of the play needs further testing to confirm similar productivity levels. Current activity is mainly focused on developing gas which has had superior well productivity and price incentives are in place till 2021. Vaca Muerta tight oil volumes are running at around 36,000 b/d, but there is scope for significant upside with resource break evens of under US$50/bbl (NPV15). Most tight oil projects are in the pilot stage with operators planning to move to full development by 2020.  Canada today is the biggest tight oil producer outside the US. Maturing oil-prone plays and low prices have reduced production from the 2014 peak by about 5% to the current 335,000 b/d. Liquids production is split between tight oil (200,000 b/d) and condensate (135,000 b/d). There are a number of individual plays in the shadows of the Rocky Mountains, including the world class gas-charged reservoirs of the Duvernay and Montney. These have been productive for oil and condensate, but folding has made Rockies geology more complex - sweet spots are smaller than those of the giant US counterparts. Most of the Canadian oil-prone plays, many of which are shallow, low-cost formations in the prairies of Saskatchewan, have already peaked. We forecast tight oil production will be flat at 200,000 b/d over the next decade as new drilling offsets declines.  .  Russia is the tight oil dark horse. There is already around 1 million b/d of production from unconventional Tyumen and Achimov 'hard to recover' reservoirs that require horizontal drilling and fracking. But volumes from the Bazhenov and Domanik, the two plays classified as ‘tight oil’, are just 20,000 b/d.

UK medium-range storage natural gas stocks down over 50% since end-November - The amount of gas held within the UK's medium-range natural gas storage facilities has fallen by more than 50% since the end of November on the back of high demand allied to weaker UK gas production, an analysis of data by S&P Global Platts showed. Gas stocks held within the UK's seven medium-range reservoirs combined began Thursday's gas day at 594 million cu m, less than half the 1.211 Bcm held at the start of the November 28 gas day, data from National Grid showed.Withdrawals from medium-range reservoirs have been well above seasonal trends in December due to falls in both UK Continental Shelf production and weaker withdrawals from the long-range Rough reservoir, in addition to high UK gas demand on the back of below-average temperatures during the middle of the month.As a result, MRS stocks began Thursday's gas day well below levels seen in previous years, standing 333 million cu m lower year on year and 151 million cu m shy of the bottom of the five-year range.However, stocks were set to receive a boost in late December with NBP price spreads incentivizing injections due to the January contract trading above contracts for December delivery.The NBP January contract was assessed at 58.75 pence/therm Thursday, 2.75 p/th higher than the weekend contract (Saturday-Tuesday) and 1.25 p/th above the working-days-next-week contract (Wednesday-Friday), Platts data showed. Indeed, data from Platts Analytics' Eclipse Energy showed MRS reservoirs injected a net 11 million cu m into stock during Thursday's gas day, set to boost stock levels back above the 600 million cu m mark as a result.

Platts JKM breaks above $11/MMBtu on stronger North Asia winter LNG demand - Platts JKM for February delivery cargoes, the new front month, continued its recent uptrend and tested higher through the week to end at $11.075/MMBtu Friday, on the back of additional North Asia LNG demand and limited Pacific supply. Further information on Malaysian Petronas' mid-January delivery cargo supported bullish sentiment in the prompt market, with the deal reported done at above $11/MMBtu to a Japanese end-user. While several traders noted that Japanese and South Korean end-users would likely rely on inventory drawdown to avoid spot procurement, there were concerns over fast depletion of inventory amid colder regional weather. Meanwhile, private Chinese LNG buyers were reported to be active in the market seeking prompt cargoes to accommodate potential terminal slots to be given by PetroChina, according to multiple sources. In India, Gail was reported to have issued a tender seeking two cargoes for H1 and H2 February delivery, according to multiple sources. Bharat Petroleum Corporation Limited's buy tender seeking a January 19-21 delivery cargo was reported to have been awarded at just below $10/MMBtu earlier in the week. BPCL's tender seeking cargoes for May, August and October delivery next year was reported to have been awarded at around 11.5% Brent oil slope. Decoupling of West India prices to Northeast Asia prices amid an imbalance in regional demand widened the differential further by 45 cents/MMBtu on the week. In Indonesia, Pertamina was heard to have issued an Expression of Interest, with restricted participation, to offer 13 cargoes for February to November 2018. In the Atlantic, thin trading ahead of Christmas as well as expectations of warmer weather eased NBP prices, opening up the NBP-JKM gap to above $3/MMBtu over the week. 

The World's Biggest Offshore Boom Is Accelerating - In a sign that Brazil’s offshore sector is competitive in a world of $50–$60 oil prices, two large oil companies just announced significant investments in oil fields in the South American nation.  Total SA announced on Monday a final investment decision in a massive offshore oil field in Brazil’s Santos Basin, and the French oil giant boasted of low production costs. “The decision to launch the large-scale development of the Libra field is a major step for Total in Brazil,” Arnaud Breuillac, Total’s President of Exploration & Production, said in a statement. “We have worked with Petrobras, the operator, and our partners to secure technical costs below 20 dollars per barrel. This proves that we are capable of developing competitive deep offshore projects.”The Libra field is located about 180 kilometers off the coast of Rio de Janeiro in ultra-deep water, a pre-salt field that is considered to be Brazil’s largest discovery, with estimated reserves of between 8 and 12 billion barrels. It was discovered in 2010 and dramatically raised expectations for future growth, ushering in a period of bullishness and confidence in the country’s direction.The field is finally getting some large-scale investment for development. Total said it would use a floating production storage and offloading (FPSO) unit that would have a production capacity of 150,000 bpd and 17 wells. It is expected to come online by 2021. But more FPSOs will be added to eventually scale up output to 600,000 bpd.Statoil made a separate announcement on Monday, agreeing to take a 25 percent stake in Brazil’s Roncador field, an acquisition from Petrobras valued at $2.9 billion. The Roncador field has been producing for almost two decades, and as of November it was producing 240,000 bpd. Statoil has expertise in squeezing more oil out of mature fields. Roncador is thought to hold 10 billion barrels of oil equivalent (boe), with about 1 billion boe remaining. Statoil is confident it can boost that figure 1.5 boe. The move will triple Statoil’s production in Brazil to 110,000 bpd. The investment announcements are significant because Brazil is picking up momentum after years of disappointment. Petrobras had to repeatedly downgrade its forecast for production growth, succumbing to a future of more modest ambitions. The state-owned oil company can claim the mantle of the most indebted oil company in the world, a debt pile that once vastly exceeded $100 billion.

Colombia begins importing bulk LPG as natural gas reserves, output fall - Colombia has begun receiving is first sustained imports of bulk liquid propane gas, with volumes expected to rise significantly in the coming years as the country's natural gas reserves and output continue to decline. Juan Manuel Morales, an attorney and spokesman for G-5, a Bogota-based consortium including Colombia's five largest LPG distributors, said Thursday the group took receipt of its first shipment of 1,600 mt on November 14 at a port near Cartagena from Vitol, the London-based energy trading, refining, and transport firm. The LPG was produced by a US Gulf Coast refiner and delivered via bulk cargo ship. Terms of the six-month firm contract the consortium signed with Vitol, which has offices in Houston, call for the Colombian group to receive at least 4,000 mt/month of LPG through April. By mid-2019, Morales said imports likely will have doubled to 7,000-8,000 mt/month, possibly reaching 10,000 mt/month by 2022. So far, five additional cargoes of 1,600 mt have arrived since the initial shipment. Colombian domestic consumption of LPG is stable at 49,000-51,000 mt/month, Morales said, so current and projected imports by the consortium represent a significant portion of the gas that Colombians consume. G-5 members serve 80% of the domestic liquid propane consumers.

Is A Russia-Cuba Energy Deal In The Works? --The chief executive of Russian state oil major Rosneft met yesterday with Cuba’s President Raul Castro, suggesting that the two are working on an energy deal, Reuters reports. Rosneft started exporting crude oil to the Caribbean island earlier this year as its main supplier, Venezuela, struggled with a decline in its own production, and in October Sechin said there were plans to increase oil shipments to Cuba. Rosneft also plans to invest in refining in Cuba, it became clear after a meeting between Sechin and Cuba’s Energy Minister Alfredo Lopez. More specifically, the company will take part in the modernization of the Cienfuegos refinery—a joint venture between Cupet and PDVSA that last week became officially fully Cuban. PDVSA held 49 percent in the refinery, and according to a former government official from the South American country, Cuba took over the stake as payment for debts that had been incurred from tanker rentals and professional services. The refinery has a daily capacity of 65,000 barrels of crude, but in August this year it only processed about 24,000 bpd, the Cuban daily said. What’s more, Venezuela’s oil industry troubles led to a change in the grades it sent to Cienfuegos to heavier ones that are more difficult to process. Cuba has been dependent on Venezuelan oil imports for as much as 70 percent of its domestic energy needs, but with Venezuelan production falling, the island has turned to alternative suppliers. It also has plans to develop its own oil and gas resources. There are few foreign energy companies operating in Cuba, but one of these, Australian Melbana Energy, has set its sights on an onshore deposit dubbed Block 9, which, according to the company, could have reserves of between 1.18 billion and over 44 billion barrels of oil, with the recoverable portion estimated at around 637 million barrels.

The Beginning Of The End For Norwegian Oil  --   The demise of the North Sea doesn’t necessarily mean the end of Norway’s petroleum era - far from it. Still, despite significant reserves in the Barents Sea, Norway is about to embark upon a long period of structural decline as its benchmark fields inch closer to depletion and its reserves taper before our very eyes.The average Norwegian might not even perceive the difference between an oil-rich Norway and one that is past its prime. The nation’s massive external and fiscal net position, as well as its complete energy independence thanks to hydropower, allows for great flexibility regarding future policies. Yet its oil workers must prepare for a future that is much more Arctic, smaller-scale and gas-based.There’s ample evidence to conclude that all the sweet spots of Norway’s continental shelf have been found. The latest shelf licensing round (24) elicited a weak response, with only 11 companies applying for production licenses. There was plenty to bid for—102 blocks were up for grabs (never before did the Norwegian Petroleum Directorate offer so much, with an overwhelming majority of them in the Barents Sea), but due to their remoteness from formations deemed to be the most hydrocarbon-rich, bidders were only half as numerous as they were during the previous licensing round in 2015.Other factors also contributed, including ongoing legal disputes whether drilling in the Arctic breaches Point 112 of Norway’s constitution (“natural resources should be managed based on long-term considerations, safeguarded for future generations”) and questions over the admissibility of drilling in Russia-disputed Svalbard waters (10 blocks) might have scared away an investor or two.

France bans fracking and oil extraction in all of its territories -  France’s parliament has passed into law a ban on producing oil and gas by 2040, a largely symbolic gesture as the country is 99% dependent on hydrocarbon imports. In Tuesday’s vote by show of hands, only the rightwing Republicans party opposed, while leftwing lawmakers abstained. No new permits will be granted to extract fossil fuels and no existing licences will be renewed beyond 2040, when all production in mainland France and its overseas territories will stop. Socialist lawmaker Delphine Batho said she hoped the ban would be “contagious”, inspiring bigger producers to follow suit. France extracts the equivalent of about 815,000 tonnes of oil per year – an amount produced in a few hours by Saudi Arabia. But centrist president Emmanuel Macron has said he wants France to take the lead as a major world economy switching away from fossil fuels – and the nuclear industry – into renewable sources. His government plans to stop the sale of diesel and petrol engine cars by 2040 as well. Above all the ban will affect companies prospecting for oil in the French territory of Guyana in South America, while also banning the extraction of shale gas by any means – its extraction by fracking was banned in 2011. 

France Approves World's First Ban on Fracking and Oil Production -The French parliament passed a law on Tuesday that bans exploration and production of all oil and natural gas by 2040 within mainland France and all overseas territories.  Under the new law, France will not grant new permits or renew existing licenses that allow fracking or the extraction of fossil fuels . French President Emmanuel Macron , who has cast environmental protection as a key presidential policy , celebrated the vote. "Very proud that France has become the first country in the world today to ban any new oil exploration licences with immediate effect and all oil extraction by 2040. #KeepItInTheGround #MakeOurPlanetGreatAgain," he tweeted.  Some, however, consider the gesture largely symbolic as the country is 99 percent dependent on hydrocarbon imports and extracts very little of its own oil and gas. According to Quartz , France produces about 16,000 barrels a day—much less in comparison to Saudi Arabia's output of 10.4 million barrels or Russia's 10.5 million barrels.

Why One Giant Gas Field Is a Big Deal for Egypt - The gas imports which once helped Egypt avert power blackouts may soon be a thing of the past. Eni SpA’s massive "Zohr" natural gas field, the Mediterranean Sea’s largest offshore field, started production earlier this month. Its huge reserves could prove a permanent remedy to the most populous Arab nation’s power needs and bring Egypt closer to its goal of energy self-sufficiency. Discovered in August 2015, Zohr is often described as a "supergiant" field because it has estimated reserves of about 30 trillion cubic feet, equal to the reserves of Israel and Oman combined, making it the largest gas discovery in the Mediterranean Sea. The field covers an area of about 100 square kilometers. On Dec. 16, gas from Zohr began to flow to a facility in Port Said city, with initial production of 350 million cubic feet per day. Daily output is expected to rise to about 1 billion cubic feet in June, and then to 2.7 billion by the end of 2019. President Abdel-Fattah El-Sisi has vowed to tackle the energy shortage as a priority. The project could also eventually enable Egypt to return to exporting gas. Previously, Egypt had sufficient supplies to export gas by pipeline to Jordan and Israel. Gas shortages began after the 2011 uprising against then president Hosni Mubarak.  Sporadic sabotage of its pipeline in the Sinai Desert by Islamist militants also throttled exports.  Zohr’s output is enough to cover the gap between Egypt’s total gas consumption, which stood at 4.9 billion cubic feet per day in 2016, and its total daily production of 4 billion cubic feet, according to data from the BP statistical review. Consumption outstripped production in 2015 reversing a trend of more than a decade. Egypt now imports liquefied natural gas, or LNG, at high costs to meet its energy needs. It first purchased the fuel in 2013. It bought a total of 89 LNG cargoes from international suppliers in fiscal year 2015/2016 at the cost of $2.2 billion, according to the oil ministry. Egypt’s government will issue another tender for LNG purchases in early 2018 to cover needs for the second quarter. It plans to stop importing the fuel by the end of next year because of gas from Zohr, Tarek El-Molla, Egypt’s oil minister, said in a November interview. Initial production from the field has raised Egypt’s gas production to 5.5 billion cubic feet a day, according to oil ministry data.

Feature: Indonesia to postpone LNG imports as domestic output rises -- Indonesia is planning to postpone LNG imports until at least mid-2019 because of more gas produced at the Eni-led Jangkrik field than was expected, leading to more LNG supply from Bontang. The decision could affect the long-term contract between state-owned Pertamina and Houston-based LNG exporter Cheniere Energy. Under the contract, 1.52 million mt/year of LNG was to be supplied from Corpus Christi in Texas from 2018-2019. Since then, the date of first commercial delivery has been redefined as 2019, in line with the project's completion timeline, a Cheniere Energy's spokesman said Wednesday. While long-term LNG contracts tend to lack a mechanism to defer or cancel a significant supply volume, the inherent flexibility of US LNG means offtakers can either resell the volumes to third parties or divert them to alternative markets. Pertamina could resell the LNG to portfolio sellers and take it only when needed, or integrate the volumes into its portfolio for delivery to customers either in Indonesia or elsewhere in Asia, market sources said. Earlier this year, Pertamina was in negotiations with a portfolio seller for the swap of 0.7 million mt of LNG over five years from its contractual offtake commitment with Cheniere. Djohardi Angga Kusumah, Pertamina's senior vice president for gas and power, said in May that an agreement would be signed by the end of 2017, but no updates were available. The swap would take place over the initial five years of Pertamina's 20-year contract with Cheniere, starting from 2018, Kusumah said at the time. The agreement would be similar to another US LNG swaps deal Pertamina signed with France-based portfolio seller Total in February 2016, he added. Under the agreement, Total will buy from 2020 onwards around 0.4 million mt/year of Pertamina's contracted LNG volumes from Corpus Christi LNG. Total will also supply from its global portfolio to Pertamina a volume growing over time from 0.4 million mt/year to 1 million mt/year. Pertamina has contracted to buy more than 4 million mt/year from international markets, with delivery before 2025, including 1.52 million mt/year from Cheniere. The first stage of Cheniere's supply, 0.76 million mt/year, was initially due to start in 2018, and the second from 2019.

Analysis: Soaring Brent pushes Indonesia to process sour crudes in 2018 -- The sustained strength in key Brent crude following the recent shutdown of the North Sea Forties pipeline has encouraged Asian end-users to switch from the expensive sweet crude complex in December, with Indonesia feeling the urge to upgrade its refinery systems next year to handle high sulfur crude oil. Unlike many highly sophisticated refineries in Northeast Asia, Indonesian end-users have limited feedstock procurement options as a majority of the refineries are not capable of handling sour crudes, increasing the pressure on state-owned Pertamina to make the necessary changes to help reduce the country's dependency on costly imported sweet crudes. Last week, Pertamina said it will start to modify its refineries to process more high sulfur crude oil in 2018. The modification program will start next year at the 125,000 b/d Balongan, 260,000 b/d Balikpapan and 348,000 b/d Cilacap refineries, a senior official told S&P Global Platts recently. "We want to upgrade all our refineries gradually to be able to process sour crude. We will not add new units in the refineries but only upgrade the existing ones," Pertamina's refining director Toharso said. "With the modification, we expect our refineries can process either sweet crude or sour crude," Toharso added. 

Putin’s Mr. OPEC Becomes an Oil Market Player - When they meet, they often drive in the same car. When they make a visit together, they tweet the world smiling selfies. And when Alexander Novak, the Russian energy minister, and Khalid Al-Falih, his Saudi counterpart, speak they exchange so many pleasantries that oil investors talk about a “bromance.” While neither man is the ultimate arbiter of oil policy in his country, the blossoming relationship between them has helped to deliver an unprecedented period of cooperation that is re-shaping the global oil market and energy geopolitics. For Al-Falih, the spotlight is natural. But for Novak it is all new: The soft-spoken, poker-faced Russian has now become one of the key voices in global oil markets after Moscow joined forces with OPEC to cut production and lift prices. His role is likely to become even more important over the coming months as the market’s focus shifts toward a possible exit from the cuts. “We now have to literally parse every Novak word—he has become the enigma,” says Helima Croft, global head of commodity strategy at RBC Capital Markets LLC and a former analyst at the Central Intelligence Agency. “Having that role in this market makes him one of the most visible Russian officials.”   Within Russia, Novak is seen as a consummate technocrat: intelligent and hard-working, a shrewd implementer of the Kremlin’s policies in the face of often challenging domestic and international energy politics. “He is one of the most promising people in the government—very smart, level-headed and diplomatic.”  The Russian energy minister demonstrated those qualities at the last OPEC meeting in Vienna, when the cartel agreed to extend output cuts to the end of 2018. Novak was a key driver of the push for Libya and Nigeria, whose surging production earlier this year helped to crash oil markets, to agree to cap their output, according to people familiar with the discussions. He even used Russia’s political ties to help the negotiations with the two countries. That’s unusual: The issue would traditionally be resolved within OPEC, as both countries are members, without the involvement of outsiders.

The Great Oil Swindle by Chris Martenson... When it comes to the story we're being told about America's rosy oil prospects, we're being swindled.  At its core, the swindle is this: The shale industry's oil production forecasts are vastly overstated. And the swindle is not just affecting the US.  It's badly distorted everything from current geopolitics to future oil forecasts. The false conclusions the world is drawing as a result of the self-deception and outright lies we're being told is putting our future prosperity in major jeopardy. Policy makers and ordinary citizens alike have been misled, and everyone -- everyone -- is unprepared for the inevitable and massive coming oil price shock.  Our thesis at Peak Prosperity is that the world’s equity and bond markets are enormous financial bubbles in search of a pin. Sadly, history shows there’s nothing quite as sharp and terminal to these sorts of bubbles as a rapid spike in the price of oil. And we see a huge price spike on the way. As a reminder, the US still remains a net oil importer (more on that below). At approximately 96 million barrels per day of oil consumption, each $10 rise in the price of oil per barrel means that oil consumers have to redirect an additional $960 million dollars each day(!) away from such things as profits, discretionary spending, and debt payments. Instead, that money is sent to the oil producers.  So a future price shock that tacks on an addition $50/bbl to the current price (bringing the total price of oil back over $100/bbl) would translate into $4,800 million ($4.8 billion) per day. That's some $1.7 trillion per year of “redirected spending” that used to go to some other purposes but will now go to oil producers and oil producing nations.  This is why I love quoting Jim Puplava's observation that the price of oil is the new Fed Funds rate.  It has more ability to determine the future of the economy than interest rates.

Factbox: Forecasters offer differing oil outlooks for 2018 -   Three of the most closely watched oil market forecasters have divergent outlooks for next year, especially in terms of demand and the pace of market rebalancing, as seen in their recent monthly reports published earlier this week. The International Energy Agency appeared less cheerful about the prospects for the market balancing in 2018, with a stern warning about growth in supply and demand. "We see that 2018 might not be quite so happy for OPEC producers ... 2018 may not necessarily be a happy new year for those who would like to see a tighter market. Total supply growth could exceed demand growth," the IEA said Thursday. OPEC's statistical arm was not as worried about the supply-and-demand balance, but anticipates much stronger demand for its own crude next year, despite a steady rise in US production. The US Energy Information Administration, in its Short-Term Energy Outlook, was the most optimistic in terms of demand, seeing demand growth of 1.62 million b/d.The IEA continued to maintain a less enthusiastic tone on demand growth for next year at 1.29 million b/d while OPEC's forecast was at 1.51 million b/d. All three expect a steady rise in non-OPEC oil production. led by the US next year. The EIA and IEA expect non-OPEC supply to grow by 1.68 million b/d and 1.60 million b/d, respectively, in 2018. OPEC forecast 990,000 b/d of extra non-OPEC supply to hit the market next year. EIA also forecast that global oil consumption will outpace supply by 370,000 b/d this year, but in 2018, supply will outpace demand by 50,000 b/d. Below are key forecasts for the global oil market from the IEA, EIA and OPEC. The figures are taken from the IEA's Oil Market Report, the EIA's Short-Term Energy Outlook and OPEC's Monthly Oil Market Report, all released earlier this month.

OPEC vs IEA: Who's Right On Oil Prices? -- Last week, the International Energy Agency made a lot of OPEC brows furrow when itwarned that 2018 may not be a very happy new year for the cartel.  U.S. shale supply, the IEA said in its December Oil Market Report, is set to grow more than OPEC has estimated and this could be the undoing of the production cut that boosted prices this year.  OPEC, for its part, has insisted that U.S. shale production won’t grow as much as the IEA says, baffling some observers who now wonder who they should believe.   OPEC has a history of underestimating U.S. shale. This underestimation led to the glut that sank prices in 2014. Now it stands to reason that the cartel is more cautious in its estimates of U.S shale oil developments, but this caution does not necessarily have to be reflected in comments. Let’s not forget that comments from OPEC officials—whether or not grounded in facts—have had a direct and immediate effect on prices from events such as the shutdown of the Forties pipeline network last week.  So, it would make sense to lean more towards what the IEA says, and it says that non-OPEC supply next year will probably rise by 1.6 million bpd—a 200,000 bpd upward revision on the previous OMR. U.S. shale production alone will, according to IEA’s latest estimate, grow by 870,000 bpd in 2018. Meanwhile, demand will rise by 1.3 million barrels daily next year, hinting at another glut in the making.   Now, OPEC’s last forecast is that non-OPEC supply next year will rise by just 990,000 bpd next year to 58.81 million bpd, although the group does caution that any non-OPEC supply growth forecast involves considerable uncertainties regarding U.S. shale production growth. For the U.S. specifically, OPEC forecasts a 1.05-million-barrel daily supply growth next year, which will be partially offset by declines in producers such as Russia, China, and Mexico, among others.  That’s quite a discrepancy between IEA and OPEC figures, but it’s not the only one.The two more notably disagree on when the glut will be over. IEA is skeptical about it disappearing before the end of next year, while OPEC is upbeat, believing the market will return to balance in the second half of 2018 as demand growth accelerates.   Sometimes OPEC’s forecasts sound like developments that the cartel can will into existence, and this market rebalancing forecast is one of these cases. It’s true that some OPEC members have been very diligent in their compliance to the lower production quotas. Others not so much, so those from the first group have actually cut more than they agreed to in order to compensate for the non-compliant ones.

Hedge funds show signs of exhaustion in oil: Kemp - (Reuters) - Hedge fund managers have boosted their bullish positions in Brent futures and options in response to the shutdown of the Forties oil pipeline, according to an analysis of regulatory and exchange data.But bullishness in Brent cannot completely conceal the increasing staleness of long positions in the rest of the rest of the petroleum complex, as prices fail to rise further and the end of year approaches.Portfolio managers raised their net long position in Brent by 10 million barrels to a record 544 million barrels in the week ending on Dec. 12 (http://tmsnrt.rs/2ke0CD4).Long positions in Brent rose by 8 million barrels, which was relatively modest given the complete outage of the Forties pipeline system, while short positions were trimmed by 1 million barrels.But across the five major petroleum contracts as a whole, which include NYMEX and ICE WTI, U.S. gasoline, U.S. heating oil, as well as Brent, the net long position was cut by 3 million barrels.Net long positions in WTI and gasoline were each cut by 8 million barrels with only heating oil up by 3 million barrels.Hedge funds' net long position in gasoline has been cut by 26 million barrels or 26 percent over the last four weeks.There has been no real increase in hedge fund positions in petroleum since the second half of November, as managers become more cautious following the big rise in prices since June.The near-record number of long positions in petroleum has itself become a significant source of downside risk if and when hedge fund managers attempt to realise some profits.Fund managers still hold more than eight long positions in petroleum for every short position, up from a ratio of less than 2:1 at the end of June.In the past, such lopsided positioning has often preceded a sharp reversal in prices when hedge fund managers attempt to crystallise some of their paper gains.

Oil prices rise on ongoing North Sea outage, Nigeria strike  (Reuters) - Oil prices rose on Monday amid an ongoing North Sea pipeline outage and because a strike by Nigerian oil workers threatened its crude exports. Signs that booming U.S. crude output growth may be slowing also supported crude prices, although the 2018 outlook still points to ample supply despite production cuts led by OPEC. Brent crude futures, the international benchmark for oil prices, were at $63.72 a barrel at 0821 GMT, up 49 cents, or 0.8 percent, from their last close. U.S. West Texas Intermediate (WTI) crude futures were at $57.70 a barrel, up 40 cents, or 0.7 percent. The higher prices came on the back of a strike by Nigerian oil workers and the ongoing North Sea Forties pipeline system outage, which provides crude that underpins the Brent benchmark. North Sea operator Ineos declared force majeure on all oil and gas shipments through its Forties pipeline system last week after cracks were found. "The force majeure ... is acting as a major prop for crude," In Nigeria, the Petroleum and Natural Gas Senior Staff Association of Nigeria, whose members mainly work in the upstream oil industry, started industrial action on Monday after talks with government agencies ended in deadlock, potentially hitting the country's production and exports. "Oil prices are getting a bounce... as the Nigerian oil union talks have hit an impasse and will begin strike action," In the United States, energy companies cut rigs drilling for new production for the first time in six weeks, to 747, in the week ended Dec. 15, energy services firm Baker Hughes said on Friday. Despite the dip in drilling, activity is still well above this time last year, when the rig count was below 500, and actual U.S. production has soared by 16 percent since mid-2016 to 9.8 million barrels per day (bpd). This means U.S. output is fast approaching that of top producers Saudi Arabia and Russia, which are pumping 10 million bpd and 11 million bpd respectively. 

US oil benchmark ends slightly lower -- Oil futures saw a mixed finish Monday, with the U.S. benchmark slipping in quiet trade to close in negative territory.West Texas Intermediate crude oil for January delivery the U.S. benchmark, declined 14 cents, or 0.2%, to end at $57.16 a barrel after earlier trading as high as $57.78.Brent oil for February, the global benchmark, gained 18 cents, or 0.3%< to close at $63.41 a barrel.The moves mirrored a mixed session on Friday, when WTI rose 0.5%, but Brent shed 0.1%.,There was no clear catalyst for the turn lower for WTI. Analysts noted that Nigerian oil workers suspended a strike, according to Bloomberg, agreeing to reopen negotations with management next month. Position squaring ahead of the expiration Tuesday of the January WTI contract may have played a role, traders said.U.S. futures had already turned lower when the U.S. Energy Information Administration forecast crude production from seven major shale regions would grow by 94,000 barrels a day in January.The earlier optimism for the U.S. benchmark came after Baker Hughes reported that the number of active U.S. rigs drilling for oil was down 4 at 747 last week, breaking a three-week string of rising rig numbers. A drop in rigs implies a slowdown in drilling activity, which is usually boost oil prices. Brent was underpinned by the closure of North Sea Forties pipeline due to a power outage. “The outage of the North Sea’s most important oil and gas pipeline is continuing to lend support,” analysts at Commerzbank said in a note. “As a result, there is currently a lack of a good 400,000 barrels per day of Forties oil, the leading oil type in the Brent basket. This should preclude any fall in the Brent price for the foreseeable future,” they added. In other energy products on Monday, gasoline rallied 1.1% to $1.6725 a gallon, while heating oil climbed 1.1% to $1.9252 a gallon. Natural gas jumped 5.1% to $2.745 per million British thermal units, rebounding from a nearly 10-month closing low set Friday. The bounce came after forecasts were revised to show much colder than previously expected temperatures across much of the U.S. in the latter part of this month and early January, according to analysts at TFS Energy.

Oil near $57 on expectations of lower crude stockpiles - Houston Chronicle: Oil traded near $57 a barrel for a third day before data expected to show that surplus crude inventories in the U.S. continued to diminish as global markets rebalance. Futures rose 0.7 percent in New York after slipping 0.2 percent on Monday. Inventories probably lost 3 million barrels last week, according to a Bloomberg survey before Energy Information Administration data Wednesday. Nigerian oil workers suspended strike action and agreed to continue talks next month, while output from a Libyan field returned to normal after a power outage. Oil has rallied the past three months as the Organization of Petroleum Exporting Countries and its allies reduce supply to drain a global glut. The unprecedented cooperation among producers, which has now been extended until the end of 2018, has crude prices on their way to a second annual advance. "As long as the agreement between Saudi Arabia and Russia holds to curb production, oil prices will stay in the region of $60," Paolo Scaroni, vice-chairman of NM Rothschild & Sons and former chief executive officer of Eni SpA, said in a Bloomberg television interview on Tuesday. "Oil prices are also OK for the shale-oil producers, which need a price of around $60 if they want to make some money. In total, the situation is stable." West Texas Intermediate for January delivery, which expires Tuesday, added 37 cents to $57.53 a barrel on the New York Mercantile Exchange. Total volume traded was about 52 percent below the 100-day average. The more-active February futures rose 34 cents to $57.56 at 12:58 p.m. in London.

Oil Market On Edge Following Outages - Oil prices initially rose on Monday on news that Nigerian oil workers went on strike, raising fears of a supply outage. The strike was called off, however, leading to a selloff in oil prices. But the lingering outage of the Forties pipeline continues to support Brent prices. Nigeria oil workers’ strike begins…and ends. A union for Nigerian oil workers declared a strike on Monday on demands for improved working conditions went unaddressed, raising questions about supply outages in the African nation. Last year, a strike at an ExxonMobil (NYSE: XOM) project temporarily idled more than 500,000 bpd. This week’s strike affected workers at dozens of oil companies. However, the strike was also called off on Monday as talks seemingly started to get somewhere, although details remain sparse. The issue is important for the global oil market – an outage at a major oil producing country could lead to sharply higher prices, particularly with the market making substantial progress at lowering inventories. The EIA’s Drilling Productivity Report predicts a rise of 94,000 bpd in U.S. oil supply in January, compared to December. The gains will be led by the Permian Basin with a 68,000-bpd increase, with smaller contributions from other shale plays. The estimate shows that U.S. shale (the Permian, mostly) is still growing strongly. Western Canada Select prices have melted down this month, as rising supply is bumping up against a lack of pipeline infrastructure. WCS normally trades at a discount to WTI, often by $10 to $15 per barrel, but the discount widened sharply to as much as $28 per barrel in the last week. Alberta oil producers are suffering from this steep discount, and although crude is increasingly moving by rail (for a heftier fee), rail companies cannot entirely resolve the issue. Rail companies don’t want to make investment decisions that could span decades for a problem that might only last a few years. With new pipeline capacity a few years away at least, the steep discount for Canadian oil could linger for a while. The capacity shortage is expected to grow worse – Canada’s oil sands will add 315,000 bpd of new supply in 2018 and 180,000 bpd in 2019.

Oil Gains as Pipeline Outage Continues | Fox Business: Oil prices rose Tuesday, helped in part by the continuing outage of a North Sea pipeline and reports that Russia's largest oil company could envision continuing production curbs past 2018. U.S. crude futures traded up 30 cents, or 0.52%, at $57.46 a barrel on the New York Mercantile Exchange. Brent, the global benchmark, rose 39 cents, or 0.62%, to $63.80 a barrel on ICE Futures Europe. Russian oil giant PAO Rosneft is "contemplating cuts beyond 2018, which is probably supporting things a bit," said Thomas Pugh, commodities economist at Capital Economics. The Organization of the Petroleum Exporting Countries and 10 producers outside the cartel, including Russia, agreed late last month to extend an accord to hold back nearly 2% of crude production through the end of 2018. The deal, first agreed a year ago, was meant to rein in a global supply glut that has weighed on prices since 2014. Pavel Fedorov, PAO Rosneft's first vice president, reportedly said that an OPEC-led agreement to curb crude output "could be extended" after it expires at the end of next year, according to Reuters. Oil prices have also been propped up since the closure of the Forties Pipeline System in the North Sea last week. The outage, which could last for weeks, stops the flow of around 450,000 barrels of North Sea oil a day.

WTI/RBOB Extend Gains After Bigger Than Expected Crude Draw -- WTI/RBOB inched higher on the day ahead of tonight's API data and then WTI knee-jerked higher as the data showed a much-bigger-than-expected 5.2mm crude draw.API

• Crude -5.2mm (-440k exp)
• Cushing +70k
• Gasoline +2.001mm (+2.45mm exp)
• Distillates -2.85mm (+250k exp)

A very mixed bag as the series of crude draws continues and gasolines builds... “Export numbers have definitely been stronger than anything we’ve seen in recent history,” says Brad Hunnewell, senior equity analyst at Rockefeller. “That’s going to be an important driver to watch.” WTI/RBOB prices had lifted into the API print buit the machines got very confused as the data hit with RBOB dropoping before joining crude higher...

Brent prices caught in the calm before the storm? Kemp (Reuters) - Crude oil traders have started to price in the resumption of North Sea shipments on the Forties pipeline, with spot prices stalling and nearby calendar spreads returning to levels before the pipeline was shutdown.Pipeline owner Ineos is working on several repair options and said it expects operations to resume within 2-4 weeks of the original shutdown on Dec. 11 ("Ineos awaiting custom parts to fix Forties oil pipeline", Reuters, Dec. 19). Brent futures for delivery in February have eased back to under $64 per barrel from a high of almost $66 immediately after the shutdown, and are no higher than they were at the start of November.The February-March calendar spread has shrunk to just 31 cents backwardation from a peak of nearly $1 per barrel, and is almost back to where it was before the rupture (http://tmsnrt.rs/2z3ZeHS).Calendar spreads for the first six months have continued to tighten, but in line with the pre-shutdown trend, and now show little impact from the disruption.The strong and consistent rally in crude and products prices between the end of June and early November appears to have petered out, at least for the time being.Hedge funds and other money managers are sitting on a record bullish position in Brent futures and options and a near-record position in crude and products derivatives more generally.But with the exception of Brent, there has been no significant advance in positions in U.S. crude, gasoline and heating oil, as well as in European gasoil since the second half of November.In fact, hedge funds have lightened their bullish positions in WTI, gasoline and European gasoil since the end of last month, as fund managers have taken some profits after the rally. The build up of a massive bullish long position in oil and the limited number of short positions that remain to be covered as itself become a major risk to prices.

WTI/RBOB Algos Confused As Crude Draws, Gasoline Builds, & Production Jumps Again --WTI/RBOB held gains overnight following API's reported crude draw (despite the gasoline glut) but after DOE confirmed a 5th weekly crude draw and 6th weekly gasoline build, algos were confused with prices chaotic. Production hit a new record high.North Sea and Canadian crude supply disruptions are suppressing U.S. imports and encouraging exports. DOE:

• Crude -6.5mm (-3.15mm exp)
• Cushing +754k
• Gasoline +1.24mm (+2.3mm exp)
• Distillates +769k (+250k exp)

This is the 5th weekly draw in crude in a row (and sixth weekly build in gasoline), perhaps the unexpected build in Distillates is spooking markets...  Bloomberg Intelligence energy analyst Fernando Valle: Heightened U.S. refinery utilization is shifting the supply glut from crude inventories to refined products, particularly gasoline. Exports have risen, but are not enough to offset higher production and a seasonal demand slowdown.Distillate demand, on the other hand, is rising, domestically and abroad.Crack spreads have stayed near $20 a barrel since Hurricane Harvey, which may lead refiners to shift gasoline yield toward distillates. Total crude inventories are the lowest since Oct 2015 (but as is clear remain well elevated from old norms)...

What Will Drive The Next Oil Price Crash? - As we roll into 2018, analysts and investors are more optimistic that the oil market will further tighten next year and support higher oil prices, but rising U.S. shale production will likely cap any significant price gains.  On the demand side, expectations are that global economic growth will support solid oil demand growth.  On the supply side, Venezuela’s dire situation, possible new sanctions on Iran, and increased tension in the Middle East mostly with the Saudi-Iran issues and the Iraq-Kurdistan standoff may take more barrels off the market than OPEC and friends plan, and send geopolitical jitters through the oil market. However, according to energy policy expert Michael Lynch, there remain three potential events in the markets that could send oil prices tumbling. These include a large correction in the U.S. stock market that could spread to a sell-off in commodities; one of the OPEC members or Russia breaking away from the unusually strong compliance to the cuts we have seen so far; and U.S. oil production rising so much as to make OPEC see it as a threat to its long-term oil market share. In markets, there are already some signs that we may be seeing some bubbles,Bitcoin being the most likely candidate, according to Lynch. In addition, the price to earnings ratio of the S&P 500 index is now over 25, well above the mean historical average of just over 15. Last week, Fed Chair Janet Yellen said, referring to the high valuation in some asset classes, “the fact that those valuations are high doesn’t mean that they are necessarily overvalued.” According to VTB Capital’s Global Macro Strategist Neil MacKinnon, the ultra-low volatility in U.S. equities this year is “very vulnerable” to shocks, and current stability could actually bring future instability.According to Lynch, if the U.S. market moves into bear territory next year with a big correction, it could spread the financial contagion to commodities such as oil. Another potential threat to oil prices is that of an OPEC/non-OPEC pact participant beginning cheating outright—Iraq and Russia, for example—which could lead to the Saudis deciding to let the price of oil drop, Lynch argues.

Oil Prices Rise After Strong Crude Inventory Draw - The Energy Information Administration reported yet another inventory draw for last week, making it the fifth one in a row with falling inventories. The authority said inventories had gone down by 6.5 million barrels, to 436.5 million barrelsAnalysts had expected a draw of 4.5 million barrels, more modest than API’s latest estimate that pegged crude oil inventories 5.2 million barrels lower last week.Yet traders are not only watching crude oil inventory movements: gasoline stockpiles last week jumped by 1.2 million barrels, the EIA said. This could dampen the bullish mood among market participants, though not by much as there are other events speculators are watching, such as the growth in U.S. shale production and international politics. Last week the bullish bets on WTI stood at a nine-month high, data from CFTC showed.Refineries processed 17.1 million barrels of crude per day last week and produced 10.1 million barrels per day of gasoline, unchanged from the week before.Interestingly, as inventories have been falling over the past five weeks, production of crude oil in the United States has been growing. The daily rate reached 9.78 million barrels in the week to December 8, from 8.95 million bpd at the start of the year. All forecasts point to a consistent further increase in U.S. production, which may well undermine OPEC and Russia’s production cut efforts. Meanwhile, WTI has been benefitting by the Forties pipeline shutdown, although the shutdown’s impact on Brent, the international benchmark, has been more pronounced. Earlier this week, Ineos, the operator of the pipeline, said the shutdown could last for a month as custom parts needed to be made. According to Bloomberg, the shutdown could take some 5.5-13 million barrels from global oil markets for the duration.

Oil prices stable on lower US crude stocks, but rising output weighs - Oil prices were stable on Thursday after posting strong gains late in the previous session on the back of a drop in US crude inventories.Another rise in US oil production, which is close to breaking through 10 million barrels per day (bpd) is capping crude prices as it undermines efforts led by the Organization of the Petroleum Exporting Countries (OPEC) and Russia to tighten the market through withholding output this year and next.US West Texas Intermediate (WTI) crude futures were at $58.05 a barrel at 0126 GMT, down 3 cents from their last settlement. Brent crude futures, the international benchmark for oil prices, were at $64.58 a barrel, down 8 cents.   Both crude benchmarks gained around 1 per cent during the previous session. Traders said falling US crude oil inventories were supporting the market. US crude inventories fell by 6.5 million barrels in the week to December 15, the Energy Information Administration (EIA) said on Wednesday. Overall crude stocks, excluding the US Strategic Petroleum Reserve, fell to 436 million barrels, the lowest since October, 2015.The rebalancing of supply and demand is a result of OPEC and Russian led voluntary production cuts. Despite this, the energy minister of Saudi Arabia, the world's top crude exporter and OPEC's de-facto leader, said it would take more time to rein in the global supply overhang, which was created by strong global production increases in the years up to 2015.

OPEC starts working on oil supply cut exit strategy: sources (Reuters) - OPEC has started working on plans for an exit strategy from its deal to cut supplies with non-member producers, two OPEC sources said, a sign that an eventual winding down of the deal is coming onto producers’ radar, at least in theory. The Organization of the Petroleum Exporting Countries, Russia and other non-OPEC producers on Nov. 30 extended an oil output-cutting deal until the end of 2018 to finish clearing a glut. But the market is increasingly interested in how producers will exit the deal once the excess is cleared. Two OPEC sources said the group’s secretariat in Vienna has been tasked to work on a plan with different options and it was too early now to say what the plan would look like. “It’s a continuity strategy, rather than exit,” one of the OPEC sources said. Oil prices have rallied this year and are trading near $64 a barrel, close to the highest since 2015, supported by the OPEC-led effort. This is above the $60 floor that sources say OPEC would like to see in 2018. Publicly, OPEC ministers say it is too early to talk of an exit strategy. But OPEC has said producers want to continue working together beyond the end of 2018, including on supply management. While oil prices have risen to levels seen as favorable by OPEC, the stated goal of the supply cut is to reduce inventories in developed economies, which built up after a supply glut emerged in 2014, to the level of the five-year average. OPEC is making progress and said in October OECD inventories stood 137 million barrels above the five-year average. Since the start of deal in January, the overhang relative to that average is down by 200 million barrels, Kuwait’s oil minister said on Wednesday. [OPEC/M] A discussion on exiting the deal may be needed before December 2018 if, as OPEC expects, the world oil market returns to balance by late 2018. OPEC and its allies hold their next full ministerial meeting in June, which will be a opportunity to review progress. 

Brent up to 2015 high on hopes OPEC will not end supply cuts abruptly - Brent oil prices edged up enough on Thursday to close at the highest since the summer of 2015 as OPEC started working on plans for an exit strategy from its deal to cut crude supplies, fueling hopes it would not end supply cuts abruptly. The Organization of the Petroleum Exporting Countries, Russia and other non-OPEC producers on Nov. 30 extended an oil output-cutting deal until the end of 2018 to finish clearing a glut. But the market is increasingly interested in how producers will exit the deal once the excess is cleared. urn:newsml:reuters.com:*:nL8N1OK2O6 Two OPEC sources said the group's secretariat in Vienna has been tasked to work on a plan with different options and it was too early now to say what the plan would look like. "Fading prospects for a hard exit from the (OPEC) deal has provided some support to prices," said Abhishek Kumar, Senior Energy Analyst at Interfax Energy's Global Gas Analytics in London, noting global oil markets were expected to be volatile next year as details pertaining to an exit strategy emerge. Brent futures LCOc1 gained 34 cents, or 0.5 percent, to settle at $64.90 a barrel, while U.S. West Texas Intermediate crude CLc1 rose 27 cents, or 0.5 percent, to settle at $58.36 per barrel. That was the highest close for Brent since June 2015 and for WTI since Nov. 24. Earlier Thursday, crude prices were trading down after the operator of Britain's Forties pipeline in the North Sea said it was expected to restart in early January after repairs over Christmas.

Forties Pipeline System Repairs Scheduled to Complete by Christmas - Ineos revealed Thursday that repair work on the Forties Pipeline System (FPS) is scheduled to complete around Christmas, based on current estimates. The company expects to bring the pipeline progressively back to normal rates early in the new year and has already initiated the planning phase necessary to begin recommissioning the system. “Ineos continues to work with the emergency services, relevant authorities and regulators as it implements the code compliant repairs on the FPS pipeline,” Ineos said in a company statement. “We apologize to our customers and the local community for the issues that this creates and we are working hard to minimize the impact of the pipeline closure as far as possible,” Ineos added. A controlled shutdown of the FPS was implemented on December 11, after a hairline crack was found in the system at Red Moss, south of Aberdeen. Earlier this month it was revealed that independent oil and gas firms EnQuest plc and Premier Oil plc could lose millions of dollars in the event of a prolonged shut down of the FPS. 

UK's Forties North Sea oil pipeline should fully restart in early Jan -Ineos (Reuters) - One of the biggest and most important oil pipelines in the North Sea, Britain’s Forties pipeline, should restart in early January after repairs of a crack over Christmas, the pipeline’s operator Ineos said on Thursday. “Work on the pipeline is progressing well and based on current estimates Ineos is planning to complete the repair around Christmas,” it said in a statement. “Ineos has initiated the planning phase necessary to begin recommissioning the system, including the Kinneil facility, as soon as the pipeline repair is complete.” ”Initially a small number of customers will send oil and gas through the pipeline at low rates as part of a coordinated plan that allows Ineos to carefully control the flow into the system. “Based on current estimates the company expects to bring the pipeline progressively back to normal rates early in the new year,” Ineos said. 

OilPrice Intelligence Report: Christmas Brings Quiet To The Oil Markets: Oil prices were flat amid light trading at the end of the week after strong gains on Thursday. The EIA reported some mixed figures – more strong oil production gains from the U.S., but also a sizable drawdown in crude inventories. The approaching holidays has the market subdued.  Saudi oil minister Khalid al-Falih told Reuters that the inventory surplus will be eliminated in the second half of 2018, and the earliest date to reassess the market will be at the OPEC meeting in June. And while the IEA has forecasted strong supply growth next year from U.S. shale, al-Falih says demand will help drive the market towards rebalancing. “[T]he untold story is demand. Demand has been extremely healthy in the last couple of years. 2017 will prove to be a very robust year in terms of demand and we expect that momentum to continue,” al-Falih said. Separately, Reuters reported that OPEC has quietly started working on an exit strategy behind the scenes, and the group will reportedly consider several options. “It’s a continuity strategy, rather than exit,” one of the OPEC sources told Reuters. The operator of the Forties pipeline system, Ineos, said that the pipeline will be repaired by Christmas and will restart operations by January. “Based on current estimates the company expects to bring the pipeline progressively back to normal rates early in the new year,” Ineos said.  CEO Bob Dudley told the FT that he isn’t worried about shale threatening conventional oil producers in the long-term. He argued that shale won’t be able to grow forever, so the threat to permanently low oil prices is not as big as most people think. “There are cracks appearing in the model of the Permian being one single, perfect oilfield,” he said. Over the long run, that could diminish shale’s importance. “I don’t think [U.S. shale] will be the perfect swing producer now,”

Oil Prices Stable On Flat Oil Rig Count - The number of active oil and gas rigs rose this week, according to Baker Hughes data, increasing by 1 rig, for a total of 931 rigs currently in operation in the United States—278 rigs above this time last year.The number of oil rigs in the U.S. stayed the same, while the number of gas rigs climbed by 1. The number of oil rigs stands at 747 versus 523 a year ago. The number of gas rigs in the U.S. now stands at 184, up from 129 a year ago.For Canada’s part, the number of oil and gas rigs fell hard, by 28 rigs, with gas and oil rigs each falling by 14.At 1:00pm EST, the price of a WTI barrel was down $0.11 (+0.19 percent) to $58.25, while the Brent barrel was trading up $0.16 (-0.11 percent) to $64.50. Prices had come off a previous years-ago high earlier on Friday, as rising US output and news surfaced that Forties will be back up and running at normal capacity in early January.The hotspot Permian Basin gained one rig for the week, but things are looking up for the Permian, as Kinder Morgan announced on Thursday that, with its partners, it will go ahead with its $1.7 billion gas pipeline project that will alleviate existing bottlenecks that prevent more gas from flowing out of the basin.US crude oil production continues to climb a weekly basis, placing further pressure on prices. U.S. crude oil production for the week ending December 15 was 9.789 million barrels per day—another record for 2017, and the ninth straight weekly increase.  At 1:06pm EST, WTI was trading at $58.26 with Brent trading at $64.49.

U.S. oil extends win streak to 4 days as rig count remains stable - Oil futures erased modest losses Friday to end with gains after data showed the number of U.S. oil rigs remained steady this week. West Texas Intermediate crude for February delivery on the New York Mercantile Exchange rose 11 cents, or 0.2%, to settle at $58.47 a barrel. The U.S. benchmark posted a 2% rise for the week, marking its first weekly gain in three weeks. February Brent crude , the global benchmark, rose 35 cents, or 0.5%, to end at $65.25 a barrel, marking a 3.2% weekly advance. Volume was light ahead of the Christmas holiday on Monday. The gains saw WTI futures extend a win streak to four sessions, while Brent has risen for five straight. Read:When do financial markets close for Christmas? (http://www.marketwatch.com/story/when-do-financial-markets-close-for-christmas-2017-12-20) Baker Hughes said the number of U.S. oil rigs was unchanged at 747 this week. Traders are keeping an eye on the count amid concerns shale producers could move to ramp up production next year in response to higher prices. That said, it was the shutdown of the Forties Pipeline System in the North Sea that was the main focus for oil traders this week. The pipeline was shut down last week after operator Ineos discovered a hairline crack in a pipe, stopping the flow of 450,000 barrels of North Sea oil a day. That tightening of supply had buoyed prices over the past week. But Ineos said Thursday it expects to bring pipeline flows "progressively back to normal rates" early in the New Year. "Doing the simple arithmetic, if the pipeline restarts on 1 January, the outage will have resulted in a loss of 8.4 [million barrels] (21 days at 400,000 barrels a day); if the pipeline restarts on 8 January, the outage will be 11.2 Mb (28 days at 400 kb/d). The actual number will depend not only on the dates and the pipeline, but also on the pace of ramp-up of the oil fields themselves," which doesn't alwasy go smoothly, said Societe Generale oil analyst Michael Wittner, in a Friday note. Crude prices have risen more than 20% since September, as a result of renewed geopolitical risk to supply in the Middle East, declining global inventories and OPEC's ongoing efforts to curb production.

Saudi energy minister: Premature to discuss changes in OPEC-led pact (Reuters) - Saudi Arabia’s energy minister said it is premature to discuss any changes to the OPEC-led supply cut pact as market rebalancing is unlikely to happen until the second half of 2018 even with the current outage of the North Sea Forties pipeline. Any potential exit from current cuts would be done gradually once the market returns to balance but drawing down inventories will still take more time, Khalid al-Falih told Reuters on Wednesday. “We haven’t seen any major declines in inventories that we didn’t expect. As we said last month, we still have approximately 150 million barrels of overhang, and it is going to take the second half 2018 to draw that down,” Falih said. “We expect the first few months of 2018 to be either flat or a build (in inventories) as it is typically the case with the seasonality with the oil market especially on the demand side,” he said in an interview in Riyadh. “So I think it is premature to discuss any potential changes in our course, and the earliest opportunity to assess where the market is in a major way would be in June.” OPEC and 10 other producers led by Russia last month extended an agreement to cut oil production by 1.8 million bpd until the end of next year. The alliance is targeting the elimination of an oil glut to bring global oil inventories back to the industry’s five-year average. Crude prices firmed on Wednesday, supported by a larger-than-expected drop in U.S. inventories and the continued outage of Britain’s North Sea Forties pipeline system. Falih, who holds the OPEC presidency this year, said he does not expect the shutdown of the key North Sea pipeline to affect supply significantly. 

Saudi Economy Contracts For First Time In 8 Years, Unveils Record Spending Spree To Boost Growth --Back when oil was at $100 and above, the Saudi economy was firing on all cylinders, and nobody even dreamed that the crown jewel of Saudi Arabia - Aramaco - would be on the IPO block in just a few years. However, with oil stuck firmly in the $50 range, things for the Saudi economy are going from bad to worse, and today Riyadh - when it wasn't busy preventing Yemeni ballistic missiles from hitting the royal palace - said its economy contracted for the first time in eight years as a result of austerity measures and the stagnant price of oil, as the Kingdom announced record spending to stimulate growth. OPEC's biggest oil producer said 2017 GDP shrank 0.5% due to a drop in crude production, as part of the 2016 Vienna production cut agreement, but mostly due to lower oil prices. The last time the Saudi economy contracted was in 2009, when GDP fell 2.1% after the global financial crisis sent oil prices crashing. Riyadh also posted a higher-than-expected budget deficit in 2017 and forecast another shortfall next year for the fifth year in a row due to the drop in oil revenues: the finance ministry said it estimates a budget deficit of $52 billion for 2018. More surprising was the Saudis announcement of a radically expansionary budget for 2018,projecting the highest spending ever despite low oil prices in a bid to stimulate the sluggish economic, saying it expects the GDP to grow by 2.7%. While we wish Riyadh good luck with that, we now know why confiscating the wealth of ultra wealthy Saudi royals was a key component of the country's economic plan...

Saudi Arabia Sees Non-Oil Economy Rebounding on State Spending - Saudi Arabia Arab expects its economy to rebound in 2018, a crucial year for Prince Mohammed bin Salman’s blueprint for the post-oil era, as authorities ease an austerity drive that hurt growth. The non-oil economy, the engine of job creation in the kingdom, is expected to grow “north of 3 percent,” Finance Minister Mohammed Al-Jadaan said in an interview with Bloomberg TV in Riyadh on Tuesday. That’s twice the 2017 rate. After two years of austerity, Saudi officials rolled out plans that seek to balance the need to rebuild state coffers while avoiding crippling private businesses. An expanding economy could make it easier to advance key elements in the prince’s long-term plan in 2018, including selling a stake in state-run oil giant Aramco to help create the world’s largest sovereign wealth fund. The government plans to raise total spending to 1.1 trillion riyals ($293 billion) from 926 billion in 2017. The increase will help counter revenue-boosting measures, such as the introduction of value-added taxation and a levy paid by companies on expat workers. Overall growth is expected to rebound to 2.7 percent after lower oil prices drove a 0.5 percent contraction in 2017.

Mohammed bin Salman’s ill-advised ventures have weakened Saudi Arabia’s position in the world - Crown Prince Mohammed bin Salman (MbS) of Saudi Arabia is the undoubted Middle East man of the year, but his great impact stems more from his failures than his successes. He is accused of being Machiavellian in clearing his way to the throne by the elimination of opponents inside and outside the royal family. But, when it comes to Saudi Arabia’s position in the world, his miscalculations remind one less of the cunning manoeuvres of Machiavelli and more of the pratfalls of Inspector Clouseau. Again and again, the impulsive and mercurial young prince has embarked on ventures abroad that achieve the exact opposite of what he intended. When his father became king in early 2015, he gave support to a rebel offensive in Syria that achieved some success but provoked full-scale Russian military intervention, which in turn led to the victory of President Bashar al-Assad. At about the same time, MbS launched Saudi armed intervention, mostly through airstrikes, in the civil war in Yemen. The action was code-named Operation Decisive Storm, but two and a half years later the war is still going on, has killed 10,000 people and brought at least seven million Yemenis close to starvation. The Crown Prince is focusing Saudiforeign policy on aggressive opposition to Iran and its regional allies, but the effect of his policies has been to increase Iranian influence. The feud with Qatar, in which Saudi Arabia and the UAE play the leading role, led to a blockade being imposed five months ago which is still going on. The offence of the Qataris was to have given support to al-Qaeda type movements – an accusation that was true enough but could be levelled equally at Saudi Arabia – and to having links with Iran. The net result of the anti-Qatari campaign has been to drive the small but fabulously wealthy state further into the Iranian embrace. Saudi relations with other countries used to be cautious, conservative and aimed at preserving the status quo. But today its behaviour is zany, unpredictable and often counterproductive: witness the bizarre episode in November when the Lebanese Prime Minister Saad Hariri was summoned to Riyadh, not allowed to depart and forced to resign his position. The objective of this ill-considered action on the part of Saudi Arabia was apparently to weaken Hezbollah and Iran in Lebanon, but has in practice empowered both of them. What all these Saudi actions have in common is that they are based on a naïve presumption that “a best-case scenario” will inevitably be achieved. There is no “Plan B” and not much of a “Plan A”: Saudi Arabia is simply plugging into conflicts and confrontations it has no idea how to bring to an end.   

Saudi Government Seeks "Amicable Exchange" - $6 Billion For al-Waleed's Freedom -- In case you were wondering what the going-rate was for one of the world's richest men's freedom... it's $6 billion... in unencumbered cash (not Bitcoin). That is the price that Saudi authorities are demanding from Saudi Prince al-Waleed bin Talal to free him from detention. The 62-year-old prince was one of the dozens of royals, government officials and businesspeople rounded up early last month in a wave of arrests the Saudi government billed as the first volley in Crown Prince Mohammed bin Salman’s campaign against widespread graft.According to the Mail, al-Waleed, who is (or was, until recently) one of the richest men in the world, has also been hung upside down and beaten. The Saudi government has disclosed few details of its allegations against the accused,but as The Wall Street Journal reports, people familiar with the matter said the $6 billion Saudi officials are demanding from Prince al-Waleed, a large stakeholder in Western businesses like Twitter, is among the highest figures they have sought from those arrested.While the prince's fortune is estimated at $18.7 billion by Forbes - which would make him the Middle East’s wealthiest individual - he has indicated that he believes raising and handing over that much cash as an admission of guilt and would require him to dismantle the financial empire he has built over 25 years.Prince al-Waleed is talking with the government about instead accepting as payment for his release a large piece of his conglomerate, Kingdom Holding Co., people familiar with the matter said. The Riyadh-listed company’s market value is $8.7 billion, down about 14% since the prince’s arrest.

Saudi Arabia's Crown Prince, who is leading a crackdown on corruption, bought the world's priciest home -- Saudi Arabia's Crown Prince Mohammed bin Salman has been revealed to be the owner of the world's priciest residence.  The extravagant Chateau Louis XIV sold in 2015 to an unnamed Middle Eastern buyer for over $299 million, making it the most expensive residence in the world at the time — and Salman acquired the 57-acre estate through a Saudi-owned investment company managed by his personal foundation, The New York Times reported, citing documents and interviews.  The Times reported that the chateau was purchased through a series of proxy companies in France and Luxembourg, allowing Salman to maintain his anonymity. Those companies are owned by Eight Investment Company, a firm managed by the head of Salman's personal estate, according to the report.  Advisers to the royal family say the megamansion belongs to Salman, the report says.  The villa is part of a series of high-scale acquisitions for Salman, including a $500 million yacht and a luxury vacation palace in Morocco.  The lavish chateau, near the Palace of Versailles, was constructed over three years by Cogemad, an ultraluxury developer.

Saudis Intercept Houthi Ballistic Missile Targeting Riyadh Royal Palace -- For the third time in roughly seven weeks, Houthi rebels have fired a ballistic missile at the Saudi capital of Riyadh, according to a spokesperson. This time, the target was al-Yamamah palace in the Saudi capital. US President Donald Trump notably held meetings with the Saudi king at the al-Yamamah palace during his May trip to the kingdom. Witnesses in Riyadh reported hearing a blast and seeing a plume of smoke. Saudi security officials did not immediately comment on the incident, according to Haaretz.Loud boom heard in central Riyadh -- big enough that we felt it shake our tower. No official statement on cause yet. We're looking into it. #???_??????_??_??????— Vivian Nereim (@viviannereim) December 19, 2017 Houthis launched two ballistic missiles at Saudi Arabia in November, but neither hit their targets. One was reportedly fired at King Khalid International Airport in Riyadh while the other was fired at a Saudi oil refinery.According to Russia Today, the Saudi-led coalition that has been battling the rebels in Yemen has reportedly shot down the missile, according to Russia Today. Saudi state TV claimed the missile – a Burkan 2H ballistic missile - was intercepted by Saudi defenses…

The Fight For Syria's Last Al Qaeda Holdout: Russian Jets Launch Nonstop Airstrikes Over Idlib -- The Russian Aerospace Forces launched a large number of airstrikes over the southern countryside of the Idlib Governorate overnight on Thursday, targeting the positions of Hayat Tahrir Al-Sham (HTS/al-Nusrah) around the town of Abu Dali. Russian jets flying out of the Hmaymim Military Airbase began their attack by launching airstrikes over the towns of Abu Dali and Musharifah. Not long after launching this attack, the Syrian Army was able to overwhelm the jihadist rebels of Hayat Tahrir Al-Sham that were attempting to defend the town; they would then retreat before their entire front-line collapsed. Momentum against the al-Qaeda insurgents began early this week when the Syrian Arab Army (SAA) scored a new advance in the southeastern countryside of Idlib, capturing a small town that was under jihadist control. Led by elements of the Republican Guard and 4th Mechanized Division, the SAA stormed the town of Al-Ruwaida on Monday, striking the jihadist defenses from its southern flank. With this latest advance in southeast Idlib, the Syrian Army has managed to establish a strong presence in this once jihadist dominated province in northern Syria. At the same time, elsewhere in Syria thousands of people gathered in Saadallah al-Jabiri square in Aleppo on Thursday to join a military parade marking one-year since the Syrian government retook the city. The military were greeted by many of the city’s residents carrying pro-government banners and images of President Bashar al-Assad.

The Ultimate In Irony: Syrian Army Rolls Into Idlib With US Weapons Captured From ISIS -- The Syrian Arab Army’s (SAA) Tiger Forces arrived in northern Hama this week with a big surprise from their previous operations in the Deir Ezzor Governorate. Units from the Tiger Forces were seen armed with US-manufactured weapons that were seized from the Islamic State (ISIS) during the two month long battle in Deir Ezzor. According to a military source in Hama, the Syrian Army’s Tiger Forces are planning to use the US-manufactured weapons against the jihadist rebels in the upcoming battle for the Idlib Governorate. Among the US-manufactured weapons transferred to the Idlib front were a large number of TOW missiles that were previously supplied by Washington to the rebel forces in Syria before they were later sold to the Islamic State. The rapid defeat of Islamic State forces in eastern Syria over the last several months has seen the Syrian Arab Army capture untold quantities of military equipment from the terrorist group, most of which will likely go into the raising of new pro-government formations. As Syrian pro-government forces chased ISIS out of its main strongholds along the western shore of Euphrates River, the jihadist faction never had the time to re-locate its weapons stockpiles. The inevitable result of this was that such stockpiles came into the possession of the Syrian Army. As video evidence has shown time and time again, the vast loot accumulated thus far comprises not only small arms, but also heavy weapons including mortars, howitzers, field guns, technicals, armored personnel carriers, main battle tanks and guided missiles.

Chinese companies poised to help rebuild war-torn Syria - China is turning towards the Middle East and is ready to play a major role in helping to rebuild war-torn Syria. The world’s second biggest economy has already pledged US$2 billion for reconstruction work at the aptly-named First Trade Fair on Syrian Reconstruction Projects in Beijing. “China appears determined to take on a central role,” said Dr Gideon Elazar a lecturer at Bar-Ilan University in Tel Aviv and a post-doctoral fellow at Ben-Gurion University, specializing in Asian Studies. “One factor motivating the country’s involvement is the One Belt-One Road Initiative – a planned attempt to establish and control a modern day Silk Road connecting China, the Middle East and Europe. This might mark a shift in the geo-strategic reality of the region,” he added. Beijing already has strong ties with President Bashar al-Assad and sees a golden opportunity on the horizon now that Syria is edging towards peace after a brutal civil war. More than 30 Chinese companies, including infrastructure construction giants China Energy Engineering Corporation and China Construction Fifth Engineering Division, are reported to have visited the country this year. The main topic of discussions with provincial governors was major infrastructure projects. “With the gradual collapse of ISIS and the impending conclusion of the Syrian civil war, it is becoming clear that China will (have a crucial part to play),” Elazar said. “Indeed, its involvement in Syria has been on the rise over the past several months.” 

Chinese officials point fingers as gasification crisis worsens (Reuters) - When an inspector from a local environmental protection bureau visited a small village in China’s Shandong province in October to check on a gasification project, she said village officials became tearful in lamenting how far behind schedule they were. For years, the village has been haunted by pollution from nearby coal mines and chemical plants. The village had been rushing to finish installing new gas boilers for residents as they ditched their old coal stoves, the inspector told Reuters. The boilers are part of an ambitious gasification program under which millions of households, and some industrial users, are switching from coal to natural gas for heating, as Beijing tries to clean the tainted air in northern China after decades of galloping growth. The effect of the dramatic switch has been felt globally, with internationally shipped gas prices almost doubling this year to more than $10 per million British thermal units, the highest since the end of 2014. It has also been felt locally due to poor coordination among government bodies and gas producers, and miscalculations in demand, which have sent gas prices soaring, left many residents freezing in their homes, and shuttered factories. Where there is gas supply, it cannot reach homes in some cases as the replacement gas infrastructure has not been installed. “Everyone’s job is linked to whether we can meet the target,” the environmental protection inspector said, declining to be named and refusing to identify the village due to sensitivity of the matter. In China, policy targets are trickled down to the village official level with the objectives generally understood to be the minimum to be achieved. “If we did not meet the target, we will get bad performance reviews and we will start worrying about our careers,” the inspector said. She declined to specify the targets. 

Ships in a bottleneck: China, Australia ports clogged as coal, iron ore demand soars (Reuters) - More than 300 large dry cargo ships are having to wait outside Chinese and Australian ports in a maritime traffic jam that spotlights bottlenecks in China’s huge and global commodity supply chain as demand peaks this winter. With some vessels waiting to load coal and iron ore outside Australian ports for over a month, key charter rates have jumped to their highest in more than three years. Placed end-to-end, the total delayed fleet would stretch more than 40 miles, enough to span the English Channel from Dover to Calais and back. As well as choking supplies to the world’s second-biggest economy, the clog is costing extra in a shipping sector operating on tight margins, just as it recovers from its worst downturn in more than three decades. Charterers of capesize ships - the largest bulk dry cargo carriers - face paying an extra $1 million per vessel, assuming a 45-day wait, according to fixture data on the Reuters Eikon terminal. “There are some ports in east Australia that have 80 vessels anchored, which translate into 20-25 days of delay and congestion,” said Ziad Nakhleh, managing director of Greek ship owner Teo Shipping. Shippers and brokers said the delays were typical, especially during the peak demand winter season, as bad weather including fog and strong winds in China and infrastructure issues in Australia exacerbate increased demand for vessels to satisfy China’s soaring minerals appetite.  Australian ports affected include Queensland export terminals at Hay Point and Dalrymple Bay, where there are 76 capesize and panamax vessels - named for being the largest size than can navigate the Panama Canal - waiting to load, according shipping data in Thomson Reuters Eikon.