US oil refining at an all time high, topping previous year's summertime records...

based on recommendations from an OPEC panel meeting last Friday and statements from the major producers, it's now broadly accepted that OPEC will be extending their production cuts after June, although that won't be made official till they meet on May 25th....with that as a given, oil traders have turned their attention to recent oil supply and shipment data, and found that global oil supplies remain adequate and shipments of oil continue to set new records, and they’ve thus deemed the OPEC production cuts we've seen so far to be ineffective...as a result, oil again traded lower this week, ending down another 29 cents a barrel, after last week's $3.98 a barrel, 7.4% plunge....

after opening higher on Monday, US crude for June delivery fell after a report that Russian oil output might climb to its highest rate in 30 years if the OPEC and non-OPEC producers did not agree extend their cuts, and closed at $49.23 a barrel, down 39 cents from last Friday's close....prices then edged up in choppy trade on Tuesday in anticipation of the weekly American Petroleum Institute and EIA oil inventory reports, which were expected to show a third consecutive weekly draw of around 1.6 million barrels, with U.S. June futures closing 33 cents higher at $49.56 a barrel, their first increase in 7 trading days....with the API report showing a smaller than expected decrease in supplies, oil prices opened lower on Wednesday morning, but then spiked to as high as $50.20 a barrel in early afternoon, after the EIA report showed the largest draw on crude inventories thus far this year, but then later retreated after analysts noted the EIA report also showed gasoline and distillate stockpiles grew, while U.S. production and imports increased, with prices hanging on to a gain of 6 cents on the day tp close at $49.62 per barrel....oil prices then extended the Wednesday afternoon selloff on Thursday, after the big jump in gasoline supplies knocked gasoline prices down to their lowest April price in 8 years, and after the restart of two oilfields in Libya added more crude to an already bloated global market, with oil prices closing down 1.3% for the day at $48.97 a barrel, a one month low...prices then edged back up on Friday, as traders who had earlier sold oil they didn't own bought it back to close out their positions before the end of the month, thus forcing a 36 cent increase in prices that left oil priced at $49.33 a barrel at the close...

natural gas pricing for the week was a little more complicated, because trading in the natural gas contract for May delivery expired on Wednesday, and after that the quoted price of natural gas was referencing the June contract...after closing last week at $3.101 per mmBTU (million British thermal units), May natural gas fell 3.5 cents on Monday to close at $3.066 per mmBTU, a four week low, on expectations that warmer-than-normal weather and light heating demand would mean higher-than-usual additions to supplies through mid-May...prices for May natural gas then fell another 2.3 cents on Tuesday to close at $3.043 per mmBTU, as lower spot prices for natural gas in New England weighed on the expiring futures contract...natural gas prices then turned higher on Wednesday on forecasts of cooler weather, with the expiring May contract closing up 9.9 cents at 3.142 per mmBTU, while the contract for June natural gas, which had gained a half cent on Tuesday, rose another 10.6 cents to close at on Wednesday $3.271 per mmBTU...now quoting the June contract, natural gas retreated 3.2 cents on Thursday to close at $3.239, after the EIA's weekly natural gas storage report showed a 74 billion cubic feet addition to US supplies, 2 billion cubic feet more than the industry had expected...prices for June natural gas then rose 3.7 cents on Friday to close the week at $3.276 per mmBTU, as a report indicated an average 12-month decline rate of 51 percent for existing wells in the Marcellus...that would mean, for instance, that a typical well in the Marcellus that started producing at 10 million cubic feet per day a year ago is now yielding only 4.9 million cubic feet per day, which in turn means that natural gas "producers have to drill at a breakneck pace just to keep output stable"

The Latest US Oil Data from the EIA

the big story from the US oil data for the week ending April 21st from the US Energy Information Administration was that US refineries processed more crude than in any other week in our history, so despite a concurrent big jump in our oil imports, we had to take oil out of storage to meet refining needs for the third week in a row...our imports of crude oil increased by an average of 1,102,000 barrels per day to an average of 8,912,000 barrels per day during the week, while at the same time our exports of crude oil rose by 587,000 barrels per day to an average of 1,152,000 barrels per day, which meant that our effective imports netted out to 7,760,000 barrels per day during the week, 515,000 barrels per day more than during the prior week...at the same time, our crude oil production rose by 13,000 barrels per day to an average of 9,265,000 barrels per day, which means that our daily supply of oil, from net imports and from wells, totaled an average of 17,025,000 barrels per day during the cited week...

at the same time, refineries reportedly used a record 17,285,000 barrels of crude per day, 347,000 barrels per day more than they used during the prior week, while 592,000 barrels of oil per day were being pulled out of oil storage facilities in the US....thus, this week's EIA oil figures seem to indicate that our total supply of oil from net imports, production and from storage was 332,000 more barrels per day than what refineries used...since that oil couldn't have just vanished, the EIA inserted a -332,000 barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the supply and demand data balance out, which they label in their footnotes as "unaccounted for crude oil" 

details from the weekly Petroleum Status Report show that the 4 week average of our oil imports rose to an average of 8,113,000 barrels per day, now 4.9% above the imports of the same four-week period last year...the 592,000 barrel per day decrease in our total crude inventories came about on a 520,000 barrel per day withdrawal from our commercial stocks of crude oil and a 72,000 barrel per day sale of oil from our Strategic Petroleum Reserve, part of an ongoing sale of 5 million barrels annually that was planned 19 months ago...this week's 13,000 barrel per day crude oil production increase resulted from a 20,000 barrel per day increase in oil output from wells in the lower 48 states, which was partially offset by a 7,000 barrels per day decrease in oil output from Alaska...the 9,265,000 barrels of crude per day that we produced during the week ending April 21st was another 20 month high, up by 5.6% from the 8,770,000 barrels per day we were producing at the end of 2016, and up by 3.7% from the 8,938,000 barrel per day output during the during week ending April 22nd a year ago, while it was still 3.6% below the June 5th 2015 record oil production of 9,610,000 barrels per day... 

US oil refineries were operating at 94.1% of their capacity in using that record 17,285,000 barrels of crude per day, up from 92.9% of capacity the prior week, and the highest capacity utilization since the last week in November 2015...since we now have a new record for the amount of oil refined in any one week, we'll include a graph here of what that looks like, compared to recent refining history...

the above graph comes from a weekly emailed package of oil graphs from John Kemp, senior energy analyst and columnist with Reuters...this graph shows US refinery throughput in thousands of barrels per day by "day of the year" for the past ten years, with the past ten year range of our refinery throughput on any given date shown in the light blue shaded area, and the median of our refinery throughput, or the middle of the 10 year daily range, traced by the blue dashes over each day of the year...the graph also shows the number of barrels of oil refined for each week in 2016 traced weekly by a yellow line, with our year to date oil refining for 2017 represented in red...from that we can note that for most all of 2016 and through most of 2017, US oil refining was either at seasonal record highs or near the top of the average range...however, we can also note there is normally a seasonal swing for oil refining, with demand for their products highest in the summer and again around the holidays, so for a refining record to be set this early in the year is truly an outlier...the 17,285,000 barrels of crude per day refined during the week ending March 21st beat the previous record of 17,107,000 set during the first week of 2017 by more than 1%; it was also 9.1% more than the 15,847,000 barrels per day that were being refined during the week ending April 22nd of 2016, when refineries were running at 88.1% of capacity...

even with the week's refining increase, gasoline production from our refineries decreased by 84,000 barrels per day to 9,710,000 barrels per day during the week ending April 21st, which was still 2.3% more than the 9,507,000 barrels of gasoline that were being produced daily during the comparable week a year ago....in addition, refineries' production of distillate fuels (diesel fuel and heat oil) decreased by 87,000 barrels per day to 5,150,000 barrels per day, which was 4.6% more than the 4,622,000 barrels per day of distillates that were being produced during the week ending April 22nd last year....meanwhile, there were small increases in refinery production of residual fuels, jet fuel, propane/propylene, and other refined products, but not enough to account for the 347,000 barrel per day increase in the amount of oil refined...

however, even with the drop in our gasoline production, the EIA reported that our gasoline inventories increased by 3,369,000 barrels to 241,041,000 barrels as of April 21st, after they had increased by 1,542,000 barrels the prior week....that additional surplus came about because our imports of gasoline rose by 73,000 barrels per day to 916,000 barrels per day, and as our gasoline exports fell by 23,000 barrels per day to 625,000 barrels per day, while our domestic consumption of gasoline fell by 17,000 barrels per day to 9,206,000 barrels per day...we'll take a look at a graph of that, too, since our gasoline supplies have started increasing at a time of year when they're normally being drawn on...

like the earlier graph, this graph comes from that emailed package of oil graphs from John Kemp, and it also shows our gasoline supplies in thousands of barrels by "day of the year" for the past ten years, with the past ten year range of our gasoline supplies on any given date shown in the light blue shaded area, and with the median level of our gasoline supplies over the 10 year period traced by the blue dashes over each day of the year...the graph also shows our gasoline supplies in thousands of barrels for each week in 2016 traced weekly by a yellow line, and our year to date oil refining during 2017 traced by a red line...from that we can see that for all of 2016 and through the first month of 2017, US oil refining was continuously at record high for each time of year, with an all time record of 259,063,000 barrels of gasoline supply set during the week ending February 10th of this year...however, even though our gasoline inventories were being drawn on for the following 8 weeks, shrinking by nearly 23 million barrels over that period, they've now recovered nearly 5 million barrels of that drawdown, and are now just a small fraction off the 241,259,000 barrels we had stored on the equivalent day a year ago...moreover, current gasoline inventories are now 6.0% higher than the 225,738,000 barrels of gasoline we had stored on April 24th of 2015, and 13.9% more than the 211,572,000 barrels of gasoline we had stored on April 25th of 2014...

similarly, even with the nominal decrease in distillate's production, our supplies of distillate fuels rose by 2,651,000 barrels to 148,266,000 barrels during the week ending April 21st, because the amount of distillates supplied to US markets, a proxy for our consumption during that warm week, decreased by 510,000 barrels per day to 3,667,000 barrels per day, and as our exports of distillates fell by 348,000 barrels per day to 1,071,000 barrels per day even as our imports of distillates fell by 113,000 barrels per day to 54,000 barrels per day at the same time...while our distillate inventories are still 4.6% below the 158,240,000 barrels that we had stored on April 22nd, 2016, following last year's warm El Nino winter, they are now 16.7% higher than the distillate inventories of 129,270,000 barrels that we had stored on April 24th of 2015, following a more normal winter…  

finally, with a record amount of crude going to our refineries, our commercial inventories of crude oil fell for the 3rd week in a row, decreasing by 3,641,000 barrels to 528,702,000 barrels as of April 21st, in the largest weekly drop since December 30th....however, we still finished the week with 10.4% more crude oil in storage than the 479,012,000 barrels we had stored on December 30th, and 3.8% more crude oil in storage than what was then a record 509,311,000 barrels of oil in storage on April 22nd of 2016, and 15.4% more crude than what was also then a record 458,181,000 barrels in storage on April 24th of 2015, and 43.8% more crude than the 367,576,000 barrels of oil we had in storage on April 25th of 2014... 

This Week's Rig Count

US drilling activity increased for the 25th time in the past 26 weeks during the week ending April 28th, and the week's increase was also the 12th double digit rig increase in the past 15 weeks....Baker Hughes reported that the total count of active rotary rigs running in the US increased by 13 rigs to 870 rigs in the week ending Friday, which was 450 more rigs than the 420 rigs that were deployed as of the April 29th report in 2016, and the most drilling rigs we've had running since August 28th, 2015, while it was still far from the recent high of 1929 drilling rigs that were in use on November 21st of 2014.... 

the number of rigs drilling for oil increased by 9 rigs to 697 rigs this week, which was more than double the 332 oil directed rigs that were in use a year ago, and the most oil rigs that were in use since April 24th 2015, while it was still way down from the recent high of 1609 rigs that were drilling for oil on October 10, 2014...at the same time, the count of drilling rigs targeting natural gas formations also rose by 4 rigs to 171 rigs this week, which was up from the 87 natural gas rigs that were drilling a year ago, but down from the recent natural gas rig high of 1,606 rigs that were deployed on August 29th, 2008...in addition, there were also 2 rigs in use that were classified as miscellaneous, compared to a year ago, when there was one miscellaneous rig at work...  

three more drilling platforms that had been working offshore from Louisiana in the Gulf of Mexico were shut down this week, which left 17 offshore rigs still drilling in the Gulf, down from the 24 working in the Gulf of Mexico a year earlier....that was also down from the total of 25 offshore rigs that were deployed a year ago, as there was also an drilling platform working in the Cook Inlet offshore from Alaska during the equivalent week of 2016...however, there was an additional drilling platform set up on an inland lake in southern Louisiana this week, which brought the inland waters rig count back up to 4 rigs, the same as a year ago...

active horizontal drilling rigs increased by 12 rigs to 730 rigs this week, which was up from the the 324 horizontal rigs that were in use in the US on April 29th of last year, but still down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014...at the same time, a net of 3 directional rigs were added this week, bringing the directional rig count up to 63, which was also up from the 46 directional rigs that were deployed during the same week last year....however, 2 vertical rigs were pulled out this week, reducing the vertical rig count down to 77 rigs, which was still up from the 50 vertical rigs that were deployed during the same week a year ago...

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 April 28th, the second column shows the change in the number of working rigs between last week's count (April 21st) and this week's (April 28th) count, the third column shows last week's April 21st 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 the 29th of April, 2016...      

once again, most of this week's new drilling rigs were deployed in Texas, and although it's not evident from the above, the Permian in west Texas saw an addition of 5 rigs, as did the Eagle Ford of south Texas...what appears to have happened is that 3 of the rigs that were drilling in the Permian in southeastern New Mexico were moved across the border to Texas this week, which is only apparent when looking at the rig counts from the separate Texas oil and gas districts (pdf map), so the net Permian count was only up 2 rigs...other than that, Oklahoma added 3 rigs with the addition of 4 rigs in the Cana Woodford, and Louisiana ended up with a net change of zero after 3 rigs were pulled out of the Gulf, one was added on an inland lake in southern Louisiana, a natural gas rig was added in the Haynesville in the north, and another rig was added in the southern half of the state...deployment of all 12 additional horizontal rigs is evident from the basin counts above, while the four new natural gas rigs were added in the Haynesville and 3 other unnamed basins....also note that of the states not shown above, Florida saw it's first drilling rig in operation since July 2015 start this week, while one rig was shut down in Mississippi, where there is now just 1 rig still active, down from 3 rigs a year ago....

+++++++++++++++++++++++++++++++++++++++

OOGA Ohio Oil and Gas Association : Energy In Depth Releases Compendium Demonstrating Health Benefits of Fracking -- Ahead of Earth Day, and as anti-fossil fuel activists prepare to 'march for science,' Energy In Depth is releasing a new compendium demonstrating that air quality improvements across the country can be traced directly back to fracking. [Attachment] The report - Compendium of Studies Demonstrating the Safety and Health Benefits of Fracking - houses dozens of scientific studies that show how the increased use of natural gas for electricity generation, made possible by the shale revolution, is the reason for dramatic decreases in air pollution across the board. This, in turn, has provided substantial health benefits for Americans. In addition to the compendium, EID unveiled a new microsite, EIDHealth.org - a one-stop shop for anyone looking for information about shale development and public health. 'This new compendium and health microsite provides the overwhelming scientific evidence that our increased use of natural gas, thanks to fracking, has delivered immense health benefits for families across the country,' said Jeff Eshelman, executive vice president of Energy In Depth. 'Activists who are supposedly 'marching for science' this weekend should stop denying the science that clearly shows shale development has led to cleaner air and lower greenhouse gas emissions.' EID's compendium includes data from 23 peer-reviewed studies, 17 government health and regulatory agencies, and reports from 10 research institutions that clearly demonstrate:

• Increased natural gas use - thanks to hydraulic fracturing - has led to dramatic declines in air pollution. The United States is the number one oil and gas producer in the world andit has some of the lowest death rates from air pollution. Numerous studies have shown that pollution has plummeted as natural gas production has soared.
• Emissions from well sites and associated infrastructure are below thresholds regulatory authorities consider to be a threat to public health - that's the conclusion of multiple studies using air monitors that measure emissions directly.
• There is no credible evidence that fracking causes or exacerbates asthma. In fact, asthma rates and asthma hospitalizations across the United States have declined as natural gas production has ramped up.
• There is no credible evidence that fracking causes cancer. Studies that have measured emissions at fracking sites have found emissions are below the threshold that would be harmful to public health.
• There is no credible evidence that fracking leads to adverse birth outcomes. In fact, adverse birth outcomes have decreased while life expectancy has increased in areas that are ramping up natural gas use.
• Fracking is not a credible threat to groundwater. Study after study has shown that there are no widespread, systemic impacts to drinking water form hydraulic fracturing.

The company behind the Dakota Access pipeline is in another controversy - The same company that built the controversial Dakota Access oil pipeline has twice spilled drilling fluids in two pristine Ohio wetlands this month while constructing a $4.2 billion natural gas pipeline that will stretch from Appalachia to Ontario, Canada. The drilling fluid — a mudlike substance used to lubricate and cool equipment — is not toxic. But the Ohio state Environmental Protection Agency and environmental groups were worried that the larger of the two spills, which covered a vast area the size of 8½ football fields, could smother aquatic life in the wetlands. Energy Transfer Partners notified the Ohio EPA that it spilled as much as 2 million gallons of drilling mud and cuttings from underground on April 13, affecting an area 1,000 feet long and 500 feet wide south of the town of Navarre. And on April 14, it spilled 50,000 gallons of the same fluids, affecting a smaller area of 30,000 square feet near Mifflin Township more than 100 miles away.Both incidents happened during the construction of the Rover pipeline, a 710-mile project that includes 207 sensitive water crossings. Energy Transfer was drilling horizontally under the crossings. The spills aren’t the only spots of controversy for the Rover pipeline. Last year, the Federal Energy Regulatory Commission referred the company to its enforcement division for possible penalties after Energy Transfer Partners bought and then demolished a house that dated back to 1843 and which was under consideration for inclusion in the National Register of Historic Places.  FERC said that “Rover demolished the structure with no prior notice or forewarning” even though “Commission staff identified the Stoneman House as an issue of concern early-on during the pre-filing process.” FERC said “Rover had intentionally and adversely affected the historic property.”   Energy Transfer Partners has also been in the political limelight. Its chief executive Kelcy Warren has given heavily to Republican candidates and political action committees. Its board of directors included Rick Perry, who resigned Dec. 31 after he was nominated to become energy secretary. And Donald Trump was an investor, but his lists of stock holdings indicate that he sold his shares.  The company has asserted that there is no danger from the spills. It said in a statement that the drilling mud is made of bentonite and “is a nontoxic, naturally occurring material that is safe for the environment.”  But the Ohio state EPA said the spill posed a danger to some of Ohio’s last surviving wetlands. “Discharges of bentonite mud and other material into waters of the state (including wetlands) can affect water chemistry, and potentially suffocate wildlife, fish and macroinvertebrates,” said Ohio EPA spokesman James Lee.

Rover Pipeline Construction Leaks Raise Questions of Contamination -- Cleanup is under way in Stark County where millions of gallons of drilling material spilled into a wetland during the construction of a natural gas pipeline. The pipeline construction crew shot 2 million gallons of drilling mud into a wetland.  Ohio Oil and Gas Association’s Shawn Bennett assures that the mud, which is used to borrow a hole for the pipe, does not pose a public health risk.“It’s a non-toxic component that is used in shampoo, deodorant, toothpaste and kitty litter,” Bennett said.But Melanie Houston with the Ohio Environmental Council says that wetland is supposed to protect a wide array of species.“The effects that it has is the potential to smother out any aquatic life,” Houston said. There’s no word yet on the exact impact on the wetlands or its aquatic life. The Ohio Environmental Council would like to see an investigation into this spill.

Rover Pipeline Causing Issues In Richland Co, Company Speaks- The construction of the Rover Pipeline has made it's way to Richland County, but recently a spill caused issues for a local wetland.  Last week, the Rover Pipeline construction caused 50,000 gallons of drilling fluid to spill into a local wetland off of Pavonia East Rd. in Mifflin Township.   This local spill was part of Rover's estimated 2 million gallons of drilling fluid pollutants into wetlands "adjacent to" the Tuscarawas River last week, according to a violation filed by the Ohio Environmental Protection Agency (EPA).Local resident, Kathy Wolfe, told WMFD that the spill occurred within her and her husband's 480-acre property which is located within Richland and Ashland counties.  Wolfe mentioned that she was told by her Rover land agent, Mitch Phillis, that it was a frack-out spill and that it was 'no big deal, it's just mud'.   Alexis Daniel, PR & Communication Specialist for Energy Transfer, released a statement to WMFD that stated: "The Rover Pipeline project team would like to provide an update on the inadvertent release of “drilling mud” that occurred as part of our construction activities in Ohio.The drilling mud, which is a non-toxic, naturally occurring material that is safe for the environment was being used to help facilitate horizontal directional drills in Ohio. Due to the subsurface conditions and other environmental conditions of the locations, the drilling mud was able to migrate through naturally occurring fractures in the soils and reach the surface. It is important to note this is a common and normal component of executing directional drilling operations, there will be no impact to the environment and the release of the drilling mud is being managed and mitigated in accordance with the previously approved and certificated Horizontal Directional Drilling Contingency Plan on file with the Federal Energy Regulatory Commission (FERC) and the Ohio Environmental Protection Agency (OEPA)."

Ohio pipeline project's early messes don't inspire confidence --Just in time for Earth Day, the company that only recently began skewering Ohio with a $4 billion natural-gas pipeline has racked up a brace of environmental blunders. Or maybe, as the Rover Pipeline suggests, it’s Earth’s fault. Rover reported to the Ohio Environmental Protection Agency that it had an “inadvertent release” of about 2 million gallons of drilling mud into a Stark County wetland on April 13, and another one of 50,000 or so gallons into a Richland County wetland a day later. The mud, a mixture of water and bentonite clay, is used as a lubricant in drilling. Rover’s parent company, Energy Transfer Partners of Dallas, stressed in an occasionally redundant but expertly spun email that bentonite clay is “naturally occurring,” “nontoxic” and “safe.” “There will be no impact to the environment,” it reads. Bentonite clay, the statement notes, “is used in a variety of household products.”  Which is true. Among its uses, bentonite clay puts the clump in clumping cat litter. But this misstep involved more than a cat box’s worth of bentonite clay. The clay sludge in question could fill three Olympic swimming pools.Here’s how the company says it happened: “Due to the subsurface conditions and other environmental conditions of the locations, the drilling mud was able to migrate through naturally occurring fractures in the soils and reach the surface.” So Earth did it, in cahoots with the environment.  No one should be surprised that construction of the pipeline, which started only recently, has led to screw-ups. Rover has not hidden the fact that it is in a hurry. Hemorrhaging a few million gallons of muck into some wetlands is one thing. Hemorrhaging money is quite another.  Once finished, the pipeline will slice through 713 miles of West Virginia, Ohio, Pennsylvania and Michigan. The larger of the two spills coated 500,000 square feet of a wetland beside the Tuscarawas River, or about the area taken up by five Wal-Mart stores.

Local anti-fracking group hopes third time's the charm for charter -- athensnews.com: For the third year in a row, the Athens County Bill of Rights Committee will seek to put the question of turning the county into a charter form of government to voters in November. As with the other initiatives, this charter proposal doubles as an effort to keep oil and gas horizontal hydraulic fracturing (fracking) out of Athens County, through the use of local water for fracking operations. It also would prohibit fracking waste-injection wells, of which Athens County already has several in operation. This past September, for the second year in a row, the Ohio Supreme Court ruled that a proposed anti-fracking charter amendment for Athens County would not appear on the county’s general election ballot. The amendment, in addition to setting up a charter form of government, would have outlawed fracking waste injections wells in Athens County, as well as the use of county water resources for oil and gas drilling activities in Athens County and elsewhere. The latter provision would substantially curtail any future local fracking, which uses an immense amount of water. So far, the deep-shale oil and gas boom hitting other parts of eastern Ohio in recent years hasn’t extended into Athens County, and it’s an open question whether it ever will. The same Supreme Court decision also tossed out similarly crafted charter amendment petitions for Meigs and Portage counties. The high court did the same thing the previous year to charter amendment petitions for Athens, Meigs and Fulton counties, but for different reasons. Both years, the cases reached the Supreme Court (and before that, lower courts) after appeals of decisions by county boards of elections and the state Secretary of State rejecting the petitions.

Ohio's natural-gas production soared during a down year nationally - In a year when the country’s natural-gas production went down, Ohio’s went up — way up. The 2016 results, part of a government report issued this week, show that Ohio passed West Virginia to become the nation’s sixth-largest gas producer. Ohio also had the largest percentage increase of any of the top states. Ohio energy companies produced 1,465 billion cubic feet of gas, up from 1,015 billion in 2015, according to the Energy Information Administration. (The figures are from a report on “marketed production” of gas; they are slightly different from figures issued by the Ohio Department of Natural Resources.) The growth is notable because last year was difficult for many people in the energy business. Low prices for oil and gas and cost-cutting led to a pervading sense of gloom among producers. Nearly all of Ohio’s gas comes from the Utica and Marcellus shale formations, which are deep below ground and accessible through horizontal drilling and hydraulic fracturing, or fracking. A few positive factors helped to cancel out the negative ones for Ohio. First, several pipelines and processing sites came online, which allowed producers to move some of the pent-up gas supply to market. “In Ohio, we certainly have had a lot of gas behind pipe that was waiting on connections,”  Second, Ohio had the good fortune that many of its gas wells turned out to be prolific, with eye-popping output. Many of the top wells were in the eastern Ohio counties along the Ohio River, such as Belmont and Monroe. The United States produced 28,296 billion cubic feet, down from 28,753 billion the prior year.

Ohio and Pennsylvania increased natural gas production more than other states in 2016 - EIA - After reaching a record high of 79 billion cubic feet per day (Bcf/d) in 2015, U.S. marketed natural gas production fell to 77 Bcf/d in 2016, the first annual decline since 2005. Texas, the state with the most natural gas production, fell by 2.5 Bcf/d, while Ohio and Pennsylvania each increased by about 1.2 Bcf/d. EIA measures natural gas production in three different ways. Gross withdrawals are the full volume of compounds extracted at the wellhead, which includes all natural gas plant liquids and nonhydrocarbon gases after oil, lease condensate, and water have been removed. Marketed natural gas production excludes natural gas used for repressuring the well, vented and flared gas, and any nonhydrocarbon gases. Dry natural gas production is marketed production minus natural gas plant liquids. Pennsylvania and Ohio had the two largest annual natural gas production increases from 2015 to 2016, reflecting higher production from the Utica and Marcellus shale plays, which have accounted for 85% of the U.S. shale gas production growth since 2012. Production in Pennsylvania and Ohio has accounted for an increasing share of total U.S. natural gas production in recent years, growing from less than 2% in 2006 to 24% in 2016.  Pennsylvania surpassed Louisiana in 2013 to become the second-highest natural gas producing state, behind Texas. Although both states had higher production in 2016, Ohio surpassed West Virginia last year to become the seventh-highest natural gas-producing state. The increased productivity of natural gas wells in the Marcellus Shale and Utica Shale is a result of ongoing improvements in precision and efficiency of horizontal drilling and hydraulic fracturing occurring in these regions.  Louisiana, West Virginia, and North Dakota also increased their natural gas production in 2016. Louisiana’s increase was the first annual increase since 2011, while West Virginia and North Dakota have had 13 and 8 consecutive years of natural gas production increases, respectively.

Ohio, Pennsylvania saw biggest natural gas production increases in 2016 -- Ohio and Pennsylvania each increased natural gas production by approximately 1.2 Billion cubic feet per day (Bcf/d) in 2016, the largest annual natural gas production increases from 2015 to 2016 for any U.S. state, according to a recent report released by the U.S. Energy Information Administration. These increases came about despite an overall decrease in U.S. natural gas production. Marketed natural gas production, which excludes natural gas used for repressuring the well, vented and flared gas and any nonhydrocarbon gases, fell from 79 Bcf/d in 2015 to 77 Bcf/d in 2016. Texas, the state with the highest natural gas production levels, decreased production by 2.5 Bcf/d. The increases in Ohio and Pennsylvania were mostly a result of increased production from the Utica and Marcellus shale plays, which have made up 85 percent of U.S. shale gas production growth since 2012. Pennsylvania and Ohio’s share of total U.S. natural gas production has grown from under two percent in 2006 to 24 percent in 2016. In 2013, Pennsylvania surpassed Louisiana to become the state with the second highest natural gas production behind Texas. Ohio became the seventh highest natural gas producing after surpassing West Virginia last year. Louisiana, West Virginia, and North Dakota also increased their natural gas production in 2016. The increase in Louisiana was the state’s first annual increase since 2011, while West Virginia and North Dakota have seen annual for the past 13 and eight consecutive years respectively. The EIA’s Short-Term Energy Outlook projects that natural gas production will increase in both 2017 and 2018 as natural gas prices rise. 

E&P companies doubling down on Marcellus / Utica in 2017 CAPEX plans.  As a group, the nine natural gas-focused exploration and production companies that were analyzed in our Piranha! market study are forecasting a 62% increase in capital spending in 2017 compared with 2016, a significantly higher percentage gain than their oil-focused and diversified counterparts. The driver of accelerated investment is the expected completion of natural gas infrastructure that will boost takeaway capacity from the Marcellus and Utica shales, the operational focus of eight of the nine gas-weighted E&Ps.  Expanded access to Canadian, Midwestern, Gulf Coast and export markets should significantly boost realizations and margin. Production growth by the nine E&Ps, which slowed to 4% in 2016 after a 19% rise in 2015, is expected to accelerate to 10% in 2017 and to rise rapidly in 2018 and beyond. Today we continue our analysis of U.S. E&P capital spending and production trends by taking a deep dive into the investment strategies of the natural gas-weighted peer group. U.S. oil and natural gas E&P companies, anticipating continuing low crude oil and natural gas prices, have been reshaping their portfolios to focus on a half-dozen top-notch resource plays whose production economics can hold up even if prices were to soften further. The biggest of these asset purchases and sales grab the headlines, but countless other, smaller-bite deals are having profound effects too. Taken together, this piranha-like devouring of E&P assets in the Permian, the SCOOP/STACK and other key production areas is transforming who owns what in the plays that matter most, and positioning a select group of E&Ps for success.

Fearful parents demand schools near gas pipeline release evacuation plans - Behind closed doors at Rose Tree Media school headquarters in Delaware County, the “safety summit” brought together district and township leaders, first responders, officials from Sunoco Logistics, and even Homeland Security to draw up school evacuation plans in the event of a catastrophic explosion or leak from the impending Mariner East 2 pipeline.  Not in the room — barred from attending, in fact — were the people whose growing anxiety and anger prompted the summit: a coalition of more than 2,700 elementary school parents and allies who fear their children won't be able to get out of harm's way should disaster strike the pipeline as it carries 275,000 barrels of natural gas liquids daily through their densely populated suburbs. A tight lid was kept on the late March confab. In a statement, Rose Tree Media Superintendent James Wigo joined other attendees in insisting that releasing evacuation details would “compromise student safety,” for instance in a school shooting. “Think about the horrors of a potential sniper situation.” The secrecy has further inflamed the Middletown Coalition for Community Safety, which continues to add members in Delaware and Chester Counties, through which Mariner 2 will soon pass. It formed in August after parents learned the pipeline would come within 650 feet of Rose Tree Media’s Glenwood Elementary, attended by 430 children. The group tried to stop Middletown Township from granting easements near the school, but lost. Since then, it has pressed Rose Tree Media and the West Chester Area School District for answers about student safety, while sounding the alarm at other schools along the route. According to risk assessments commissioned by the coalition, a vapor-cloud leak can spread 1,800 feet in three mintues, and ignition of the gas can produce a fireball with a blast radius up to 1,100 feet that would burn until the pipeline is fully purged. As many as 40 Pennsylvania schools would be in the potential "blast zone" if the line were to explode near them. Thousands of houses and facilities such as nursing homes also adjoin the route, but coalition founder Eve Miari said that worries about the schools have trumped other issues. “An elementary school is sort of like the heart center of the community," she said. "It’s where we send our babies."

Salem couple unswayed on Mariner East 2 pipeline project as Spectra explosion anniversary nears - When the Pintos bought property along Route 819 and built a house on it over 50 years ago, they were aware of an existing 8-inch pipeline running beneath their land. But they said they never imagined two additional pipelines, both more than double in size, would follow. The hotly debated Mariner East 2 pipeline project received the final permits necessary for construction in February from state regulators after five public meetings and 29,000 public comments. Construction already has started. The 20- and 16-inch pipelines will be able to carry 275,000 barrels of liquid natural gas a day and cross 270 properties over 36 miles in Westmoreland County as the Mariner East 2 cuts 350 miles from Ohio and West Virginia to refineries near Philadelphia. The new pipelines will run parallel to the existing Mariner East 1 line. More than 4 miles of Mariner East 2 will traverse Salem. With the one-year anniversary of the Spectra pipeline explosion approaching this week, some township residents fear catastrophe is inevitable. Others are not so concerned. Spectra Energy's 30-inch natural gas pipeline near the intersection of Routes 22 and 819 ruptured and sparked a massive explosion on April 29. The blast left one man severely burned, incinerated a home and damaged others, charred 40 acres of farmland, melted portions of a highway and negatively impacted the energy futures market.

Range Recalls 'Incredibly Creative Solution' for Marcellus/Utica 'Problem'  -- On March 9, 2016, the Ineos Intrepid – a new class of LNG vessel – embarked on a nearly 4,000-mile voyage across the Atlantic Ocean to Ineos' ethane cracker in Rafnes, Norway. As Ineos noted at the time, never before had shale gas produced in the United States been shipped to Europe.  "It was an incredibly creative solution to what was at one time viewed as a problem – what to do with our ethane," recalled Jeff Ventura, Range Resources' president and CEO. "In Texas and in Oklahoma, there was infrastructure in place in to process wet gas. When we were getting started in Pennsylvania, there wasn't." When it was establishing its foothold in the Marcellus during the mid-2000s, Range needed to find a home for the natural gas liquids (NGL) produced from its acreage in Washington County, Pa., in order to justify the economics of operating there. The company considered various proposals for tackling its "ethane problem." Given the lack of NGL pipeline takeaway capacity, the company considered shipping the ethane via rail and barge but found that approach unsatisfactory. Instead, it opted for the processing route. "In order for that product to become profitable, the gas would need to be processed," explained Curt Tipton, Range's vice president of Marcellus development "There were no chemical companies (that could take the ethane and use it as a feedstock) – and no real option to separate out the ethane so that the methane ("dry gas") could make its way to customers on the other end of natural gas-ready pipelines. Without the ability to remove ethane, you can't produce the gas." Since February 2016 Sunoco Logistics has delivered up to 70,000 barrels per day (bpd) of ethane from Washington County in southwestern Pennsylvania eastward to its Marcus Hook Industrial Complex via the Mariner East 1 pipeline. Previously a conduit for shipping refined products from east to west, Sunoco Logistics' Mariner East 1 is being paired with a parallel pipeline – Mariner East 2 – that will raise the system's total takeaway capacity to 345,000 bpd. According to Sunoco Logistics' website, Mariner East 2 should go into service later this year.

PennEast Pipeline 'Would Cause Massive Increase in Climate Pollution' -- A study released Wednesday found that, if built, the controversial PennEast Pipeline for fracked gas could contribute as much greenhouse gas pollution as 14 coal-fired power plants or 10 million passenger vehicles—some 49 million metric tons per year.  The analysis, conducted by Oil Change International, showed that federal regulators are poised to rubber-stamp the PennEast Pipeline based on a woefully inadequate climate review that ignores the significant impact of methane leaks and wrongly assumes that gas supplied by the project will replace coal .  The Federal Energy Regulatory Commission (FERC) is facing a growing backlash across the country over its routine approval of gas pipeline projects that endanger communities and the climate . Today's study comes on the heels of a federal court hearing in which a judge slammed FERC's shallow and dismissive review of the climate impact of the Sabal Trail gas pipeline in the Southeast.  The new analysis counters FERC's final environmental impact statement for the PennEast project released in early April. It applies a methodology recently developed by Oil Change International to calculate the climate impact of gas pipelines from the Appalachian Basin. In contrast to FERC, the Oil Change methodology reflects the evolving analysis of methane leakage and the full lifecycle of pollution that pipelines cause from fracking well to smokestack.  "Our analysis shows that the PennEast Pipeline would cause a massive increase in climate pollution," said Lorne Stockman, lead author of the study and Oil Change International senior research analyst. "The only way FERC can conclude otherwise is by ignoring both science and economics. The PennEast pipeline is not needed, communities don't want it and it will deepen reliance on fossil fuels that we can't afford to burn."

Is the northeast natural gas market no longer pipeline capacity constrained? - Natural gas production growth in the U.S. Northeast—the primary driver of U.S. production growth in recent years—has slowed dramatically in the past few months, up no more than 1 Bcf/d year-on-year, compared with growth in increments of 3 and 4 Bcf/d in previous years. Despite the slowdown, the regional balance continues to lengthen, with supply growth outpacing demand. Yet, regional gas prices, specifically at key supply hubs, which previously were struggling under the weight of oversupply coupled with limited access to growing demand markets, are strengthening. Is this the beginning of the end of takeaway constraints and distressed supply pricing in the region? Or will constraints reemerge this summer? Today, we provide an update of Northeast gas supply/demand balance. Ever since the Marcellus Shale first took off in late 2009-10, the Northeast region has been marching toward becoming a full-fledged supplier of natural gas in the U.S. At first it grew practically unconstrained, targeting the region’s own gas-thirsty winter premium markets. By 2014, the Northeast was meeting its own regional demand through the lower-demand shoulder and summer months, but regional demand continued to outpace supply in the winter months. Then the winter of 2015-16 marked another milestone. It was the first time Northeast produced enough to meet all of its winter demand and then some. Now, dynamics are once again shifting. Regional production growth has slowed to a crawl, relatively speaking. At the same time, the region has been dealt two consecutive mild winters that have dampened demand. On the other hand, the region has added more takeaway capacity that, with production flattening out, is less constrained. What does this all mean for the Northeast gas market? We wrote about the evolving balance about a year ago in One Step Closer and looked at the fundamentals again in November 2016 in Still They Ride. We’ve since also blogged about the expansion of Tallgrass Energy’s Rockies Express Pipeline (REX) in It’s Been a Long Time Coming. But with another winter behind, injection season well under way and more takeaway capacity on the way, it’s time again to revisit the balance.

Duke Study Finds Fracking Isn't Contaminating Groundwater - Daily Caller -- Duke researchers collaborated with other scientists from Ohio State University, Pennsylvania State University, and Stanford University to sample water from 112 drinking wells in northwestern West Virginia over a three-year period. They sampled 20 drinking water wells before fracking began in the area to compare. Duke’s new research matches the findings of other scientific studies from regulatory bodies, academics, and the U.S. Geological Survey(USGS) which determined that fracking hasn’t contaminated ground or drinking water. Even the Environmental Protection Agency (EPA), which wants to regulate fracking using groundwater contamination as an excuse, still hasn’t found any groundwater contamination after five years of study. Environmentalists responded to these studies, saying, “millions of Americans know that fracking contaminates groundwater and for the EPA to report any differently only proves that the greatest contamination from the industry comes from its influence and ownership of our government.”Myths about fracking are so widespread that the USGS actually maintains a “Myths and Misconceptions” section of its website to debunk them.  Up to 96 percent of wastewater from fracking is from naturally occurring salts and brines, not artificial fracking fluids, another study published by Duke University concluded. Duke researchers found that between 92 and 96 percent of wastewater coming out of fracking wells was comprised of naturally occurring brines and salts, which were extracted along with the gas and oil. Only about 4 to 8 percent of the wastewater included man-made chemicals.

West Virginia groundwater not affected by fracking, but surface water is -- Fracking has not contaminated groundwater in northwestern West Virginia, but accidental spills of fracking wastewater may pose a threat to surface water in the region, according to a new study led by scientists at Duke University."Based on consistent evidence from comprehensive testing, we found no indication of groundwater contamination over the three-year course of our study," said Avner Vengosh, professor of geochemistry and water quality at Duke's Nicholas School of the Environment. "However, we did find that spill water associated with fracked wells and their wastewater has an impact on the quality of streams in areas of intense shale gas development.""The bottom-line assessment," he said, "is that groundwater is so far not being impacted, but surface water is more readily contaminated because of the frequency of spills."The peer-reviewed study was published this month in the European journal Geochimica et Cosmochimica Acta.The Duke team collaborated with researchers from The Ohio State University, Pennsylvania State University, Stanford University and the French Geological Survey to sample water from 112 drinking wells in northwestern West Virginia over a three-year period.Twenty of the water wells were sampled before drilling or fracking began in the region, to provide a baseline for later comparisons.Samples were tested for an extensive list of contaminants, including salts, trace metals and hydrocarbons such as methane, propane and ethane. Each sample was systematically analyzed using a broad suite of geochemical and isotopic forensic tracers that allowed the researchers to determine if contaminants and salts in the water stemmed from nearby shale gas operations, from other human sources, or were naturally occurring.

Study: Fracking didn’t impact West Virginia groundwater, but wastewater spills pollute streams - Fracking the Marcellus Shale did not pollute groundwater in northwestern West Virginia, but wastewater spills did contaminate surface water, according to a new study from Duke University. The report adds to an increasing body of work pointing to greater risks from fracking wastewater transport and treatment, than from the process itself. The study was unique in that it monitored drinking water wells and surface water over three years, a longer time period than previous research on the impact of fracking on drinking water. The study also used multiple methods of determining the source of the pollution, and was able to draw on baseline water quality data. “Based on consistent evidence from comprehensive testing, we found no indication of groundwater contamination over the three-year course of our study,” said Avner Vengosh, professor of geochemistry and water quality at Duke’s Nicholas School of the Environment. ”However, we did find that spill water associated with fracked wells and their wastewater has an impact on the quality of streams in areas of intense shale gas development.”Vengosh says the study results are dissimilar from previous research in Northeast Pennsylvania where the methane found in drinking water wells was connected to fracking. The peer-reviewed study was published recently in Geochimica et Cosmochimica Acta, a European journal. It adds to a growing body of academic research focused on the impacts of shale gas drilling, which requires high pressure water, mixed with chemicals, to be injected deep below the surface to break up the shale rock to release the gas trapped within it. Although industry says the practice is safe, concerns have grown over how often the practice can lead to groundwater contamination in areas where residents rely on well water.Vengosh said differences in geology and industry practices can play a role. And although three years is longer than previous studies, Vengosh said ground water moves very slowly, so results may be different 10 or 15 years from now.”You need to do the science,” he said. “There’s no way to avoid the science and come to a conclusion. And you have to do it in a really thorough way to determine the source of contamination.”Vengosh said the baseline data, gathered from drinking water wells before shale gas drilling occurred nearby, boosts their confidence in the results. A total of 112 water wells were sampled over three years, with 20 sampled before drilling or fracking occurred.

Increased Oil and Natural Gas Production Could Result from Data on Low Frequency Tremors Discovered by NETL During Hydraulic Fracturing -- When researchers from the Department of Energy's (DOE) National Energy Technology Laboratory (NETL) set up new monitoring capabilities at active Marcellus Shale hydraulic fracturing sites in Pennsylvania and West Virginia to better understand seismic activity, they discovered that low frequency tremors occur, which they believe could be useful to optimize oil and natural gas production from unconventional shale. Abhash Kumar, a contractor at NETL who developed the new surface seismic monitoring capability along with Erich Zorn, an intern with NETL in the Oak Ridge Institute for Science and Education (ORISE), explained that hydraulic fracturing has revolutionized the Nation's energy security requirements as well as hydrocarbon production capabilities. 'It's a well-established exploration technique to stimulate production of oil and natural gas from unconventional formations such as shale and tight gas sands, commonly referred as 'tight oil',' he said. 'The injection of water or other fluids during hydraulic fracturing helps enhance permeability of the reservoir rock, increasing the rate of flow of the hydrocarbons. Surface seismic monitoring of hydraulic fracturing is an important tool to evaluate the effectiveness of reservoir stimulation.' Kumar and Zorn, mentored by NETL researcher Richard Hammack and Professor William Harbert of the University of Pittsburgh, collected seismic data that indicated the presence of low frequency seismic emissions during hydraulic fracturing. 'Our analyses confirmed seismic events lasting between 30 to 60 seconds in duration with significant concentration of energy at lower frequencies.' Kumar said. 'During various stages of hydraulic fracturing, long period events were found to occur most frequently when the pumping pressure and slurry rate were at maximum levels. That suggests that they may play a significant role in the reservoir stimulation.'

Gas storage field leak capped in rural southwestern Indiana  — Officials say a natural gas leak from an underground storage field in rural southwestern Indiana has been capped. Citizens Energy Group says a well drawing gas from the storage area near the Greene County town of Worthington failed during maintenance work Tuesday evening. High-pressure gas was escaping Wednesday and the leak was reported capped later in the day. No fire or injuries occurred. The Indianapolis-based utility said escaping gas had prompted the evacuation of seven nearby homes and the closure of a state highway. It said the loss of gas won't impact service to customers.

Enbridge's Great Lakes Pipeline Has Spilled 1 Million Gallons Since 1968 -- Enbridge Energy Partners ' aging Line 5 pipeline , which runs through the heart of the Great Lakes, has spilled more than 1 million gallons of oil and natural gas liquids in at least 29 incidents since 1968, according to data from the federal Pipeline Hazardous Materials Safety Administration obtained by the National Wildlife Federation .  Built in 1953, the 645-mile, 30-inch-diameter pipeline carries petroleum to eastern Canada via the Great Lakes states. As it travels under the Straits of Mackinac, a narrow waterway that connects Lake Michigan and Lake Huron, Line 5 splits into twin 20-inch-diameter, parallel pipelines.  Line 5 opponents fear that a spill in the Great Lakes, which contains 21 percent of the world's surface fresh water, would be an ecological disaster. Notably, the straits' strong currents reverse direction every few days and a spill would quickly contaminate shoreline communities miles away.  Enbridge is behind a number of major spills, most notoriously in 2010 when an Enbridge line spilled more than 800,000 gallons into the Kalamazoo River in Michigan—creating the biggest inland oil spill in U.S. history .  "We have a pipeline system with a history of problems running through our country's largest source of surface freshwater, and it happens to be operated by the company responsible for one of the largest inland oil spills in North America," said Mike Shriberg, executive director for the National Wildlife Federation's Great Lakes "This pipeline system places the Great Lakes and many local communities at an unacceptable risk. The state of Michigan needs to find an alternative to this risky pipeline to protect our drinking water, health, jobs and way of life."  The National Wildlife Federation has released a new interactive map showing what has spilled from Enbridge's pipeline system, the repair methods that have been used, and how leaks and defects are being discovered.

North American E&Ps seen likely to post modest Q1 growth as natural gas output grows - Coming off a two-year period of belt-tightening the first-quarter earnings of some North American exploration-and-production companies are expected to reflect the first signs of new gas production growth, but that growth is conditional upon the basins where the producer operates and the individual company's economic circumstances going into the quarter. In addition, the quarterly results are apt to show a continuation of the trend of producers increasingly focusing on basins with better economic returns -- chiefly oilier and more liquids-rich plays -- while downplaying efforts in the drier gas basins. US drilling activity has been on the upswing, particularly in the Permian Basin of West Texas and southeastern New Mexico, the hottest oil and gas play in the country. Producers in recent months have flocked to the Permian, which boasts some of the highest initial production (IP) rates for oil and gas of any basin in the country. The Permian hovers around a 30-day average oil IP rate of 600 b/d, and for the gas the IP rate is closer to 1,400 Mcf/d, according to Platts Analytics.Crude-focused producers such as Anadarko Petroleum are expected to post strong Q1 results as a result of investments in the oil-rich Permian as well as the DJ Basin of Colorado, another oily province. Anadarko said last month it expected a 25% increase in oil sales volumes over the prior year. Meanwhile, some gas producers could see production growth in the quarter as well. Appalachian producers operating in the liquids-rich portions of the basin -- chiefly the southwestern Marcellus and Utica plays -- are largely expected to increase drilling and production in the quarter compared with the same period last year. Appalachian producer Range Resources also provided guidance that it would increase its capital expenditures to $1.150 billion versus $513 million in 2016, while the producer estimated it would increase its production for full-year 2017 to 2.07 Bcfe/d versus 1.54 Bcfe/d in 2016.  To drill a well in the Marcellus costs around $6 million with a gas IP rate of 10,000 Mcf/d, according to Platts Analytics. Producers drilling in the Utica Shale in eastern Ohio have mentioned gas IP rates around 20,000 Mcf/d with a well cost around $10.6 million.  Chesapeake Energy, which operates in a number of basins across the country, is expected to drill and produce less oil and gas than last year, largely as a result of the sale of some of its non-core assets, such as the Barnett Shale of North Texas last year, according to its most recent guidance.

U.S. natural gas prices soften, market eyes big hedge fund longs: Kemp (Reuters) - Hedge fund managers have accumulated a near-record bullish position in U.S. natural gas futures and options as gas stocks have remained at a modest level despite an exceptionally mild winter. Hedge funds and other money managers have boosted their net long position in the two main futures and options contracts for seven consecutive weeks by a total of 1,313 billion cubic feet. By April 18, fund managers had accumulated a net position equivalent to 3,511 billion cubic feet, the highest for three years, according to data published by U.S. Commodity Futures Trading Commission. Fund managers show a strong bullish bias, with long positions outnumbering short positions by 4.3:1, up from a recent low of 2.2:1, and the highest ratio since February 2014. Funds have reacted to signs of tightness in the gas market as a result of sluggish production, strong exports and a structural increase in gas demand from new combined-cycle power plants. Working gas stocks have finished the winter around 380 billion cubic feet, or 15 percent, below the same point last year even though temperatures have been slightly warmer. But the concentration of long positions has increased the risk of a sharp correction if funds try to take profits following the recent increase in prices. The correction may already be underway with both flat prices and the calendar spreads under pressure in recent sessions. Futures prices for gas delivered to Henry Hub in June 2017 have fallen from a recent high of $3.33 per million British thermal units on April 7 to $3.19 on April 21. And the calendar spread between June 2017 and June 2018 has dropped from 53 cents on April 6 to just 27 cents on April 21. FU The sustained increase in gas prices is likely to cause power producers to run their gas-fired units for fewer hours this summer and increase the utilisation of coal plants. Higher U.S. gas prices have already made it more economically attractive to run coal-fired units despite their lower efficiency and flexibility. U.S. coal shipments by rail have risen by 18 percent so far this year compared with the same period in 2016, according to the Association of American Railroads (http://tmsnrt.rs/2pWrmMm ).  Some of the increase in shipments reflects the clearing of excess stocks at power plants that built up between 2014 and 2016. However, some of the increase likely reflects plans to run coal-fired units for more hours during the summer of 2017 to meet air-conditioning demand.

EIA Reports Natural Gas Inventories Rise 74 Bcf, Prices Still Advance: The latest Energy Information Administration (EIA) natural gas storage data recorded a build of 74 Billion Cubic feet (Bcf) for the week ending April 21st following an increase of 54 Bcf last week. The increase was slightly higher than consensus forecasts of a 72 Bcf gain and this was also the largest build since the middle of October 2016.  There will also be concerns over net build seen in stocks during April which is likely to be higher than that seen for April 2016. There is also the strong probability of a substantial net build during May on seasonal grounds. Stocks overall are 14.1% below the year-ago figure, but 15.8% above the five-year average from 15.4% last week. There was an increase in stocks across all regions on the week with the East recording the largest gain, although stocks here are still 29.2% below the levels seen last year. Stocks are below year-ago levels in all regions while Midwest stocks are 30.2% higher than the 5-year average.  Natural gas prices dipped at the end of last week, but did find support on approach to the $3.10 per mBtu area and prices moved to highs around $3.25 on Wednesday.In this context, prices have been broadly resilient despite a weaker trend in crude prices over the past few days.  Weather conditions are likely to drive moderate demand for gas over the next week with generally cool conditions in the Central and Western areas triggering limited demand for heating demand while hot conditions in parts of the South will drive early demand for air-conditioning.

Europe lures rare diesel cargoes from U.S. East Coast | Reuters: U.S. East Coast refineries are stepping up exports of diesel despite a regional deficit of the fuel as strong overseas demand, particularly in Europe, is proving more profitable. Two tankers carrying 60,000-tonne cargoes of diesel have been booked in recent days out of New York Harbor to go to Northwest Europe, traders said. The two vessels, River Shiner and Two Million Ways, were chartered by Swiss-based trading house Trafigura [TRAFG.UL] and will load fuel sold by Delta Air Lines Inc's refiner subsidiary Monroe Energy, near Philadelphia. They are expected to top up their cargo in New York before sailing to Europe, an East Coast trader said. The BP-chartered, 37,000-tonne Arctic Breeze is nearing its destination - Sete port in southern France - after loading a diesel cargo this month at the Kinder Morgan terminal in New York, according to traders and Reuters shipping data. At least one other 37,000-tonne tanker has been booked on the transatlantic route, traders said. U.S. Gulf Coast refineries have become a powerhouse of distillate exports amid a rise in demand from Latin America and West Africa due to refinery outages there. While Europe historically relies on a steady stream of diesel from the U.S. Gulf Coast, the rise in competition has led to a marked drop in that region's diesel exports to Europe.The U.S. East Coast typically imports middle distillates, including diesel and heating oil, to meet regional demand. Over the past year, the region imported an average of around 180,000 barrels per day of distillates, according to the U.S. government's Energy Information Administration. 

Senate advances bill to let FPL customers pay fracking costs | Tampa Bay Times: Florida Power & Light's quest to have customers pay for natural gas fracking projects in other states overcame a key hurdle Tuesday as the Senate Rules Committee passed the controversial measure and overlooked opposition from residential and commercial customers. The proposal, SB 1238 by Sen. Aaron Bean, R-Fernandina Beach, now goes to the Senate floor. A similar measure in the House, HB 1043, has made it through one of three committees in that chamber. The goal of the legislation is to overturn a Florida Supreme Court ruling last year that found the Public Service Commission exceeded its authority when it gave FPL permission to charge customers up to $500 million for investing in an Oklahoma-based fracking company in 2015. Although the company predicted the project would save customers millions in fuel costs, it resulted in a loss of $5.6 million in the first year. The Rules Committee adopted a series of amendments proposed by Sen. Jack Latvala, R-Clearwater, who opposes the measure, and approved the modified bill on a bipartisan vote of 7-3. Latvala said the bill will "for the first time make the ratepayers pay for exploration" and "allow the utilities to charge a rate of return on that exploration cost." He asked Bean if customers pay if the well produces a "dry hole — so all the risk is with the ratepayers and not with the company?" Bean responded: "That is correct" and added that the projects won't be exploratory because "it is highly likely that there is natural gas," he said. Latvala countered: "That is still exploration." 

Gulf of Mexico crude oil production hits all-time high. The Permian may be grabbing most of the energy headlines lately, but a noteworthy share of crude oil production growth the U.S. experiences over the next two or three years is sure to come from the Gulf of Mexico. There, far from the Delaware Basin land rush and the frenzy to build new Permian-to-wherever pipelines, a handful of deepwater production stalwarts are completing new wells — at relatively low cost — that connect to existing offshore platforms. Taken together, these projects are expected to increase the Gulf’s output by more than 300 Mb/d by the end of 2018. Today we look at the Gulf’s under-the-radar growth in oil output and the prospects for continued expansion there.  In 2016, U.S. crude oil production averaged 8.9 million barrels/day (MMb/d), according to the Energy Information Administration (EIA), with offshore production in the Gulf of Mexico (GOM) contributing 1.6 MMb/d—or 18.2%—of the total.  On an annual basis, that is an all-time high record level of offshore Gulf production!     As shown in Figure 1, GOM production was up to 1.75 MMb/d in January 2017, more than 300 Mb/d above GOM production when the Deepwater Horizon tragedy struck. and less than a fraction of a percentage point below the all-time record high for GOM hit in September 2009. There is a pretty good chance that record will fall in the next month or so. EIA expects 2017 GOM production to keep growing, increasing to 1.9 MMb/d in 2018. Admittedly, that’s an increase of only 300 Mb/d from 2016, which might not be groundbreaking news, but it sure puts the kibosh on any suggestion that production off the coasts of Texas, Louisiana, Mississippi and Alabama is dead in the water. It’s not—by a long shot.

US Shale (And US Gulf Of Mexico) Too Much For OPEC -- Bloomberg --  --Oilprice.com may be confused, but Bloomberg certainly is not, calling it like it is -- simply put, US shale is eating Saudi Arabia's lunch. OPEC's four-month experiment with production curbs has failed. More worryingly, the strength of shale's rebound suggests that OPEC faces a long-term struggle against this new source of supply in an industry where technological advances are the norm and today's niche play becomes the next decade's global standard. Total U.S. crude production has risen by more than 550,000 barrels a day in the 20 weeks since OPEC decided to cut output, according to weekly Department of Energy data. Much of that increase has come from shale formations. If this rate of growth -- a little under 30,000 barrels a day of new supply each week -- continues, U.S. output could top its recent peak of 9.61 million barrels a day shortly after OPEC meets on May 25 to consider its next move. That is bad enough for OPEC producers, but the picture just gets worse for them each month. The DoE publishes a monthly outlook and its views on domestic production are evolving rapidly -- and not in a way that suits OPEC.  Its latest forecast, published on April 11, pegs U.S. oil production at 9.24 million barrels a day by July. That is half a million barrels a day higher than it was forecasting for that month in November 2016, just before OPEC decided to restore output restraint. Its outlook for December 2017 has increased by 700,000 barrels a day over the same period.

Trump to sign offshore orders as 100th day in office, shutdown near --Ahead of his 100th day in the White House on Saturday, President Trump is expected this week to unveil details of major policy initiatives, including executive orders aimed at expanding oil and natural gas drilling in federal waters and an outline of his tax reform goals. The week will also be complicated by ongoing negotiations with Congress to keep the federal government from shutting down on Friday, as occurred in 2013. "So we expect a massive increase in military spending," Priebus said Sunday on NBC's "Meet the Press." "We expect money for border security in this bill. ... And it ought to be, because the president won overwhelmingly and everyone understands that building the border wall ... was part of it." On Friday, as those spending negotiations may still be ongoing, Trump is expected to sign "several" executive orders on energy, the White House said Sunday. "This builds on previous executive actions that have cleared the way for job-creating pipelines, innovations in energy production, and reduced unnecessary burden on energy producers," the White House said in a statement. The orders will include calls to redo the Obama administration's schedule for offshore lease sales and attempt to reverse Obama's prohibitions on drilling in Arctic and Atlantic waters. One order will call for the administration to redo the 2017-2022 federal offshore leasing plan, which was finalized by the Obama administration in November and currently includes 10 sales in the Gulf of Mexico and one in Alaska's Cook Inlet over those five years, but does not include sales in the Chukchi and Beaufort seas, which were removed from the plan before it was finalized. A proposed Atlantic lease sale had been removed from the plan in March 2016.

Trump aims to expand U.S. offshore drilling, despite low industry demand | Reuters: U.S. President Donald Trump signed an executive order on Friday to extend offshore oil and gas drilling to areas that have been off limits - a move meant to boost domestic production but which could fall flat due to weak industry demand for the acreage. The order could open up swathes of the Atlantic, Pacific and Arctic oceans, as well as the U.S. Gulf of Mexico, that former President Barack Obama had sought to protect from development after a huge BP (BP.L) oil spill in 2010. "We're opening it up....Today we're unleashing American energy and clearing the way for thousands and thousands of high-paying American energy jobs," Trump said as he signed the order. Trump had campaigned on a promise to do away with Obama-era environmental protections that he said were hobbling energy development without providing tangible benefits, pleasing industry and enraging environmental advocates. But the executive order, called the America-First Offshore Energy Strategy, comes as low oil prices and soaring onshore production have pushed industry demand for offshore leases near their lowest level in years, raising questions over the impact. A Reuters review of government data showed the amount of money that oil companies spent in the central Gulf of Mexico's annual lease sale dropped more than 75 percent between 2012 and 2017. Dollars bid per acre and the percentage of acreage receiving bids both declined more than 50 percent. The figures were similar in the western Gulf of Mexico, the only other zone that got offers for leases during that period, according to the figures from the U.S. Bureau of Ocean Energy Management.

People are willing to pay a lot to prevent another BP-like oil spill - According to a paper published in the journal Science on Thursday, Americans are willing to pay $17.2 billion to prevent another BP Deepwater Horizon oil spill. Thanks to a team of scientists who conducted a six-year study into the effects of the 134-million-gallon spill, we now have a more accurate picture of the devastating consequences—and also how desperately we want to reduce our dependency.  To relate the true damages of an oil spill of this magnitude, researchers set out to equate the damage in monetary terms, as so often we view natural resources as permanent and limitless. In order to arrive at the $17.2 billion figure, scientists surveyed households across the country to see how much they’d be willing to pay to avoid similar spills in the future. Along with asking participants these questions, the study authors included detailed accounts of the damage already done to beaches, animals, marine life, and marshland. As one of the paper’s authors, Kevin Boyle, explained to Virginia Tech News, “This is proof that our natural resources have an immense monetary value to citizens of the United States who visit the Gulf and to those who simply care that this valuable resource is not damaged.” Commissioned by the U.S. National Oceanic and Atmospheric Administration one month after the 2010 spill, the long-awaited study can now give us some insight into the actual dollar value of devastating the environment. What they also found was an overwhelming public willingness to put hard-earned cash into prevention funds. According to the survey, the majority of households said they’d willingly pay $153 each for prevention measures. Adding up all the reported figures led researchers to the $17.2 billion total.  Here's a link to the Science article.

Massive Natural Gas Deposit Discovered In The Gulf Coast Basin- Technological advancements have just pushed the boundaries of recoverable oil and gas in the U.S. further, according to an announcement by the U.S. Geological Survey. The agency reported that two formations in the Gulf Coast Basin may contain as much as 304.4 trillion cubic feet of natural gas plus 1.9 billion barrels of natural gas liquids, making the area the largest untapped continuous gas deposit in the country. The two formations—Haynesville and Bossier—also contain some 4 billion barrels of crude, according to mean estimates, the USGS also said in a press release. It bears noting, however, that these are mean estimates of the reserves contained in the two formations. For gas, the range runs from 37.1 trillion cu ft to 223.5 trillion cu ft for Bossier, and from 96.3 trillion cu ft to 341 trillion cu ft for Haynesville. Still, even the minimum estimates are impressive, and could theoretically push gas prices even lower. Meanwhile, the EIA said in a recent report that natural gas will surpass coal as the top power generation fuel this summer – some good news on the demand side. Gas, the authority expects, will account for 34 percent of generation fuels, versus 32 percent for coal. As good as this is—the third summer in a row that power plants in the U.S. will use more gas than coal—the summer 2017 estimate is lower than the 36 percent that gas accounted for last summer.

The US Geological Survey may have found the largest untapped natural-gas deposit in the country - Technological advancements have just pushed the boundaries of recoverable oil and gas in the U.S. further, according to an announcement by the U.S. Geological Survey. The agency reported that two formations in the Gulf Coast Basin may contain as much as 304.4 trillion cubic feet of natural gas plus 1.9 billion barrels of natural gas liquids, making the area the largest untapped continuous gas deposit in the country. The two formations—Haynesville and Bossier—also contain some 4 billion barrels of crude, according to mean estimates, the USGS also said in a press release. Technological advancements have just pushed the boundaries of recoverable oil and gas in the U.S. further, according to an announcement by the U.S. Geological Survey. The agency reportedthat two formations in the Gulf Coast Basin may contain as much as 304.4 trillion cubic feet of natural gas plus 1.9 billion barrels of natural gas liquids, making the area the largest untapped continuous gas deposit in the country.   The two formations—Haynesville and Bossier—also contain some 4 billion barrels of crude, according to mean estimates, the USGS also said in a press release.   The USGS has been reassessing a lot of oil and gas deposits across the U.S., noting how new exploration and extraction technologies have been “a game-changer” for the industry. Indeed, the last assessment of the Haynesville and Bossier formations was conducted seven years ago, and oil and gas technology has undergone major evolution since then.  It bears noting, however, that these are mean estimates of the reserves contained in the two formations. For gas, the range runs from 37.1 trillion cu ft to 223.5 trillion cu ft for Bossier, and from 96.3 trillion cu ft to 341 trillion cu ft for Haynesville. Still, even the minimum estimates are impressive, and could theoretically push gas prices even lower.

Golden Pass LNG cleared to export-  The Golden Pass LNG terminal on the Texas Gulf Coast was cleared by the Department of Energy Tuesday to begin exporting up to 2.21 billion cubic feet of gas per day.  Located outside Sabine Pass, the Golden Pass terminal was built to import LNG from abroad in 2009. But following the boom in domestic gas production through hydraulic fracturing and horizontal drilling, Golden Pass, a joint venture between Qatar Petroleum, ExxonMobil and ConocoPhillips, shifted gears.  The approval adds to a growing list of LNG export terminals under development in the United States. Cheniere Energy began exporting last year from its Sabine Pass terminal in Louisiana. As of January, there were seven facilities under construction and another four that had been approved but not yet begun construction, according to the Federal Energy Regulatory Commission. “This announcement is another example of President Trump’s leadership in making the United States an energy dominant force,” U.S. Secretary of Energy Rick Perry said in a statement Tuesday. “This is not only good for our economy and American jobs but also assists other countries with their energy security.” There has been no announcement on when the export facility will be completed. But Golden Pass is estimating construction will provide 45,000 direct and indirect jobs over five years, along with another 3,800 direct and indirect jobs over the next 25 years when the facility becomes operational.

US DOE clears way for LNG exports by Golden Pass into uncertain global market - Against a backdrop of a seemingly glutted global LNG market and continued concerns about the impact on US natural gas prices, the Department of Energy on Tuesday turned thumbs up on a plan by Golden Pass Products to export domestically produced LNG to countries that do not have a free trade agreement with the US. With the DOE nod, Golden Pass is authorized to send out the equivalent of 2.21 Bcf/d of gas from a terminal to be developed near Sabine Pass in Jefferson County, Texas. Platts Analytics' Bentek Energy expects that global LNG markets will remain oversupplied through 2022 based on the current slate of forecast LNG export projects. Further, Platts Analytics expects that global gas prices will not support incremental spot supply during this oversupply period, which could discourage the signing of new LNG supply contracts. According to DOE, the Golden Pass order brings to 19.2 Bcf/d the total LNG exports to non-FTA countries authorized to date from planned and operational facilities in Texas, Louisiana, Florida, Georgia and Maryland. "These projects, if built, would position the United States to be the dominant LNG exporter in the world," said DOE in a statement. Clearance for the construction and operation of LNG export terminals is left to the Federal Energy Regulatory Commission, while DOE makes a national interest determination that looks largely at the expected impact of an export on the US economy and consumers. 

Developing new liquefaction capacity in an era of LNG oversupply -  In only three years, the international liquefied natural gas (LNG) market has undergone a major transformation. The old order, founded on long-term, bilateral contracts with LNG prices linked to crude oil prices, is being replaced by a more-fluid, more-competitive paradigm. That’s good news for LNG buyers, who are benefiting from a supply glut and lower LNG prices—the twin results of slower-than-expected demand growth in 2014-15 and the addition of several new liquefaction/LNG export facilities in Australia and the U.S. But the new paradigm poses a challenge for facility developers: How do they line up commitments for new liquefaction/LNG export capacity that will be needed a few years from now in a market characterized by LNG oversupply and rock-bottom prices? Today we begin a two-part series that considers the hurdles developers face and which types of projects may have the best prospects. When the first wave of U.S. liquefaction plants and LNG export facilities was in early stages of development a while back, LNG buyers and marketers were willing to enter into long-term, take-or-pay contracts for significant amounts of liquefaction capacity. These Sales and Purchase Agreements (SPAs) provided the financial underpinning for multibillion-dollar projects like Cheniere Energy’s Sabine Pass LNG facility in southwestern Louisiana, where three liquefaction trains already are operating, a fourth is gearing up to run, and a fifth is nearing completion (see Train Kept A-Rollin’). Banks and other lenders had confidence that these projects, backed by 20- or 25-year SPAs signed by creditworthy counterparties, would generate the revenue needed to pay off what their developers had borrowed. In the past few years, however, many of the fundamentals governing the international LNG market have shifted, and developers of a prospective second wave of U.S. liquefaction/LNG export projects will need to be creative in lining up the commitments (and the financing) required to make their projects a go. Most important, perhaps, the old order, with its bilateral deals and oil-linked prices, continues to be undone. In fact, Cheniere’s Sabine Pass LNG contributed to this undoing by offering LNG pegged to the price of U.S. natural gas: the sum of 115% of the Henry Hub gas price plus a flat liquefaction fee.

Cheniere ships LNG to Poland as Europe seeks less reliance on Russian gas | Fuel Fix: The U.S. is set to ship its first shale gas to a member of the former Soviet bloc as Europe seeks to cut its dependence on fuel from Russia. Poland’s state-owned PGNiG SA bought a spot liquefied natural gas cargo from Cheniere Energy Inc.’s Sabine Pass plant for delivery in June to the nation’s Baltic Sea import terminal, the first such contract for Central and Eastern Europe, it said Thursday. No LNG has been shipped to northern Europe since Sabine Pass started exports more than a year ago. Poland may offer a new outlet for Cheniere, which said it’s targeting emerging markets as new production facilities from Australia to the U.S. lead to a glut of the fuel. Poland’s Law & Justice government has sought to cut the nation’s dependence on Russia’s Gazprom PJSC for more than two-thirds of gas supplies, stating it has no plan to extend a long-term supply contract beyond 2022 and plans new infrastructure including a pipeline to Norway. The deal comes after PGNiG opened an LNG trading office in London in February and “proves Poland is a gateway for American LNG to central and eastern Europe,” Chief Executive Officer Piotr Wozniak said in a statement. The agreement is historic and “commercially attractive,” Polish Prime Minister Beata Szydlo said in an interview with TVP Info television on Thursday, without being more specific on pricing.

Distillate export boom keeps U.S. refiners busy: Kemp - (Reuters) - U.S. refiners have become a powerhouse of distillate exports, causing the supply-demand balance for fuels from the middle of the barrel to tighten in the United States despite a very warm winter.Exports of distillate fuel oil rose to a record 1.4 million barrels per day (bpd) in the week ending April 14, according to the U.S. Energy Information Administration.So far this year, exports have averaged almost 1.1 million bpd, during what is normally a seasonal lull, and will likely accelerate over the summer months.The result is that U.S. stocks of distillates, such as home heating fuel and diesel fuel, have emerged from the end of winter looking somewhat tight despite heavy levels of refinery processing.Distillate stocks stood at 148 million barrels on April 14, which was 19 million barrels above the 10-year average but 13 million barrels below the level at the corresponding point in 2016 (http://tmsnrt.rs/2pdRLCT).Stocks have been tightening against both the prior-year level and the 10-year average since the start of February and only high levels of refinery processing have kept them from drawing down even further (http://tmsnrt.rs/2pdRP5B).Even so, stocks have fallen by almost 15 million barrels since the start of 2017 compared with an average decline of about 10 million barrels and a build of more than 2 million barrels in 2016 (http://tmsnrt.rs/2p0QwIt).Stocks have fallen even though heating demand has been 2 percent lower than in 2016 and 17 percent below the long-term average because of the unusually mild weather across the country this winter (http://tmsnrt.rs/2oGrivw).Most distillate is being exported to Mexico, Brazil and other countries in Latin America and the Caribbean, where ageing local refineries are struggling to keep up with growing demand.Smaller volumes have also been shipped to markets in Europe, according to U.S. customs data analysed by the EIA.Exports are set to remain strong given the chronic shortage of distillate refining capacity across Central and South America.But U.S. domestic distillate consumption is also forecast to rise again in 2017 after falling significantly in 2016 and 2015 which will tighten the supply-demand balance even further.  EIA forecasts that domestic consumption will rise by 70,000 bpd in 2017 and another 120,000 bpd in 2018 (“Short-Term Energy Outlook”, EIA, April 2017).Hedge funds and other money managers have responded by building one of the largest bullish positions in distillate since crude oil prices crashed in the middle of 2014.

Icahn's oil refiner reports plunge in biofuels bill in first quarter | Reuters: Biofuels compliance expenses for CVR Energy's refining unit fell to the lowest level in almost five years during the first quarter, the company said on Thursday, as the U.S. government weighs an overhaul of its renewable fuels policy. The cost of compliance credits required by the Renewable Fuel Standard (RFS) have fallen sharply in recent months, driven in part by a proposal to alter the regulation by shifting the blending burden away from refiners to fuel terminals. The proposal was made in February by Carl Icahn, the majority owner of CVR Energy and an informal adviser to President Donald Trump on regulation. The White House is considering it. CVR said it spent $6.4 million on the compliance credits in the quarter. That was down 85 percent from last year, the company said on a conference call with investors to discuss quarterly earnings. CVR attributed the decline in part to lower prices. Renewable fuel credit prices averaged about 53 cents in the first three months of 2017, about one-third lower than the prior-year, Oil Price Information Service data show. CVR declined to explain in greater detail the full reasons for the sharp reduction. "We don't discuss our market activity," Chief Executive Officer Jack Lipinski said, when asked by an analyst on the call about how to square the low first-quarter expenses with CVR's projections of a full-year cost of $170 million. The first-quarter tab was CVR's lowest since the second quarter of 2012, a review of Securities and Exchange filings showed. CVR positioned itself to slash regulatory costs by deferring the purchase of some $186 million worth of credits it needed to satisfy its biofuels requirements at the end of 2016, the company said in filings in February. Lipinski and Icahn have argued that the U.S. renewable fuels program unfairly punishes independent refiners by pushing them into a highly speculative credit market.

Maiden Bakken oil cargo to Asia ships out, with more to come | Reuters: The first ever reported export of North Dakota's crude oil to Asia left port last month, according to a shipping document seen by Reuters on Wednesday, in what is expected to be the first of numerous cargoes once the key Dakota Access pipeline starts moving oil in May. Swiss-based Mercuria Energy Trading S.A. loaded more than 600,000 barrels of Bakken crude, as well as some Mars Sour crude, in late March off the coast of Louisiana onto the very large crude carrier (VLCC) Maran Canopus, destined for Singapore, according to the bill of loading and ship tracking data. The burgeoning appetite for U.S. crude among Asian refiners could be a boon for Bakken crude, especially when the Dakota pipeline starts up. That line can carry 470,000 barrels per day of oil from North Dakota's Bakken play to the Gulf, the starting point for the lion's share of U.S. oil exports. At least two Asian refiners told Reuters that they are interested in Bakken light crude because of the products it can yield through refining. "There seems to be increasing demand for light quality crude in Asia," said Michael Cohen, head of energy commodities research at Barclays. "I think with Dakota Access coming online, it makes the pipeline route from the Bakken to the Gulf Coast more economical." Mercuria could not immediately be reached for comment. With the start of Dakota Access (DAPL), Bakken producers such as Hess Corp and Continental Resources for the first time will have a direct route to export terminals on the Gulf Coast, better connecting them to international markets.

Texas oil and gas industry in ‘new cycle of expansion’ -- The oil and gas industry, after suffering through the worst downturn in at least three decades, is embarking on “a new cycle of expansion” as companies send dozens of new rigs into Texas oil fields, drill hundreds of more wells and hire thousands of workers. The rig count is up 80 percent in Texas over the first quarter last year. Drilling permits have doubled, to 1,300. And state oil and gas employment has risen by 9,000 from the trough in September, according to Texas Petro Index, a monthly report on the state’s oil and gas activity released this week. Energy companies have added jobs in Texas for five consecutive months, according to the Texas Workforce Commission, while manufacturing, which is tied closely to the state’s oil and gas industry, added a record number of jobs in February. Meanwhile, a recent survey by the Federal Reserve Bank of Dallas found oil and gas executives upbeat, reporting increases in oil and gas production, drilling equipment needs, capital expenditures and salaries and benefits, and expecting an even better 2018.

Permian Basin oil production and resource assessments continue to increase - Crude oil production in the Permian Basin is expected to increase to an estimated 2.4 million barrels per day (b/d) in May, based on estimates from EIA’s Drilling Productivity Report. Between January 2016 and March 2017, oil production in the Permian Basin increased in all but three months, even as domestic crude oil prices fell. As production in other regions fell throughout most of 2015 and 2016, the Permian provided a growing share of U.S. crude oil production.  With rising oil prices over the past year, the Permian continues to be attractive to drillers, as reflected in rising rig counts. As of April 21, 2017, the number of rigs in the Permian Basin reached 340, or 40% of the 857 total oil- and natural gas-directed rigs operating in the United States. The Permian rig count reached as high as 568 in late 2014 before falling to a low of 134 in spring 2016. The land area over the Permian Basin covers more than 75,000 square miles in 43 counties of western Texas and southeastern New Mexico. However, more than half of the rigs that have been added in the Permian are concentrated in just five counties: Reeves, Loving, Midland, and Martin counties in Texas and Lea County in New Mexico. Oil production from these five counties averaged 882,000 b/d as of November 2016 and accounted for approximately 42% of total Permian Basin oil production (2.1 million b/d) in that month. As more rigs continue to be moved to these counties, production from these areas is expected to continue to increase, which will drive the increases in total Permian production.  Recent geological surveys have further explored the resources contained in the Permian Basin. In November 2016, the U.S. Geological Survey (USGS) estimated that technically recoverable tight oil and shale gas resources in the Midland Basin portion of Texas’ Permian Basin (specifically the Wolfcamp shale formation) could exceed 20 billion barrels of oil, 16 trillion cubic feet of natural gas, and 1.6 billion barrels of hydrocarbon gas liquids. The technically recoverable resource estimate for tight oil in the Midland is higher than any previous USGS assessment of tight oil resources in any domestic resource basin.

Railroad Commission rejects ranchers’ appeal to reconsider Hilcorp enhanced oil recovery project – The Railroad Commission of Texas, the state’s oil and gas regulator, rejected on Tuesday an appeal from a Gulf Coast water conservation district to block several injection wells, which local cattle ranchers fear will pollute their groundwater supply. For years, the Texana Groundwater District has been fighting Houston-based Hilcorp Energy over an enhanced oil recovery project in Jackson County that will recover 60 million barrels of oil from an 80-year-old oilfield. Hilcorp is injecting wastewater — a by-product of fracking — and carbon dioxide underground to help force oil to the surface. Locals say unplugged and poorly plugged wells riddle the oilfield, where they have found leaks and spills of chemicals in years past. The ranchers and farmers in the area wanted the commission to require groundwater monitoring as a condition of the project, but the commission opted to let Hilcorp run its own groundwater monitoring program.Ranchers like Johnny Dugger, who relies on a well to bring water to hundreds of cattle on his land, say their concerns have been sidelined by a regulatory agency that consistently favors industry interests. Dugger and others have said they support the project, but on the condition that the groundwater be independently monitored. The Railroad Commissioners, all of whom accept hundreds of thousands of campaign donations from the oil and gas industry, have said those donations do not affect their impartiality.

Exxon released 10 million pounds of air pollution in Texas - ExxonMobil has lost a legal fight against environmentalists in its home state of Texas over air pollution at one of the oil giant's oldest refineries. A Texas court ordered Exxon (XOM) on Wednesday to pay $20 million in fines for pollutants released into the air at the Baytown, Texas refining and chemical plant outside of Houston. U.S. District Judge David Hittner cited "serious" violations that resulted in the release of about 10 million pounds of pollutants into the atmosphere. The judge ruled in favor of the Sierra Club and Environment Texas Citizen Lobby, finding Exxon violated the Clean Air Act 16,386 times between October 2005 and September 2013. The court found that Exxon enjoyed $14.2 million in economic benefits by delaying the installation of infrared imaging and other monitoring improvements at the facility, which makes everything from jet fuel to plastic. "Today's decision sends a resounding message that it will not pay to pollute Texas," Neil Carman, clean air program director for the Sierra Club's Lone Star Chapter, said in a statement. "We will not stand idly by when polluters put our health and safety at risk." In addition to the civil penalties, Exxon has also been ordered to pay the environmental groups' legal and expert fees.

How Rising Sand Prices and Supply Concerns Threaten Producer Profitability - The techniques used to wring increasing volumes of crude oil, natural gas and natural gas liquids (NGLs) out of shale continue to evolve, and as they do, producers are facing mounting costs for securing frac sand and for disposing of produced water from the wells. These costs are squeezing producer profits, and—in an era of sustained low hydrocarbon prices—sometimes even flip production economics from favorable to unfavorable. Today we continue our surfing-themed series on sand costs and water-disposal expenses with a look at how sand use in shale plays has evolved—and how these changes affect the bottom line.  In Part 1 of this blog series, we discussed how the trend toward much longer laterals and high-intensity well completions has significantly increased the volume of frac sand being used, with some individual well completions using enough sand to fill 100 railcars or more. We also noted that an even bigger concern for many producers is the rising cost of disposing of produced water—that is, the water that emerges with hydrocarbons from these supersized wells. As we said in Tales of the Tight Sand Laterals, freeing the vast amounts of oil, gas and NGLs trapped in shale and tight sands requires horizontal drilling to access the long, horizontal layers where the trapped hydrocarbons reside, and proppant (natural sand, ceramics and resin-coated sand) that, when forced out of the horizontal portion of wells at high pressure (using water and other fluids), fracture openings in the surrounding shale/tight sands. When the pressure is released, the fractures attempt to close but the proppant contained in the fluids keeps them open, making a ready path for oil, gas, NGLs and produced water to flow into the well bore.

Demand and the Frac Sand Example - A nice lively example of shifts in demand comes from the demand for sand used in hydraulic fracking operations. As the Wall Street Journal recently reported, "Latest Threat to U.S. Oil Drillers: The Rocketing Price of Sand: The market for a key ingredient in fracking is again surging," A couple of years ago, the USGS published "Frac Sand in the United States—A Geological and Industry Overview,"  with a section on "Frac Sand Consumption History" contributed by Donald I. Bleiwas. The report includes this useful figure, in which the bars show the metric tons of sand used for fracking (measured on the left axis); the numbers above the bars show the number of horizontal drilling rigs in operation in the US during any given week of the year; and the line shows the value of the sand (right axis). The basic lesson is fracking is up and it is using a lot more sand. If you look a little more closely at the years from 2010 to 2012, you can see that the number of horizontal drilling rigs rose from 822 to 1,151, but the quantity of sand being used more than doubled.  This data can be updated a bit. According to the Baker Hughes North American Rotary Rig Count, the number of horizontal rigs dropped in 2015 and stayed fairly at this lower level in 2016, as the price of oil dropped, but more recently the number of horizontal rigs is rising again.  For an update through 2016 on production levels and price, the USGS publishes an annual fact sheet on various minerals. Fracking sand falls into the category of "Industrial Sand and Gravel," of which more than 70% is used for fracking. Here's the relevant table from the 2017 factsheet. Thus, back in 2012 there was about 50 million tons of total sand production, with about 70% of it going to fracking. By 2014, output of sand had doubled--mostly due to increased demand from fracking. The price per ton rose from $52 in 2010 to $106 per ton in 2014. Then output and price sagged in 2015 and 2016. The Wall Street Journal story reports rising prices for sand this year. It also notes: "In Louisiana, Chesapeake Energy Corp. recently pumped a record 50.2 million pounds of sand into a horizontal well roughly 1.8 miles long, piquing the interest of some rivals who are now weighing whether they can do the same." And here's a figure showing quantities of sand being used in different fields. No world-changing lessons here. The higher prices for sand don't seem likely to make much difference in the quantity of fracking, least for now, because sand is a fairly small slice of the overall cost. Environmental concerns are being already being raised in some US locations about the extent of sand-mining, and those concerns are likely to become more acute as the demand for fracking sand rises. But my guess is that if it becomes difficult to increase the supply of fracking sand, then those doing the fracking will either find ways to economize on sand or will figure out some alternative substances that would fill a similar purpose.

Buffalo Pipeline Leaks 19,000 Gallons of Crude Oil on Farmland in Oklahoma -   The Buffalo Pipeline, owned by Houston-based Plains All American Pipeline, L.P. , leaked approximately 450 barrels, or roughly 18,900 gallons, of crude oil onto farmland in Kingfisher County, Oklahoma last week. Wheat farmer and cattle rancher Steve Pope told local TV station KFOR that he has lost an estimated 120 acres of pasture and wheat crop from the spill.   The National Response Center on Sunday listed "internal corrosion" of the pipeline as the likely cause of the discharge. Plains All American Pipeline released a statement about the spill: "On Friday, April 21, 2017, Plains All American Pipeline, L.P. experienced a crude oil release on our Buffalo Pipeline, near Loyal, Okla. We are following our emergency response plan, and our staff is working with regulators and affected landowners. Our current priorities are to ensure the safety of all involved and limit the environmental impact of the release.  The oil spill happened less than 1,000 feet from the nearby Cooper Creek, which feeds into the Cimarron River, but the spill was contained on Pope's fields. Cleanup is underway at the site of the leak.  Pope expressed concerns about the damage from the spill as well as President Trump 's proposed budget cuts to the U.S. Environmental Protection Agency ( EPA ), now led by former Oklahoma Attorney General Scott Pruitt . "What bothers me is we keep seeing the EPA being cut so much," Pope told KFOR.  "A lot of the regulations that have been put on the oil companies are there for a reason.."

State braces for protests during hearings on Keystone XL pipeline - The Nebraska Public Service Commission is setting aside five days in August to take comments on the proposed route of the Keystone XL oil pipeline. TransCanada has filed for approval of the route from north-central to southeast Nebraska. The routing of the Dakota Access pipeline led to protests and arrests in North Dakota. Governor Pete Ricketts says they’ll prepare for similar trouble here. “Certainly we want to protect people’s free speech rights and allow them to be able to protest but we also have to do it in a way that is protesting lawfully and that’s not what we saw in North Dakota,” Ricketts says. “We saw people violating private property rights, trespassing, and in some cases, it started to turn violent.” Ricketts says there are concerns about protesters from elsewhere joining in. “There’s certainly going to be people in Nebraska with legitimate concerns about the pipeline and they’ll want to express those, but if we have people coming in from out-of-state, those are the ones that can end up being dangerous,” Ricketts says. “They really don’t care about the local Nebraskans. They’re there for a political agenda.” Ricketts says oil pipelines like Keystone XL are still needed to fuel the economy. “We want to be responsible stewards of the land but we can’t shut down fossil fuels or our society would come to a screeching halt,” the governor says. “We really have to watch out for these radical environmentalists who are coming in from outside the state. These are the people who are typically going to be causing more problems, not the people from inside the state who really want to express their concerns about the pipelines.”

Newspaper Owned By Fracking Billionaire Leaks Memo Calling Pipeline Opponents Potential “Terrorists” - Steve Horn – The U.S. Department of Homeland Security (DHS) has published a report titled, “Potential Domestic Terrorist Threats to Multi-State Diamond Pipeline Construction Project,” dated April 7 and first published by The Washington Examiner. The DHS field analysis report points to lessons from policing the Dakota Access pipeline, saying they can be applied to the ongoing controversy over the Diamond pipeline, which, when complete, will stretch from Cushing, Oklahoma to Memphis, Tennessee. While lacking “credible information” of such a potential threat, DHS concluded that “the most likely potential domestic terrorist threat to the Diamond Pipeline … is from environmental rights extremists motivated by resentment over perceived environmental destruction.”  The Washington Examiner is owned by conservative billionaire Philip Anschutz, a former American Petroleum Institute board member. His company, Anschutz Exploration Corporation, is a major oil and gas driller involved in the hydraulic fracturing (“fracking”) in states such as Wyoming, Colorado, and New Mexico. In his story, Paul Bedard, the Examiner columnist who published the document , did not explain how he obtained the document marked “Unclassified / For Official Use Only,” and the memo is not up on the DHS website. The DHS also did not respond to multiple requests for comment, nor did Fox News 13 in Memphis, which also ran a story on the memo.  Anschutz, a major Republican Party donor, formerly owned the company Pacific Energy Partners,which was sold to Lehman Brothers and then immediately to Plains All American for $2.4 billion in 2006.  The DHS report isn’t the only sign of backlash against pipeline opponents unfolding in the Sooner State.  On February 28, the Oklahoma House of Representatives passed HB 1123, which was introduced by Republican Rep. Scott Biggs and sets harsh mandatory punishments for trespassing and a list of other crimes related to “critical infrastructure.” In the most severe scenario, citizens could receive a felony sentencing, $100,000 fine, and/or 10 years in prison if their actions “willfully damage, destroy, vandalize, deface or tamper with equipment in a critical infrastructure facility.”

Trump Signs Executive Order Targeting National Monuments, Could Open Up Lands for Oil and Gas Development - President Trump signed an executive order Wednesday ordering a review of the Antiquities Act and national monuments on more than 100,000 acres. The review enables the Department of Interior to examine whether any of the monument designations have led to a "loss of jobs, reduced wages and reduced public access." "The Antiquities Act does not give the federal government unlimited power to lock up millions of acres of land and water," President Donald Trump said during a brief ceremony today flanked by Vice President Mike Pence and Sec. of the Interior Ryan Zinke. He added that it was "time to end this abusive practice." The 1.35-million acre Bears Ears National Monument in Utah is one of the first targets for review. The monument was created by President Obama last year and has sparked major controversy between Republican lawmakers and conservationists. Utah Gov. Gary Herbert and Utah's congressional delegation led by Congressmen Rob Bishop and Jason Chaffetz and Senators Orrin Hatch and Mike Lee have launched a campaign to abolish national monument. More than 270 million acres of American land and waters are potentially at risk—an area two and a half times the size of California. GOP lawmakers have accused President Obama, who designated more monuments than any other president, of abusing the Antiquities Act to protect land from fossil fuel development. "By potentially rolling back safeguards for lands and waters that are currently protected from destructive development for generations to come, Trump is carving up this beautiful country into as many corporate giveaways for the oil and gas industry as possible," said Diana Best of Greenpeace USA . "People in this country who cannot afford the membership fee at Mar-a-Lago want safe water they can drink and public lands for their communities to enjoy."

Trump wants to make it easier to drill in national parks. We mapped the 42 parks at risk (Vox) It’s no secret that oil and gas companies are on the hunt for new places to drill. But the quest for more fossil fuels could heat up in places you might not expect: our national parks.With President Donald Trump’s executive order on energy, federal agencies are now reviewing all rules that inhibit domestic energy production. And that includes regulations around drilling in national parks that, if overturned, could give oil and gas companies easier access to leases on federal lands they’ve long coveted."This opportunity is unique, maybe once in a lifetime," Jack Gerard, president of the American Petroleum Institute lobby group, told Reuters. It could also put some of America’s most pristine and ecologically sensitive areas at risk of oil spills, ground contamination, and explosions.  There are currently more than 500 active oil and gas wells spread across 12 national parks, as you can see in the map below. In 2015, drilling on federal lands made up nearly a fifth of overall US production.  If you’re wondering why it’s legal to drill in national parks in the first place, it’s due to a little-known set of rules called the “9B regulations.”   Introduced in 1978, the 9B rules manage issues of “split estate,” or instances where the federal government owns the surface land but private individuals and companies own the mineral rights below ground. As Nicholas Lund, a senior manager at the National Parks Conservation Association, told Vox, these well rights often predate the parks. “A lot of the reasons these wells exist is because when the federal government purchased the park, they weren’t able to obtain the well,” he said. “Either the owners refused to sell them the subservice area or the government set park boundaries that included oil and gas in it.” The rules were last updated in 2016 and include a number of basic safety and environmental measures to mitigate the impact of drilling in national parks. But now, under the Trump administration, those safeguards are at risk of being watered down or repealed, shifting the burden to protect national parks to environmental watchdogs. And 30 additional national parks with split estate situations could be opened for drilling in the future.

Trump is expected to sign orders that could expand access to fossil fuels    - After moving last month against Barack Obama’s efforts to limit fossil fuel exploration and combat climate change, President Trump will complete his effort to overturn environmental policy this week, signing two executive orders to expand offshore drilling and roll back conservation on public lands. On Wednesday, Mr. Trump signed an executive order directing his interior secretary, Ryan Zinke, to review national monuments designated by previous presidents under the Antiquities Act of 1906, aiming to roll back the borders of protected lands and open them to drilling, mining and logging. The president is then expected to follow up on Friday with another executive order aimed at opening up protected waters in the Atlantic and Arctic Oceans to offshore drilling. The order would direct Mr. Zinke to revisit an Obama administration plan that would have put those waters off limits to drilling through 2022. Friday’s order is also expected to call for the lifting of a permanent ban on drilling in an area including many of those same waters — a measure Mr. Obama issued in December 2016 in a last-ditch effort to protect his environmental legacy from his drilling-enthusiast successor. The moves — just before Mr. Trump’s 100th day in office — would begin to fulfill a central campaign promise to unleash a wave of new oil and gas drilling and create thousands of jobs in energy. The reality is more complicated, experts in the law, policy and economics of energy said. The orders are not likely to lead either to significant new energy development or to job creation in the near future. With oil prices around $50 a barrel and production already glutting world markets, few oil companies are making plans to expand into costlier, riskier offshore drilling. 

Anadarko Crashes To 7-Month Lows; Shuts 3,000 Wells In Colorado After Explosions -- Anadarko shares are down over 7% to 7-month lows following a home blast near a vertical well operated by the company causing it to shut all its vertical wells in northwestern Colorado while it investigates the cause of the blast, which killed two people.As OilPrice.com's Irina Slave reports, the number of wells in the area that the company operates is more than 3,000, with a combined output of 13,000 net barrels of oil per day.Anadarko has tasked local field personnel to check the production equipment at the wellheads and the underground lines that connected them. The local Frederick-Firestone Fire Protection District is meanwhile conducting its own investigation, and told Bloomberg that the proximity of the oil well to the home where the blast occurred is one aspect to be considered, adding that the cause for the explosion has yet to be identified. There is no threat to other homes in the vicinity, the authorities said. Anadarko, which is reporting Q1 2017 financial results at the end of the month, last booked a net loss of $3.07 million for the fourth quarter of 2016, on revenues of $7.87 million. Now,some analysts are again expecting a loss: Seaport Global Securities expects the company to report a net loss of $0.41 per share, which is an improvement of the company’s earlier forecast for Anadarko, which saw it posting a net negative $0.44 per share for the first quarter of the year.The company plans to boost onshore oil production by 13 percent this year from last, when it was 31 percent lower than the 2015 output. Over the medium term, Anadarko projects a minimum 600,000 bpd from its DJ Basin and Delaware Basin acreage, provided prices stay between $50 and $60 a barrel. In 2016, this output totaled 287,000 bpd, and this year’s production rate is set at 360,000 bpd.

As Firestone investigation continues, state won't shut down other operators' older wells - Not only is the Frederick-Firestone Fire Protection District investigating the cause of a deadly blast at a Firestone home last week, but the Colorado Oil and Gas Conservation Commission and an international petroleum company have confirmed their involvement in the probe. Fire investigators, police and environmental consultants as well as oil and gas crews continue to look for clues in the rubble at 6312 Twilight Ave., where the blast and fire killed two men in the basement and a woman was seriously burned. Meanwhile, construction workers continue work on future apartments behind the neighborhood. Less than 200 feet from the southeast corner of the house sits a vertical oil and gas well owned by Anadarko Petroleum Corporation. It has since been shut off among more than 3,000 of the company's older wells in response to the tragedy, according to the company Wednesday. On Thursday, state officials said the company's decision was voluntary, and therefore the state will not require other oil and gas operators in Colorado to shut their wells. Boulder County commissioners called for other operators to shut vertical wells in their county.Matt Lepore, the commission's director, said in a press briefing that the Oak Meadows neighborhood has been deemed safe from methane and hydrocarbon gases, based on an environmental investigation. But he said a consultant on Wednesday conducted follow-up testing for gases in the soil surrounding the rubble of the home. Those findings have not yet been released. Similarly, the Frederick-Firestone Fire Protection District has not yet released an origin or cause of the deadly explosion, and the multi-agency investigation led by the local fire district is ongoing. Lepore said the commission's role "is limited to our jurisdiction, which would not include all of the aspects of the investigation."

Lawmakers: Conclusions Shouldn't Be Drawn From Explosion Development – After the house explosion in Firestone that prompted company Annadarko to close more than 3,000 vertical wells, CBS4 looked into regulations regarding development and proximity to wells. The fatal April 17 blast in the Weld County town happened near a gas well, and its cause is still under investigation. There are currently no state laws regulating how far away developers should build homes from a gas well, and lawmakers in Colorado are cautioning that not enough is known about the explosion to draw any conclusions at this point. Those on both sides of the oil and gas debate agree that the explosion shouldn’t be used to further any political agenda. While the state controls setbacks for oil and gas developers — new wells can’t be drilled within 500 feet of a house — local governments determine how far a new house can be built from an existing well. In the case of the Firestone incident, the well was present about 22 years before the house was built. While Republicans and Democrats disagree on how far apart wells and houses should be, at this point neither side is suggesting the state should make decisions about where housing developments should be built. “When it comes to figuring out land use, nobody better knows that then the local residents, and they’re the ones who should make the decision. Not the Colorado Oil & Gas Conservation Commission, not the state legislature,” said Republican state Sen. Jerry Sonnenberg, who represents Sterling. Even if the investigation into the house explosion finds the gas well is to blame, CBS4 Political Specialist Shaun Boyd said there isn’t really any more time for new legislation during this Colorado legislative session. There are only two weeks left before it wraps up.

Oil And Gas Industry Power Builds Wells Near Schools In Colorado, Trumping Environmental Concerns - International Business Times - The political power of the oil and gas industry has been on display in Colorado this Spring. When an explosion earlier this month incinerated two men in a Colorado home near an aging oil well, the catastrophe could have prompted lawmakers to pass an initiative forcing the oil and gas industry to site such wells farther away from schools. But it was too late: Only days before the disaster, Republican lawmakers bankrolled by fossil fuel industry corporations had killed the bill to do just that. The legislation passed Colorado’s Democratic-controlled House just after a University of Colorado study suggested a possible link between child cancer rates and proximity to oil and gas sites. Despite that, the Republican-controlled upper chamber voted the measure down — only months after the state Senate GOP was raking in five- and six-figure checks from major oil and gas corporations operating in the state. An International Business Times review of campaign finance data found that individual and corporate donors from the oil and gas industry pumped more than $738,000 into Colorado Republican senators’ election fund during the 2016 election cycle, which immediately preceded GOP lawmakers’ move to kill the setback bill. In total, oil and gas industry donations comprised nearly a third of all the cash the fund pulled in during the election. The donations included a $45,000 contribution from Anadarko, whose well exploded in mid-April and which this week said it is shutting down 3,000 vertical wells across northeastern Colorado.  IBT reviewed campaign finance records compiled by the nonpartisan National Institute on Money in State Politics. Those records showed that the hundreds of thousands of dollars from the oil and gas industry flowed to the Senate Majority Fund, whose website says it is “dedicated to retaining a Republican majority in the Colorado Senate.” In all, since the 2014 election when the GOP took back the Colorado Senate, the oil and gas industry has delivered $1.1 million to the Senate Majority Fund, and a total of $1.25 million to Colorado Republican Party committees. Over the same period, oil and gas interests gave just $16,235 to Democratic Party committees in the state.

Oil Pipeline Spills 1,050 Gallons Into North Dakota Tributary - A pipeline in western North Dakota spilled an estimated 756 gallons of oil and 294 gallons of saltwater, a drilling byproduct, into a tributary of the Little Missouri River, the Associated Press reports. The spill was discovered April 22, approximately 5 miles southwest of the city of Marmarth and was reported that same day, the North Dakota Department of Health announced . The spill originated from a buried three-inch pipeline operated by Oklahoma City-based Continental Resources . The spill polluted a 14-mile stretch of Little Beaver Creek but did not reach the larger waterway. "At the time of the release there was a high-enough flow in the Little Missouri that it was actually pushing water back up into Little Beaver Creek, so that prevented any from getting into the Little Missouri," Health Department environmental scientist Bill Suess explained to the AP. Suess said that the cause of the leak is unknown, with excavation work still underway. More than three-fourths of the discharge has been cleaned up as of Sunday. He added that the thick consistency of the oil causes it to clump together in the water and form balls that float down the river, making it "pretty easy to collect."  There were no immediate indications of damage to wildlife or livestock, the AP said.

Oil pipeline spill pollutes North Dakota tributary - — A 1,050-gallon oil pipeline spill in western North Dakota polluted a tributary of the Little Missouri River but was prevented from flowing into the larger waterway by its fast-moving current, a state Health Department official said Tuesday. An estimated 756 gallons of oil and 294 gallons of saltwater, a drilling byproduct, leaked from a pipeline in Bowman County operated by Oklahoma City-based Continental Resources. The spill was discovered Saturday about 5 miles southwest of Marmarth, and more than three-fourths of the mess had been cleaned up as of Sunday. Health Department environmental scientist Bill Suess was traveling to the site Tuesday and didn’t have an update on cleanup. Continental Resources spokeswoman Kristin Thomas didn’t immediately respond to a request for comment. The company reported the spill Saturday and state officials went immediately to the site, which is in a remote area with little access, according to the Health Department, which announced the spill Monday afternoon. There was no danger to the public due to the delay, as no one lives in the area and anyone wishing to swim or fish in the creek would have been warned away by company and state officials at the scene, Suess said. The cause of the leak was unknown, with excavation work still underway.   The spill polluted a 14-mile stretch of Little Beaver Creek. The company believes fewer than 50 gallons made it into the water, with the Health Department estimating about double that, Suess said. “At the time of the release there was a high-enough flow in the Little Missouri that it was actually pushing water back up into Little Beaver Creek, so that prevented any from getting into the Little Missouri,” Suess said. The Little Missouri is a tributary of the Missouri River. 

Greenpeace gatecrashes Credit Suisse shareholder meeting | Reuters: Activists from environment group Greenpeace gatecrashed Credit Suisse's annual shareholder meeting on Friday to protest against the Swiss bank's dealings with companies behind the Dakota Access Pipeline (DAPL). Greenpeace unfurled a banner criticizing the crude oil pipeline from the stadium ceiling during the speech of Chief Executive Tidjane Thiam, with two people on wires holding the banner. "I am a democrat and a great believer in freedom of expression," Thiam said. "I will continue my speech. Everyone has a right to express their views." The banner was lifted back up around 15 minutes later. Credit Suisse, Switzerland's second-biggest bank, said in April it was not involved in project financing for the DAPL. "Allegations that Credit Suisse is the biggest lender to DAPL are false and are firmly rejected by the bank," it said. "Credit Suisse has business relationships with companies undertaking the construction and operation of the pipeline." The 1,172-mile (1,885-km) Dakota Access line running from North Dakota to Illinois drew international attention in 2016 after the Standing Rock Native American tribe sued to block completion of the final link, saying it would desecrate a sacred burial ground. Environmentalists also argued that potential leaks along its length would risk poisoning the water supply for some 17 million Americans.

Feds Say It's Too Dangerous To Share Dakota Access Oil Spill Report | The Huffington Post: A federal agency won’t release a study about the potential effects of a Dakota Access Pipeline oil spill because it claims information in the report could put lives at risk. The U.S. Army Corps of Engineers made the claim while rejecting a Freedom of Information Act request from MuckRock, a journalism website that collects and publishes government documents. MuckRock’s co-founder Michael Morisy had requested in March a copy of an Army Corps environmental assessment that looked at the possible impact of a pipeline leak on Lake Oahe in North Dakota.“The referenced document contains information related to sensitive infrastructure that if misused could endanger people’s lives and property,” said Army Corps lawyer Damon Roberts in a denial letter that MuckRock published Tuesday.Rather than editing out sensitive details, Roberts withheld all materials related to the request. “I understand exempting some details, but knowing the impact of a natural disaster should be public,” Morisy told HuffPost. “I was very disappointed.” MuckRock plans to appeal the Army Corps’ decision, Morisy said. The assessment’s existence was mentioned in an internal Army Corps memo about the controversial 1,172-mile pipeline, which will carry North Dakota crude oil through South Dakota and Iowa to Illinois.The memo mentioned that several documents were withheld from the public and from representatives of a Native American tribe that has objected to the project “because of security concerns and sensitivities.”

Here is the real toxic future we face if we allow fracking to continue - The environmental effects of shale gas are varied—wide ranges of importance and risk level. First, many say that the burning of natural gas emits fewer greenhouse gases per unit of energy than burning alternative energy sources like oil or coal; however this may not necessarily be true when observing the full life cycle of natural gas, especially taking extraction into account. Second, another key environmental impact is the amount of water needed to access shale gas through hydraulic fracking. Estimates vary, but one study from Duke University found that 250 billion gallons of water was used to extract unconventional shale gas and oil from hydraulically fractured wells in the United States from 2005 to 2014. During the same period, the fracked wells generated about 210 billion gallons of wastewater. Injecting such vast amounts of water into the earth can also cause minor earthquakes, but greater magnitude ones could occur if there is a pre-stressed fault in the same location. Another environmental impact is the risk of “slickwater” (a blend of water and added chemicals to improve viscosity) containing harmful chemicals and contaminating water under the ground or migrating upwards through aquifers. This contamination at the development and production stages is extremely dangerous—deep groundwater has a much higher salinity than shallow groundwater, which is fresh, and the two do not mix naturally. In the process of drilling one must be aware of the various aquifers present so the fresh groundwater does not become contaminated by the deeper saline water. The construction of wells in the development stage is the most common method for groundwater and ecosystem contamination when poorly built. A poorly constructed dam gives large potential for fluids to contaminate groundwater and the surrounding environment through fractures in the rock. These are just a few of many plausible negative environmental consequences of extracting shale gas, but some of the most significant environmental impacts even arise from the construction of wells, including accidental spills of oils, drilling muds, and potentially toxic “slickwater.” Besides strictly environmental impacts, there are social ones too. The need for large volumes of water over short time periods for hydraulic fracking can cause stress at the coldest, driest, and most critical times of the year for communities surrounding fracking sites. There also can be spills associated with storing, mixing and pumping slickwater, meaning there is a chance chemicals involved in slickwater could infiltrate groundwater and the soil, causing potential health issues. Drilling rigs running all day and night create noise heard up to 4km away, and volatile organic compounds which contribute to smog can leave odors up to 600m from a fracking platform.

Top Trump adviser calls for reviving controversial natural gas project on Oregon’s coast -  A top adviser to President Trump on Thursday appeared to throw the administration’s support behind a controversial proposed liquefied natural gas terminal in Oregon that had been rejected by regulators during the Obama administration.“The first thing we’re going to do is we’re going to permit an LNG export facility in the Northwest,” said Gary Cohn, director of the National Economic Council. “Just think of the transport time from the Northwest to Japan versus anywhere else. Then we’ve got to put facilities on the East Coast to get from the East Coast to Germany.” “The one place we’re going to permit in the Northwest, it’s been turned down twice already,” Cohn said in comments at the Institute of International Finance, in which he called the opportunity for exporting liquefied natural gas “enormous.” Although Cohn did not name a specific project, the White House confirmed Thursday that Cohn was referring to the proposed Jordan Cove LNG export terminal, which would be located in Oregon’s Port of Coos Bay. That’s where Veresen, the Calgary-based company whose subsidiary is proposing the project, wants to construct two 160,000-cubic-meter storage tanks and other facilities that would receive natural gas from a pipeline, compress it into a liquid for transport, and then pipe it out to tanker ships for sale abroad. It isn’t clear what Cohn meant by saying that “we’re going to permit” the project, because final approval rests with the Federal Energy Regulatory Commission (FERC), an independent agency. FERC turned down Jordan Cove, as well as the proposed 232-mile Pacific Connector Gas Pipeline that would link to it, in a unanimous decision in March 2016. The agency found that the project would be “inconsistent with the public interest,” chiefly because the pipeline would have significant “adverse effects on landowners,” many of whom did not approve it and could have their properties disturbed or otherwise affected through eminent domain if it were to be built. Because the export terminal would not serve a purpose without the pipeline to connect to it, it was rejected as well.

Oregon lawmakers consider banning "fracking" by oil and gas drillers - OregonLive.com: The Oregon House passed a bill Tuesday that would place a 10-year ban on fracking, or hydraulic fracturing, by those drilling for oil or natural gas in the state. The bill is symbolic at this point, as no one is actually using the controversial technique in Oregon. But it has been employed in the past and could be again if developers look to exploit coal bed methane reserves that are potentially spread through Western Oregon, including much of the Willamette Valley. Hydraulic fracturing involves injecting millions of gallons of fluid into wells under pressure to fracture rock formations and prop open the fissures, which allows gas and oil to flow more freely. The fluid is typically a mixture of water, sand and other chemicals, and the technique is used in shale and coal bed methane formations to make them more permeable - and ultimately more profitable places to drill. Along with horizontal drilling techniques, fracking is responsible for the natural gas and oil drilling boom that has upended the U.S. energy market. But it is a highly controversial practice that opponents link to groundwater contamination, massive water consumption and the triggering of earthquakes in states where it has been used extensively. Rep. Ken Helm, D-Beaverton, called House Bill 2711 a precautionary measure. He introduced legislation in 2015 that would have directed the Oregon Department of Geology and Mineral Industries to develop tighter rules around hydraulic fracturing. But the bill never passed, and the rulemaking was estimated to cost $750,000. Since the Legislature is doing everything on the cheap this session, he said he reintroduced the bill with the 10-year moratorium and no rulemaking.

U.S. oil poised as next swing producer – INTERVIEW - Oil prices have taken a wild ride in recent years, and nobody knows exactly where they will settle.Some market analysts, though, have a better idea than others.Brent Berarducci of Blacklion Capital Management, namely, is one unique to the oil and gas financial market.His boots have been on the ground (as well as 30,000+ feet in the air) and now his hands are handling cash.As the principal and manager for Texas-based Blacklion, he works to close the disparity between those in the oil field and those in finance. While discussing topics ranging from depressed rig counts, sustained anemic demand, OPEC, and President Trump, Berarducci offered up some unconventional insights into what’s really going on in oil and gas markets today. Key takeaways from the conversation include:

• America is poised to become the world’s swing producer
• OPEC is really good at marketing
• President Trump won’t make things worse
• Rig count data isn’t a reliable indicator of market health anymore
• Demand remains weak as global economies recover from the 2008 financial crisis
• Why high storage levels aren’t impacting prices more is kind of a mystery

Drilling costs rise as U.S. oil, gas activity picks up: Kemp (Reuters) - U.S. oil and gas drilling costs have started to rise in response to a surge in activity and are set to increase further as the slack in the rig market declines.Drilling costs increased by 7 percent between November 2016 and March 2017, according to preliminary data on producer prices from the U.S. Bureau of Labor Statistics.The increase has offset only a small part of the 34 percent slump between March 2014 and November 2016 (http://tmsnrt.rs/2q6RNzc).But it is the first sustained gain in three years for drilling prices, which are now rising year-on-year for the first time since November 2014.Drilling prices are classified under the North American Industry Classification System (NAICS) code 213111 for “establishments primarily engaged in drilling oil and gas wells for others on a contract or fee basis”.Drilling prices do not include the cost of hydraulic fracturing, which is classified separately under NAICS code 213112, and where the previous decline in prices and subsequent recovery have been more muted.Drilling costs have a strong cyclical component and track changes in drilling activity with an average lag of two to three months (http://tmsnrt.rs/2oL30Sg).The number of rigs drilling for oil and gas hit a cyclical low at the end of May 2016 but has more than doubled since then (http://tmsnrt.rs/2oLo37c).The rebound is the fastest for at least a quarter of a century, according to rig counts published by oilfield services company Baker Hughes.The number of active rigs has risen from a low of 404 at the end of May 2016 to 857 on April 21 and is still gaining by an average of 10-20 per week (http://tmsnrt.rs/2p3GEOl).Drilling prices will likely keep rising in the next few months as the lagged effect of past increases in the rig count filters through and rigs continue to be added.Cost inflation for drilling as well as other inputs into the exploration and production process will likely put upward pressure on breakeven prices for U.S. shale firms.Many shale producers report breakeven costs significantly below $50 per barrel but those costs are likely to rise as service companies push through price increases. Service companies have repeatedly warned that the severe cost compression that occurred between 2014 and 2016 was unsustainable, and drilling costs would need to rise during any sustained recovery.

Oil service costs could rise 15 percent this year, Wood Mac says - As crude prices stabilize and drilling rigs dig into shale plays again, oil field service costs are beginning to rise back up. That could squeeze drillers’ margins later this year. Energy research firm Wood Mackenzie believes oil field service costs could jump 15 percent this year overall, with prices for some equipment and services possibly rising as high as 40 percent, it said in a recent report. Though oil field service companies aren’t likely to charge the same prices they got in 2014, before oil prices collapsed, they will probably get back market pricing power, Wood Mackenzie said. Oil explorers all “voice the best intentions to keep a laser eye on costs,” said Jackson Sandeen, senior research analyst at Wood Mackenzie. “But continued productivity and drilling efficiency gains over 2016 will be difficult to achieve as operators pivot to a more aggressive development mode.” The firm estimates U.S. oil companies will hike spending 60 percent this year on average, but drillers expect service prices to rise on average 10 percent to 20 percent, even though service companies forecast 15 percent to 40 percent price increases this year. Oil fields in which companies can pump crude profitably below $40 a barrel will still turn a profit even with service cost inflation. But the more active oil plays in West Texas will likely see the biggest increases in oil field service prices, Wood Mackenzie said.

Alberta Warns Trump Of Retaliation If Energy Sanctions Begin - Alberta Premier Rachel Notley warned U.S. President Donald Trump that he would face thewrath of the northern nation’s many allies if the freshman president begins employing energy trade restrictions with Canada.Notley is currently in China, negotiating her country’s trade policies with the Asian giant. She told reporters that she did not know what was meant by Trump’s comments about what Canada has done to its American neighbor with the energy, softwood lumber, and dairy industries."Canada, what they've done to our dairy farm workers, is a disgrace. It's a disgrace,” Trump said before signing a memorandum about investigation the national security implications of importing foreign steel.Trump also criticized NAFTA in general, calling it a “disaster”, adding that that “included in there is lumber, timber, and energy. We’re going to have to get to the negotiating table with Canada very, very quickly”"We're not exactly sure what it is he was referring to,'' Notley said in a conference call Monday, according to The Huffington Post."The leadership of the U.S. administration is going to find that they have a lot of their own stakeholders reminding them how much they need Canadian energy,'' she said.Figures from 2016 show that 41 percent of all American crude imports, or 3.3 million barrels per day, came from Canada.

Pipeline Leaks Crude Oil Into Canadian Creek, Any of Four Energy Companies Could Be Responsible -- A busted pipeline spilled crude oil into a Strathcona County creek in Alberta, Canada on Saturday. The amount spilled is currently unclear. The unnamed creek, near 17th Street and Baseline Road, flows directly into the North Saskatchewan River but Alberta Energy Regulator spokesperson Monica Hermary told CBC News that crews managed to contain the leak before it reached the river. Four Canadian energy companies including Imperial Oil— Exxon Mobil Corp.'s Canadian unit—could be responsible for the spill, Hermary said. The companies—Imperial Oil, Gibson Energy, Inter Pipeline and Pembina Pipeline—have since shut in and de-pressurized their pipelines after the spill was reported and are helping with cleanup. A team of Imperial Oil workers discovered the leak during routine maintenance. A company spokesperson said the crude oil did not match Imperial Oil products when tested but is leading the response to the incident. "The current process, in addition to obviously recovering the oil, is determining where the source of the crude is," the spokesperson said. "In other words, who the responsible party is. Then we would transition the recovery efforts to that company."  CBC reported that the spill occurred along a pipeline right-of-way near the boundary between Strathcona County and Sherwood Park, a strip of industrial land where a number of pipelines operate.

Pollution From Canada’s Oil Sands May Be Underreported | Climate Central: Canadian scientists have found that the standard way of tallying air and climate pollution from Alberta’s oil sands vastly understates pollution levels there — by as much as 4.5 times, according to a Canadian government study published Monday. The study shows that air samples collected using aircraft may be a more accurate way to tally air and climate pollution from oil and gas production than using industry estimates. Accurate accounting of the oil and gas industry’s pollution is critical for scientists to understand how fossil fuel production affects the climate and to find ways to cut the pollution to address air quality and climate change, said Allen Robinson, director of the EPA-funded Center for Air, Climate and Energy Solutions at Carnegie Mellon University, who is unaffiliated with the study. Both the U.S. and Canadian governments rely on energy companies’ self-reported emissions estimates in order to count all the pollution from oil and gas operations. Few actual pollution measurements are taken. If official tallies underestimate the actual emissions, climate models will likewise underestimate the extent to which fossil fuel pollution is contributing to climate change, Robinson said. The Canadian research shows that the energy industry has been underreporting its emissions and it highlights the challenges the industry faces in accurately estimating emissions from very complex equipment.

Oil and Gas Giants Flee Canada’s Tar Sands - A growing number of American oil and gas giants are divesting themselves of their Canadian tar sands holdings.  In the latest move, Chevron is reportedly looking to sell its 20 percent stake in the Athabasca Oil Sands project, located in Alberta. The company has been in talks with investment banks about the sale, which could net Chevron $2.5 billion,a source told Reuters. Chevron is the second biggest oil producer in the U.S. The month of March saw three companies — two of them American — divest some of their tar sands assets.  ConocoPhillips signed a deal worth $13.3 billion in March to divest a good part of its Canadian assets. The Houston-based oil and gas giant agreed to sell its interests in Foster Creek Christina Lake oil sands partnership in northeast Alberta and the majority of its gas assets in the Western Canada deep basin in Alberta to Cenovus, a Canadian company. The company will retain its interests in two other Alberta tar sands projects.  Divesting itself of part of its tar sands assets “improves our underlying financial and portfolio metrics, which will drive free cash flow generation and returns,” Ryan Lance, ConocoPhillips chairman and CEO, said of the deal during a press conference. Marathon Oil is another American oil and gas giant to sell its interests in Canada’s tar sands. In early March, the company signed an agreement to sell its Canadian subsidiary, which includes its 20 percent interest in the Athabasca Oil Sands project, for $2.5 billion. At the same time, the company announced an agreement to acquire about 70,000 net surface acres in the Permian basin, located in Texas and New Mexico, for $1.1 billion. Divesting of its tar sands assets while acquiring holdings in the Permian basin “are transformative milestones that will further align our portfolio with our strategy,” said Marathon Oil President and CEO Lee Tillman. Shell also sold some of its tar sands assets in March, including reducing its interests in AOSP from 60 percent to 10 percent. The British–Dutch multinational sold part of its interests in the Athabasca project to a subsidiary of Canadian Natural Resources Ltd. for $8.5 billion.

Mexico's Pemex will look to repeat new hedging program | Reuters: Mexican state-owned oil company Pemex will consider repeating a recently instituted hedging program in future years, as it looks to firm up its balance sheet and avoid the need for surprise budget cuts, a top executive said late on Tuesday. Petroleos Mexicanos [PEMX.UL], as the company is officially known, reported on Tuesday that it has hedged its output through December, the first time it has done so in 11 years, as an insurance policy against volatile oil prices. The oil hedging program, which will run from May to December and guarantees a price of $42 per barrel for up to 409,000 barrels per day, will cost the company $133.5 million. "It's important to give the market certainty that faced with drops in oil prices Petroleos Mexicanos won't have to cut its budget," Chief Financial Officer Juan Pablo Newman told Reuters in an interview. Last year, Pemex implemented about 100 billion pesos ($5.8 billion) in spending cuts, following cuts of some 62 billion pesos in 2015 due to falling crude prices. The new Pemex hedge is separate from a much larger oil price hedge undertaken by the finance ministry. Asked if Pemex would look to implement another hedging program after the current one expires in December, Newman said that company had found a mechanism that "could be adjusted to market conditions to continue with this effort." Long used as a cash cow by Mexico's government, Pemex now contributes less than a fifth of federal revenue, down from more than a third a few years ago.

Oil, natural gas industry beyond North America picking up steam: Schlumberger CEO -  The long-awaited bottoming of the two-plus-year oil and natural gas industry downturn has finally reached beyond North America, with gradual recovery this year before accelerating into 2018, the CEO of oil services giant Schlumberger said Friday. While North American investment will be up as much as 50% this year, most of the world's production comes from other arenas. And, "we're heading toward a third year of significant underinvestment," Paal Kibsgaard said during a quarterly earnings conference call. Lack of funding on such a wide scale "increases the likelihood of a medium-term supply deficit, as produced reserves are not replaced in sufficient volumes," Kibsgaard said. During the first quarter, Schlumberger began to reactivate idle equipment in the North American onshore, which started its own recovery late in 2016 as a steadily increasing rig count increased demand for services and equipment in unconventional plays. The equipment re-activations will accelerate for the rest of the year, with all idle capacity back in the field during the fourth quarter, Kibsgaard said. North American land is also the one area likely to increase E&P investments this year, although investment levels in Middle East and Russia are also expected to remain "resilient" this year, he said. But a close look at recent data clearly shows the depletion rate of proved and developed reserves is "rapidly accelerating" in several key non-OPEC countries, Kibsgaard said.

Cuadrilla To Begin Shale Drilling In “Couple Of Months” -- British unconventional exploration company Cuadrilla plans to start the drilling stage of its shale gas exploratory plans in northwest England within the next “couple of months,” company CEO Francis Egan said this week. Egan welcomed the UK’s High Court decision dismissing two claims made against Secretary of State for Communities and Local Government Sajid Javid’s approval of planning for Cuadrillla’s Preston New Road site. Last year, the company had its planning application denied by the local Lancashire councillors, but that was overruled by Javid, following a recommendation to approve from the council’s planning officers. The CEO, who a number of times expressed frustration with the lengthy permit application process, is “very pleased” with the outcome. “Work continues on the construction of the exploration site and we look forward to move to the drilling stage of our operations within the next couple of months,” he added.

Canary Islands battles two-mile oil slick after ferry crash | Reuters: Emergency teams in the Canary Islands raced on Saturday to contain a three-kilometer oil slick caused by a ferry crashing into underwater fuel pipes, the regional government said in a statement. The regional government activated emergency plans to control and clean up the nearly two-mile spill around Las Palmas de Gran Canaria and Telde, the two main towns on the Spanish resort island of Gran Canaria, the regional government said. No one at the emergency services or government could be reached for further comment on Saturday. The ferry crashed into a pier where the pipes were located late on Friday after suffering a technical fault that caused a power cut, a spokesman for operating company Naviera Armas on Saturday.

Exxon asked for a waiver to resume drilling in Russia. Trump said no -- The Trump administration rejected Exxon Mobil’s request to resume an oil drilling project in Russia that is currently blocked by US sanctions, a tangible reminder that American policy toward Moscow has yet to change as much as some observers in both countries had expected.   Shooting down Exxon’s request allows the White House to dodge a pair of political hand grenades: the raging controversy over Trump’s ties to Russia, which are currently being investigated by Congress and the FBI, and the lingering question of whether an administration whose top diplomat is former Exxon CEO Rex Tillerson will be able to impartially decide matters related to the oil giant.  In a statement Friday, Treasury Secretary Steven Mnuchin said the department “will not be issuing waivers to U.S. companies, including Exxon, authorizing drilling prohibited by current Russian sanctions.”  Exxon originally put in a request for the waiver, which would’ve allowed it to resume a joint venture with Russian oil giant Rosneft in the summer of 2015, but it was rejected at that time. According to the Wall Street Journal, Exxon began to pursue the application again in March, about a month after Tillerson was narrowly confirmed as secretary of state. The State Department was one of multiple agencies that had a say in the waiver, but Tillerson wasn’t involved in this decision — he’s recused himself from any issues that involve Exxon for two years, and he no longer has stock in the company. The former Exxon chief executive developed a close relationship with Rosneft and the Kremlin during deals that he struck with Rosneft between 2011 and 2013.The Trump administration’s rejection of the waiver — which would have provided a financial boost to Moscow, given how much the Russian economy has been hammered by Western sanctions — comes amid new and growing tensions with the Kremlin.

Chevron loses landmark tax case on transfer pricing - Multinational companies operating in Australia have been put on notice after Chevron on Friday lost a landmark tax case that is expected to have implications for the loans that overseas groups use to fund their activities in the country. The Federal Court of Australia dismissed an appeal by Chevron against an earlier ruling that found mostly in favour of the Australian Taxation Office’s claim that the US energy group owed A$340m ($256m) in tax, penalties and interest after using an inter-company loan to finance a large gas project off the coast of Western Australia. The Chevron litigation underlines an intensifying crackdown on corporate tax avoidance, which has left companies across the world reporting a significant increase in disputes over so-called transfer pricing — internal transactions within groups that are meant to be done on an arm’s length basis. The Chevron case — a rare example of a transfer pricing dispute reaching the courts — highlighted the prominent role played by inter-company loans in reducing corporate tax bills. Multinationals have clashed with revenue authorities for decades over the pricing of such loans — which determine how far profits can be shifted to low-tax countries — but in recent years the number of challenges to these arrangements have increased. The crackdown on corporate avoidance has been particularly marked in countries that have faced a public backlash over claims that multinationals are not paying their “fair share” of tax. There has been particular concern in Australia about energy groups. The Australian Tax Office, which said it was “heartened” by the outcome of the Chevron case, added that the federal court’s decision “has direct implications for a number of cases” it is “currently pursuing in relation to related-party loans, as well as indirect implications for other transfer pricing cases”. 

Australian Government ‘Encouraged’ By Steps To Avert Gas Crisis -- The Australian government said it was “encouraged” on steps taken to avert a gas crisis after meeting on April 19 with producers and the energy market operator, but it held out the threat of regulatory steps to address any supply shortages. Australia’s energy market operator and east coast liquefied natural (LNG) gas exporters updated Prime Minister Malcolm Turnbull on measures taken since a March meeting to discuss a domestic gas crunch expected to emerge from 2019. Since then, companies like France’s Engie SA and Origin Energy, have sealed deals to ensure gas supply to power plants at peak times, easing some short-term concerns about shortages that have already helped to trigger blackouts.”While this progress is encouraging, a lot more needs to be done,” Prime Minister Turnbull said in a statement following talks. “The government remains concerned that the east coast export LNG operators have not yet clearly articulated how Australian households and businesses will get adequate supply at reasonable prices,” he said.

Australia to put export controls on LNG to protect domestic supply - Natural Gas | Platts News Article & Story: The Australian government is planning to block LNG exports if there isn't adequate supply of gas domestically, Prime Minister Malcolm Turnbull announced on ABC Radio Thursday morning local time. Exactly how the mechanism will work is not clear yet, but comes in response to concerns that the eastern seaboard of the country could face gas shortages by the end of the decade. It follows meetings between the Federal Government and top executives from the country's gas companies in recent weeks, during which two of the three east coast LNG exporters -- Australian Pacific LNG and Queensland Curtis LNG -- committed to being net suppliers to the domestic market. Santos, the operator of the third east coast LNG exporter, Gladstone LNG, on Thursday said, that moving forward, it will supply more gas into the domestic market than it purchases for its share of LNG exports. "Santos will seek clarification of how the new policy will work in practice in order to understand from the government the terms on which it is proposing to introduce this mechanism and how proposals that have been put to the government to address the domestic market situation are being considered," it said in a statement in response to the announcement.

Australia's LNG export control plans raise alarms in Queensland - The Australian government's decision to enforce export controls on LNG to protect domestic supply has raised concerns among Queensland LNG exporters, which have international contractual commitments for more than 25 million mt, mainly with northeast Asian buyers. Exactly how the mechanism will work is not clear yet, but the government is planning to block LNG exports if there is not adequate supply of gas domestically, Prime Minister Malcolm Turnbull announced on ABC Radio Thursday morning local time. The move comes in response to concerns that the eastern seaboard of the country could face gas shortages by the end of the decade, but the risk of a lengthy supply deficit in the region is still low. "Out to around 2021, we do not think a gas shortage is likely," said Matt Howell, senior research analyst, Australasia upstream oil and gas, with Wood Mackenzie."Supply from the CSG-LNG projects and other existing producers should be available to fill any demand/supply shortfall. However, that is not to say that there might not be short-term shortages in periods of high demand or if there are supply disruptions." The risk of gas shortages increases post-2021, Howell said, and alternative sources of supply will need to be developed to prevent a shortage from occurring as existing supply drops off. 

LNG stocks held by key Japanese power utilities hit 4-year low at end Jan -- LNG stocks held by 10 major Japanese power utilities fell to 1.61 million mt at the end of January, the lowest level since January 2013, as the key utilities consumed the largest volume of LNG since March 2011, data released by the Ministry of Economy, Trade and Industry this week showed. Their combined stock levels have remained below 2 million mt since June 2016, according to the METI data. The average stock level over fiscal 2015-16 (April-March) was 2.22 million mt. In January, the key power utilities consumed 5.49 million mt of LNG as cold weather pushed up demand for heating. It was the largest monthly consumption recorded since March 2011. Japan LNG import data released by the Ministry of Finance in February showed that Qatar and Australian imports grew more than 20% year on year in January. Japan also received three cargoes from the US in January. In addition to power utilities, Japanese gas utilities also burned more LNG this winter. Tokyo Gas and Osaka Gas both said they chalked up record daily gas supply volumes near the end of January. Separate METI data released earlier in April showed Japan’s gas utilities held 1.83 million mt of LNG in stock at the end of January.

Argentina's Push to Mimic Permian Success Faces Long Road - Argentina’s Vaca Muerta, one of the largest shale formations outside of North America, offers tons of promise for the country’s energy future. Just don’t hold your breath waiting for it. Energy Minister Juan Jose Aranguren, billionaire investor Paolo Rocca and bullish Morgan Stanley economists all predict lightning fast growth in the region, comparing it to the Eagle Ford and Permian basins in the U.S., oil and natural gas-saturated plays that have spurred billions in revenue. The reason: Vaca Muerta offers Argentina, which has struggled for years with rampant inflation, an economic lifeline for the future. Still, before the field reaches its potential, gas and oil pipelines need to be built, roads, train lines and power networks need upgrading, and drilling costs that run 30 percent or more higher than in the U.S. need to drop, industry insiders say. “It’s all about building momentum, and that will take years,” “If the costs come to where we want them, this will happen.” Argentine President Mauricio Macri will meet with oil and gas executives in Houston on Wednesday as he seeks to drum up investment in Vaca Muerta. So far, the shale play is luring about $4 billion a year, when about $15 billion of annual spending is needed, Emilio Jose Apud, a board member at state-run YPF SA, told Telam news agency on Monday. The average drilling and completion cost of a horizontal well in Vaca Muerta was $11.2 million as of 2015, compared with $6.5 million to $7.8 million in the Eagle Ford, the U.S. Energy Information Administration said in a report in February. YPF said it’s now spending about $8.2 million to drill a horizontal well in the region, and Shell pegs it at little under $10 million.

Nigeria aims to reduce fuel imports further, eyes LPG: oil minister - The Nigerian government is working on a long-term plan to replace the use of refined oil products with LPG in a bid to further reduced fuel imports, which have become a drain on the country's dwindling foreign exchange earnings, Oil Minister Emmanuel Kachikwu said Friday. Speaking in a webcast, Kachikwu said that while the government has been able to stabilize fuel supplies after it cut the subsidy on imported gasoline in May 2016 that allowed marketers to sell on the domestic market at a capped price of Naira 145/liter, the country's downstream oil sector still faced numerous challenges. "We need to move away from white products to LPG...which is the byproduct of the gas that we have an abundance of," said Kachikwu. "So we need to begin to look long term and how we build pipelines for LPG, so we can take LPG to the closest points for cars to reduce [gasoline] consumption."Nigeria has the world's ninth largest proven gas reserves, at 187 Tcf, but a lack of key infrastructure means the bulk of the 8.0 Bscf/d of gas currently produced -- estimated at 3.5 Bscf/d -- is exported while the remainder is either utilized in oil fields or flared. Nigeria sets aside 450,000 b/d of its share of the crude produced jointly with foreign oil partners, but government officials and the country's oil industry auditors NEITI have previously called for the scrapping of the allocation and the government to export the volume to raise revenue. The four state-owned oil refineries, with a combined nameplate capacity of 445,000 b/d, have never been able to run consistently to provide the country with enough products. 

Chevron to sell Bangladesh gas fields to Chinese consortium | Reuters: Chevron Corp is selling its three Bangladesh gas fields, worth an estimated $2 billion, to a Chinese consortium as the U.S. oil and gas group looks to shed non-core assets this year. The deal, if completed, would mark China's first major energy investment in the South Asian country, where Beijing is pumping in billions of dollars in a race with New Delhi and Tokyo for influence. The gas fields, which account for more than half of the total gas output in Bangladesh, are being sold to Himalaya Energy, Chevron said. Himalaya is owned by a consortium comprising state-owned China ZhenHua Oil and investment firm CNIC Corp. CNIC, set up in Hong Kong in 2012, is a government investment platform that focuses on supporting Chinese companies' overseas investment. Reuters reported in February that ZhenHua Oil had signed a preliminary deal with Chevron to buy the Bangladesh natural gas fields. "The agreement is for the sale of Chevron's Bangladesh companies, which hold our interests in Bangladesh," a company spokesman told Reuters by email on Monday. "The value of the transaction is not being disclosed and we are not at liberty to share the details of the agreement." A ZhenHua spokesperson confirmed the agreement, adding that the closing of the deal would depend on approval from China’s Ministry of Commerce. Chevron sells its entire output from the Bangladesh fields -- 16 million tonnes a year of oil equivalent -- to state oil company Petrobangla under a production-sharing contract.

Russia cuts 250,000 b/d, to comply with oil output deal by end-Apr -  Russia has lowered its oil output by 250,000 b/d from its October level and will reach its full commitment of a 300,000 b/d cut by the end of the month, Energy minister Alexander Novak said Friday. "We're fulfilling the obligation to gradually cut the output by Russia," Novak told reporters during a visit to Tokyo. "Today, we see a 250,000 b/d cut, and in line with the plans which we announced earlier, the level of 300,000 b/d will be reached by the end of April and we'll keep that level until the end of the agreement.""There are no decisions yet and each country is currently studying this issue independently," Novak said. "The possibility to extend the agreement was envisaged by the December agreement but the final decision is to be later." The OPEC secretariat is currently studying the impact of the cuts and how an extension might affect the oil market in the second half of the year. It will unveil its findings May 24 to a monitoring committee overseeing the deal composed of OPEC members Kuwait, Algeria and Venezuela, along with non-OPEC Russia and Oman. He added that no decision had yet been made on extending the OPEC/non-OPEC deal, under which OPEC agreed to cut 1.2 million b/d and 11 non-OPEC countries led by Russia committed to a 558,000 b/d cut from January through June. Ministers from deal participants will meet in Vienna May 25 to review the agreement. Novak said Russia was "in daily contact" with OPEC countries.

Russia's Oil Cuts Won't Be So Easy If OPEC Deal Is Extended -- For Russian oil companies, the historic agreement to boost prices by cutting output in conjunction with the Organization of Petroleum Exporting Countries was an easy win. Extending the deal will be less straightforward. Cuts so far this year came alongside the traditional seasonal stagnation in Russian production, meaning the country made relatively few sacrifices in exchange for an increase in crude prices of more than 10 percent. For the powerful Russian oil bosses who plan to discuss the OPEC accord with Energy Minister Alexander Novak this week, a decision by the government to extend the cuts beyond June would stymie plans to boost output, creating many more headaches than the initial agreement.“It was not a surprise and not a big deal to have production going down in the first half of the year,” James Henderson, a Russian oil expert at the Oxford Institute of Energy Studies, said by phone. “When you go into the second half it’s a different story. All thoughts of production growth this year go out of the window.”After two years of low oil prices and competition for market share, OPEC and Russia made a surprise agreement late last year on the first coordinated production cuts in more than a decade. While the deal lifted international crude futures above $58 a barrel in January -- double the level a year earlier -- stubbornly high inventories and rising U.S. production have dragged prices back toward $50. That’s prompted producers to consider extending the curbs beyond their initial six-month term.Novak will hold talks with Russian oil companies this week before his meeting with OPEC and non-OPEC counterparts in Vienna on May 25. The minister said on April 21 that the issue of whether to prolong the deal was “ under discussion” within Russia and would depend on “the market situation by the time when the current half-year agreement expires.”Analysts predict Russia will double down and prolong the cuts, despite the problems it could cause for its largest  producers.

Will Russia Join The OPEC Cut Extension? - WTI and Brent stabilized on Tuesday after a week of steep losses. Market sentiment has shifted notably in a bearish direction over the past six trading days. The realization that the OPEC deal, nearing the end of its fourth month, is falling short on balancing the market is weighing on crude prices. Stephen Schork of the Schork report put it more bluntly on Tuesday: “OPEC has failed miserably in its endeavour to balance the oil market.” The flip side is that because the market still seems woefully oversupplied, extending the OPEC cuts seems like more of a sure bet. OPEC’s monitoring committee formally recommended an extension, although no final decision has been made.   Russia still needs to come on board with the OPEC extension, and at this point, Russia is likely the most pivotal participant in determining whether or not the cuts are extended for another six months. But Russian officials said they wouldn’t commit until the official meeting at the end of May. The problem for Russia is that the initial agreement corresponded with winter months in Russia, when output typically falls. That made agreeing to the cuts easy. But the six-month extension will overlap with the Russian summer, which usually sees an uptick in production. Moreover, Russian oil companies have a handful of fields that they intend to bring online in the second half of the year. In other words, the extension will be much harder to agree to than the initial agreement.. OPEC’s lower production has led to a smaller premium for Brent oil over Middle Eastern grades. Heavy crude from the Middle East, now in lower supplies, has become scarcer, allowing oil from the North Sea to find its way to Asia. “Crude is trading like a game of musical chairs,” Richard Fullarton, founder of London-based commodity hedge fund, Matilda Capital Management, told Bloomberg. “If OPEC extends cuts then more Brent and WTI will head to the east.” Meanwhile, Russia is also grabbing Asian market share from Saudi Arabia, reclaiming the number one spot for supplier to China.  Oil could hit low-$60s, but not $70. One of the world’s largest oil traders, Vitol, said that it foresees oil moving up into the low-$60s per barrel this year, but not any higher.

OPEC panel recommends six-month extension of oil output cuts: source | Reuters: An OPEC and non-OPEC technical committee recommended that producers extend a global deal to cut oil supplies for another six months from June, a source familiar with the matter said, in an effort to clear a glut of crude that has weighed on prices. The Organization of the Petroleum Exporting Countries (OPEC), Russia and other producers originally agreed to cut production by 1.8 million barrels per day (bpd) for six months from Jan. 1 to support the market. Compliance numbers were also reviewed at the meeting in Vienna on Friday that comprised of officials from countries monitoring adherence to agreed output levels, namely OPEC members Kuwait, Venezuela, Algeria and non-OPEC Russia and Oman. Overall compliance with pledged cutbacks stood at 98 percent in March, a source said. Two sources said the rate in March represented an increase from February's level. Oil prices still declined on Friday, with Brent crude trading below $52 a barrel LCOc1 on concerns that increasing U.S. production and high inventories would thwart the efforts by OPEC and its allies to curb supplies. The committee's recommendation that the supply cut deal be extended was not a surprise, after oil ministers from top exporter Saudi Arabia and Kuwait gave a clear signal on Thursday that producers planned to prolong the accord. Russian Energy Minister Alexander Novak said on Friday a decision on extending the pact had not yet been taken, but would be discussed with OPEC on May 24. OPEC ministers plus their non-OPEC counterparts are scheduled to meet on May 25.

OPEC heads for failure as crude shipments overwhelm cut rhetoric --  Reuters: Is it yet time to call the crude oil output cuts by OPEC and its allies a failure? Certainly there is an increasing disconnect between the rhetoric of OPEC and other producers cutting output on the one hand and the reality of a well-supplied crude oil market and mixed signals on the level of global inventories on the other. The Organization of the Petroleum Exporting Countries and other producers, including Russia, have been touting the high compliance with the agreement to reduce output by 1.8 million barrels per day (bpd) from January to June. It now appears that OPEC and its allies are moving to prolong the deal for another six months, with consensus building for an extension, which is likely to be announced at a meeting scheduled for May 25. If the success of the deal is to be judged purely by prices, then an argument could be made that it has at least led to crude finding a floor above $50 a barrel. Global benchmark Brent crude spent the second half of last year mainly between $40 and $50 a barrel, before being lifted after the OPEC and allies agreement was announced at the end of November.. But Brent is once again testing the bottom of the post-agreement range, dropping to as low as $51.42 a barrel on Monday, as scepticism mounts over the ultimate effectiveness of the OPEC measures. Perhaps more important for determining the longer-term price outlook is to look at the amount of oil available and the levels of inventories.  It's here that the main evidence of the failure of the OPEC agreement is to be found. Global oil shipments by tanker are at a record high in April, according to vessel-tracking data compiled by Thomson Reuters Supply Chain and Commodity forecasts. As of Tuesday, the data shows that an average 50.3 million barrels per day (bpd) of crude is being shipped in April, up from the previous record 46.1 million bpd in January. The data excludes crude moved by pipelines, but it's extremely unlikely that pipeline supplies have been cut by more than seaborne cargoes have increased. The data also show that Saudi Arabia, which undertook to make the largest output cut among those producers party to the November deal, is actually increasing tanker shipments in recent months, to levels well above those that prevailed late last year. The kingdom is expected to ship 8.29 million bpd in April, up from 7.94 million bpd in March, 7.73 million bpd in February and 7.83 million bpd in January.

Iraq says will comply with any OPEC oil production deal extension - Oil | Platts News Article & Story: Iraq believes it would be acceptable for the OPEC-led production cut deal to be continued in its current form, oil minister Jabbar al-Luaibi said Thursday. The producer group meets on May 25 to decide whether to extend the landmark agreement that came into force in January. Luaibi was tight-lipped on whether OPEC's second-largest producer would seek an exemption as it attempted last year in the run-up to the OPEC and non-OPEC deal before coming on board. Instead, Luaibi said Iraq should be aligned with OPEC and that the country would be in line with OPEC's final decision in May in a strong show of support that OPEC is singing with one voice.In the same vein, Luaibi stressed that Iraq is in "full compliance" with the OPEC-led deal to cut its production, playing down claims that it is the most non-compliant member. Speaking at the International Oil Summit in Paris, Luaibi then toned down his approach, saying Iraq had "reached 97% of its obligation," whereby it has agreed to slash crude output by 210,000 b/d over the six-month period. The deal calls for the group to cut 1.2 million b/d from October levels, while 11 non-OPEC producers, led by Russia, agreed to cut 558,000 b/d. Iraq, which has disputed secondary source estimates of its output, produced 4.40 million b/d in March, down slightly from February's 4.41 million b/d, according to secondary sources. Iraq did not self-report a March figure but said in February it produced 4.57 million b/d. The country appears to be the most non-compliant OPEC member in the deal, as its quota is 4.351 million b/d.

Why Kurdish Oil Is a Wild Card for Markets -- If Iraq’s Kurdish territory were a country, it would probably qualify for OPEC membership. It wouldn’t even be the smallest member, given its production of about 600,000 barrels of oil per day. That’s an impressive achievement for a landlocked enclave that started exploring only a decade ago. The region’s potential is greater still, though it faces political, military and economic challenges to expanding its output.The semi-autonomous Kurdistan Regional Government says the area’s reserves could total 45 billion barrels, more than Nigeria’s, and Kurdish crude is generally cheap to extract. When foreign investors tramped into the region’s oil fields after the fall of Saddam Hussein’s regime, the crude was so abundant it seeped from the ground beneath their feet. Tony Hayward, former BP Plc boss turned wildcatter, called Iraqi Kurdistan “one of the last great frontiers” in the oil and gas industry as his new company Genel Energy Plc started prospecting there in 2011. Ashti Hawrami, natural resources minister for the KRG, has spoken of increasing exports to 1 million barrels a day or more. Early discoveries prompted a rush of foreign investment, and by 2014 the Kurdish capital Erbil was a boomtown. The area attracted oil majors including Exxon Mobil Corp., Chevron Corp. and Total SA. Norway’s DNO ASA pumps the most oil there: more than 110,000 barrels a day at the Tawke field, in partnership with Genel.  Iraq’s Kurds have long chafed against control by Arab-led governments in Baghdad, and they’ve been developing their hydrocarbon industry to enhance their self-sufficiency. Kurdish authorities began offering oil contracts to foreign investors in 2007, against Baghdad’s wishes. The central government then barred companies working with the Kurds from operating in other parts of the country. Baghdad also threatened to sue anyone buying Kurdish crude. When it did just that in Texas in 2014, a U.S. judge blocked a tanker from unloading its cargo of Kurdish oil. The stakes rose that same year when Kurdish forces, defending against the encroachment of Islamic State, occupied oil facilities in the disputed province of Kirkuk. That’s left Baghdad in control of less than half of Kirkuk’s oil.

Why the crude rally has fizzled, continued: Market analysis series - This is the second of a three-part look at why oil prices have failed to rally despite OPEC’s best efforts at managing supply cuts. Read part 1 here. So, why is everyone so bullish? Many oil analysts take as a fait accompli that OPEC-led production cuts thus far are key to balancing the crude market. If this is the case, though, why hasn’t it happened yet? But the bulls say give it time. In the long run, the market will balance. Everyone knows what Keynes said about the long run (that we are all dead). That the market is prime for a rally has become gospel truth. But isn’t something so paradigmatic just a little bit risky? “Oil prices will get better, and you can take that to the bank,” David Purcell, head of macro research at Tudor, Pickering and Holt, said at a recent Dallas conference. “The market is under-supplied, inventories are back to normal levels by the end of the year, and if you guys don’t drill the Permian too fast, we’re okay,” Purcell said. But drilling too fast is just what drillers have been doing. According to Platts Analytics RigData, active Permian horizontal rigs now stand at 280, 40% of all US horizontal drilling. The number of US horizontal rigs will likely break above 700 soon, revisiting a number last seen in April 2015, when Permian rigs made up just 25% of the total.While Credit Suisse analysts earlier this month conceded that both Atlantic Basin and Asia-Pacific crude markets are suffering from oversupply — widening price discounts for Asian grades like Russia’s ESPO Blend and Qatar’s Al-Shaheen can attest to that — they also say that it is too early to ditch the idea that just because prices have struggled, the market isn’t rebalancing. In fact just two weeks ago, they suggested doubling down. A key factor to that call, which by now may be considered yesterday’s news, was the risk of supply disruption out of Libya after that country announced a fresh force majeure on exports from its Zawiya terminal.

US shale oil rebound shakes OPEC - The Barrel Blog: Even with oil prices hovering around the $50/b mark, the US rig count has increased rapidly while E&P companies continue to record substantial reductions in well drilling costs. The increase in new well oil production per rig demonstrates the extraordinary gains the shale drillers have made. In April 2014, new well oil production per rig on the Bakken was recorded at 492 barrels and on the Eagle Ford at 463 barrels. In April this year, the figures are 1,067 barrels and 1,448 barrels, respectively. Moreover, US E&P companies remain confident they can continue to eke further efficiencies out of their seemingly ever-evolving factory-mode production processes. However, not all is well. A large part of reductions in well costs came about as a result of the crunch in drilling activity post-2014, when the oil price fell from its heady three-digit heights. The lack of demand for drilling resulted in over-capacity in the oil services sector, which led to a fall in the prices charged for oil services and also a contraction in the sector’s capacity. As activity rebounds and the rig count rises, the oil services sector will also start to tighten and, indeed, US oil services costs are now forecast to rise about 20% this year. Even if US drillers can continue to deliver efficiency gains, they will have to battle this countervailing price pressure.Much depends on the oil services sector’s ability to re-establish its former capacity, but there is little short-term motivation to do so, as service providers will be keen to re-establish the margins they formerly enjoyed. As a result, forecasts that US crude production will return to the record levels of the 1970s in 2018 may well only be realized if oil prices move above $60/b. This, in turn, would appear to depend on an extension of OPEC’s production cuts into the second half 2017, and probably beyond, a prospect which will test the resolve of the organization’s non-OPEC partners. 

Oil prices falter as hedge funds stop buying: Kemp (Reuters) - Hedge funds have tempered their bullishness towards crude oil as the short-covering rally that gripped the market since the end of March ran its course.Hedge funds and other money managers increased their net long position in the three major futures and options contracts linked to Brent and WTI by 8 million barrels in the week to April 18 (http://tmsnrt.rs/2p97vXr).Fund managers have increased their net long position for three consecutive weeks by a total of 140 million barrels but the latest increase was much smaller than in the two previous weeks (http://tmsnrt.rs/2pWUMKz).Funds showed little appetite to increase bullish long positions further, though they continued to close out bearish short positions established earlier in March.Funds actually reduced long positions by 2 million barrels, though this was offset by a reduction in short positioning of 10 million barrels, according to an analysis of data published by regulators and exchanges.The ratio of long to short positions climbed to 5.8:1 up from a recent low of 3.7 on March 28 though it was still well below the peak of 10.3 set back on Feb. 21 (http://tmsnrt.rs/2p9aVts).The rally in oil prices between March 27 and April 12 was driven by short-covering as much as the establishment of fresh long positions.But most of those short positions had been closed out by April 11 and certainly by April 18 limiting further upward price momentum.By April 18, hedge funds had reduced short positions in NYMEX WTI to just 63 million barrels, down from a peak of 117 million barrels three weeks earlier (http://tmsnrt.rs/2pXkezz).The minimum hedge fund short positioning in NYMEX WTI over the last two years has been around 45-55 million barrels.So with few short positions left to be covered, the rally in Brent and WTI prices ran out of steam around the middle of April. Both flat prices and calendar spreads have been softening as the short-covering cycle is completed and amid growing doubts about whether OPEC’s output cuts are draining crude oil stocks.

WTI/RBOB Tumble After Surprise Crude, Gasoline Builds -- After dropping to a $48 handle, WTI bounced off its 200DMA, but remains well down from last week's levels before the DOE-reported surprise gasoline build. The initial kneejerk reaction lower in WTI/RBOB after API reported an unexpected crude build and yuuge gasoline build. API

• Crude +897k (-1.75mm exp)
• Cushing -1.971mm
• Gasoline +4.445mm (+500k exp)
• Distillates -36k

Following last week's surprise DOE reported build in gasoline inventories, API reports a huge build (bioggest in 3 months) and a surprise crude build (even as Cushing saw a big draw - the biuggest since feb 2014) Prices are well down from last week's API/DOE data prints, but bounced higher today into the API print. This initial reaction was a push lower in both WTI  and RBOB...

Oil traders’ confidence shaken by slow impact of supply cuts - Earlier bullishness gets a reality check as global crude inventories remain high - Oil traders banking on a sustained market recovery in 2017 are growing impatient. As the price of Brent crude falls towards $50 a barrel, Opec, energy analysts and some of the most powerful banks in the commodities sector are urging traders to maintain their composure. After a production cut deal between the cartel and rivals such as Russia was agreed late last year, prices began 2017 $10 a barrel higher and hedge funds quickly amassed record bets backing the push to end the biggest slump in more than a decade. Confidence has since been shaken as evidence that the cuts are working takes longer than anticipated to materialise. Global crude inventories remain stubbornly high and, crucially, the US shale industry has been reinvigorated by the run up in prices last year. “The premature bullishness we saw in early 2017 has had a reality check,” says David Fyfe, chief economist at oil trader Gunvor Group. “The market has been a bit spooked by persistently high stocks.”

WTI/RBOB Jump On Largest Crude Draw In 2017 Offset By Major Product Build, Rising Production - WTI/RBOB prices were at the lows of the day after last night's huge surprise inventory data from API, but kneejerked higher after DOE reported a surprisingly large crude draw (the biggest since Dec 2016. However, it's clear that refineries are on fire as gasoline and distillates inventories surged by the most in at least 3 months. US crude production rose once againto its highest since August 2015. DOE:

• Crude -3.64mm (-1.75mm exp) - biggest since 2016
• Cushing -1.203mm
• Gasoline +3.369mm (+500k exp) - biggest in 3 months
• Distillates +2.651mm (-1mm exp) - biggest since first week of Jan

As Bloomberg notes, the U.S. refining system is absolutely on fire: up another 347,000 barrels a day last week to 17.3 million barrels a day processing. It's huge. And that explains the major builds in products (gasoline/distilates) and surprise draw in crude... Crude stocks fell -3.6 million bbl to 529 million bbl last week, a faster draw down than normal at this time of year.As Reuters adds, crude stocks tightened last week by about -5.7 million bbl compared with 2016 and -7.6 million bbl compared with 10-yr average.  Crucially, as Bloomberg's Javier Blas details: Saudi Arabia cutting production? Not much, if you believe the U.S. oil imports figures. Last week, the U.S. bought from the kingdom 1.19 million barrels of oil, up from 1.18 million barrels the previous week. Imports from Kuwait and Iraq also rose last week. So far, OPEC cuts are not really translating into lower U.S. imports from key players in the Middle East.

U.S. crude supplies post biggest weekly fall of the year, down 3 weeks in row - Oil futures turned higher Wednesday after U.S. government data revealed that crude supplies fell a third week in a row, by their largest weekly amount of the year. Prices for petroleum products, however, fell on the back of unexpected inventory increases for gasoline and distillates.June West Texas Intermediate crude tacked on 47 cents, or 1%, to $50.03 a barrel on the New York Mercantile Exchange. It was trading lower at about $49.28 before the supply data. June Brent crude on London’s ICE Futures exchange traded at $52.24 a barrel, up 14 cents, or 0.3%. The U.S. Energy Information Administration showed that domestic crude supplies fell 3.6 million barrels for the week ended April 21. That was the largest weekly decline so far this year. Crude stockpiles also posted declines in each of the previous two weeks. The American Petroleum Institute late Tuesday reported a rise of 897,000 barrels for crude supplies, while analysts polled by S&P Global Platts forecast a fall of 1 million barrels. The headline crude number “stands in sharp contrast” to the rise reported by industry group, API, Chris Kettenmann, chief energy strategist at Macro Risk Advisors. The 1.2 million-barrel draw at the storage hub in Cushing, Okla., is “another net positive in the report.” But “the glaring net build in gasoline refined products” and rise in the lower 48 states crude production is “enough to keep us cautious on oil prices in the near term,” said Kettenmann. “We would not buy the knee-jerk rally on the print.” The EIA reported a rise of 21,000 barrels a day in lower 48 states output to total 8.722 million barrels a day. Gasoline stockpiles rose by 3.4 million barrels, while distillate stockpiles were up 2.7 million barrels last week, according to the EIA. The S&P Global Platts survey had forecast declines of 1.1 million barrels for gasoline and 1.8 million barrels for distillates, which include heating oil. 

Oil prices rise after big draw in U.S. crude inventories | Reuters: Oil prices rebounded from earlier losses on Wednesday after data showed a larger-than-expected falloff in U.S. crude inventories, a salve for investors after several days of declines founded on worries about the slow pace of global efforts to reduce a glut. The U.S. Energy Department said crude stocks dropped 3.6 million barrels last week, more than double what was expected, juicing some buying in the market. [EIA/S] U.S. crude futures have slipped in six of the last seven days, as investors have grown impatient with high inventories after last year's landmark deal by the world's major oil producers to cut output. The U.S. government data counters Tuesday's report from industry group the American Petroleum Institute that showed an unexpected build in inventories. However, gasoline and distillate stockpiles grew, while U.S. production and imports increased, so the path for higher prices remains tentative, analysts said. U.S. West Texas Intermediate (WTI) was up 37 cents at $49.93 per barrel, while Brent crude, the international benchmark, was up 11 cents to $52.21 a barrel by 11:31 a.m. EDT. The gains in oil prices were offset by a drop in reformulated blendstock gasoline prices, which dropped by 1.3 percent to $1.5999 a gallon after gasoline inventories rose sharply. Refining capacity utilization rose to 94.1 percent, highest since November 2015. That boosted gasoline inventories at 241 million barrels, or about where inventories were at this time in 2016, which sapped refining margins.

Record U.S. refinery runs fail to lift crude oil prices: Kemp (Reuters) - U.S. refineries processed a record volume of crude last week, making a small dent in the country’s bloated crude stocks but resulting in a big build-up of refined product inventories.U.S. refineries have ramped up crude processing by 1 million barrels per day (bpd) over the last four weeks and 2 million bpd over the last nine weeks, according to the U.S. government's Energy Information Administration.Refineries processed an average of almost 17.3 million bpd of crude in the week to April 21, a record for any time of year and coming well in advance of the summer driving season.Crude throughput was almost 1.4 million bpd higher than during the corresponding week in 2016 and nearly 2.5 million bpd higher than the 10-year seasonal average.Refiners are responding to robust domestic demand and strong exports of gasoline and distillates, which have resulted in margins above last year’s levels (“Distillate export boom keeps U.S. refiners busy”, Reuters, April 25). Heavy processing so early in the year has started to pull down U.S. crude stockpiles much earlier than normal.Commercial crude stocks are still almost 20 million barrels higher than at the same point in 2016, but the year-on-year surplus is down from about 36 million barrels at the start of April.Crude stocks are now around 49 million barrels higher than at the start of the year, compared with a build of 57 million barrels in 2016 and a 10-year average of 42 million barrels.But the extraordinary rate of crude processing has also led to a rise in gasoline and distillate stocks, which has led some analysts to question whether it is sustainable.Gasoline stocks are at a record for the time of year and distillate stocks have started rising when they would normally be falling.U.S. refiners are exporting record volumes of distillates to Latin America; rare cargoes have been exported from the East Coast to Europe (“Europe lures rare diesel cargoes from U.S. East Coast”, Reuters, April 26). Gasoline exports are also running well above year-ago levels as refiners and traders try to clear some of the surplus by sending it overseas.The United States has become an increasingly important refining hub for the western hemisphere and Atlantic basin thanks to cheap domestic crude and investment in sophisticated equipment. But it is not clear whether such high levels of processing can be sustained for many more weeks without crushing refinery margins.

WTI/RBOB Tumble As Market "Runs Out Of Patience With OPEC" -- Just as we warned yesterday following the EIA inventory and production data release, the exuberance over the crude draw was misplaced (due to the surge in product builds and almost unprecedented refining activity along with continued resurgent oil production). Saudi imports continue to show no sign of the OPEC cuts and asone anylst noted "the market looks like it wants to turn lower, maybe it has run out patience waiting for OPEC"As a reminder, U.S. crude inventories declined 3.6m bbl in EIA data Wednesday, but gasoline, distillate stockpiles grew by a combined 6m bbl, and U.S. production also grew for 10th week. As Bloomberg reports, WTI, Brent deepen declines and erase Wednesday’s post-EIA rally as market’s focus switches to big builds in gasoline and distillate inventories, rather than the crude draw.“The gasoline numbers took the edge off the headline,” in EIA data Wednesday, says Jasper Lawler, senior market analyst at London Capital Group."In the last couple of days we’ve had two afternoon attempts to reverse the downtrend and both have heavily been sold into.""The market looks like it wants to turn lower, maybe it has run out patience waiting for OPEC" The result is clear...

Oil prices are tanking, now at a 4-week low - U.S. oil prices fell below $49 a barrel on Thursday amid deteriorating gasoline futures and a higher dollar in the wake of the European Central Bank's latest interest rate decision.  Benchmark Brent and U.S. crude futures both fell more than 2 percent in late morning trade, extending losses to drop below their 200-day moving averages. Both contracts have fallen in 6 of the last 8 sessions, with only moderate gains on positive days.  The decline accelerated after the ECB left interest rates at zero percent, nudging the dollar higher. A stronger greenback makes dollar-denominated commodities like oil more expensive to holders of other currencies, discouraging buying. News that Libya had restarted two of its main oil fields after protests also added to selling pressure. Libya is one of two exporters exempt from OPEC's production cuts aimed at reducing a global oversupply of oil. That compounded weakness in the energy complex after the U.S. government reported a large build in gasoline inventories as refiners pumped a record amount of crude into facilities last week. This comes amid relatively weak gasoline demand.

Oil prices felled by Libyan oil restart and weak gasoline demand | Reuters: Crude prices were slightly lower after a volatile session on Thursday, as the restart of two key Libyan oilfields and concerns about lackluster gasoline demand fed concern over whether major oil producers can alleviate the glut of global inventories. Libya's Sharara and El Feel oilfields, which can produce nearly 400,000 barrels per day (bpd), returned to production after protests blocking pipelines ended. U.S. gasoline futures led the energy complex lower in choppy trading, at one point hitting its lowest level seasonally in eight years after data on Wednesday showed inventories rose by the most in nearly three months. Brent crude LCOc1 settled down 14 cents a barrel at $51.68. U.S. light crude CLc1 was down 37 cents to $49.25 a barrel. “Gasoline is kind of keeping crude from going up very much," said James Williams, president of energy consultant WTRG Economics in London, Arkansas. U.S. gasoline RBc1 tumbled almost 2 percent to $1.559 a gallon. "Gasoline is leading the way lower with ample stocks, lower demand compared to last year, and an increase in gas(oline) stocks on the east coast," said Anthony Headrick of CHS Hedging. “For the last four weeks gas demand is down 1.8 percent from last year.” Global crude oil inventories have remained high, in part because of increased production from the United States. At 9.27 million bpd it is at its highest since August 2015, according to government data.

Oil prices extend losses on supply concerns --  Crude prices fell more than 1 percent on Thursday as the restart of two key oilfields in Libya pumped more crude into an already bloated market. U.S. gasoline futures also led the complex lower, falling to the lowest in at least eight years for this time of year after inventories rose by the most in nearly three months and demand remained weak. Benchmark Brent crude was down 19 cents at $51.63 a barrel by 2:35 p.m ET (1735 GMT), nearly 9 percent below this month's peak. U.S. light crude ended Thursday's trade 65 cents, or 1.3 percent, lower at $48.98, having fallen to a fresh four-week low. Libya's 300,000 barrels per day (bpd) Sharara oilfield and 90,000 bpd El Feel oilfield have restarted after the end of protests that had blocked pipelines there, a Libyan oil source and local official said.Libyan crude production stood at 491,000 bpd on Thursday, but the OPEC member was targeting 800,000 bpd soon and 1 million to 1.1 million bpd by August, the chairman of state oil firm NOC said on the sidelines of an industry event in Paris. The news of the Libyan restarts helped push Brent below its 200-day moving average (MA) at $51.29 a barrel, a key technical support. "The 200-day had been a bullseye and today we fell through it. So to me that could be a bullish omen," said Anthony Headrick, energy market analyst at CHS Hedging. U.S. gasoline tumbled almost 3 percent to $1.5458 a gallon, the lowest since at least 2009 for this time of the year. 

Gasoline Demand Concerns Pressure Oil Prices - Now that the Organization of the Petroleum Exporting Countries (OPEC) has provided more certitude that an extension of the 1.2 million barrel per day coordinated cut is in the works, the market has shifted its worries to a glut in petroleum products. Although other concerns plague the market, such as a rising dollar, growing U.S. crude output, and material production from Libya coming back online, the main driver of uncertainty is the state of U.S. gasoline demand. For the second week in a row, the Energy Information Agency (EIA) reported a substantial build in U.S. gasoline inventories. For the week ending April 21, gasoline stocks rose by 3.4 million barrels. Demand for finished motor gasoline fell slightly week over week to 9.206 million barrels per day, but the 4-week average was down about 2 percent versus the same period last year. In anticipation of the summer driving season – when gasoline demand peaks – refiners have ramped up production to record levels, processing 17.3 million barrels per day at a seasonally high utilization rate of 94.1 percent, for the week ending April 21. At the same time imports of finished gasoline have been unusually high over the last two weeks – at 916,000 barrels per day for the week ending April 21 and 843,000 barrels per day during the previous week. Since Wednesday’s EIA data release, gasoline futures on the NYMEX and ICE have been trading down about 2 percent and 1.5 percent, respectively. Lower demand expectations for gasoline drag down oil prices as traders predict a reduction in refinery output, which would lead to growing stockpiles of crude. While waning gasoline consumption may be pressuring oil prices, the fact that crude inventories have been falling has provided some support. For the week ending April 21, the EIA reported a larger than expected drop in crude inventories of 3.6 million barrels. At Cushing, OK – the delivery point for the WTI contract – inventories fell by 1.2 million barrels for the week ending April 21. Looking at the larger economic picture in the United States, it would seem that the “Trump Trade,” which was staked on optimism around changes to policy that would boost business and employment growth, has lost steam. Now that the first 100 days have passed – with no legislative victories to claim – it appears that consumer confidence and other economic gauges are destined to continue flat-lining or fall. This implies a weak outlook for gasoline demand, which is highly correlated to GDP and employment growth.

OilPrice Intelligence Report: Crude Drawdowns Can’t Save Oil Prices: Oil prices got walloped this week on growing concerns that U.S. shale is coming back too quickly, offsetting the progress made by OPEC. Meanwhile, disrupted Libyan production could come back online, taking one of the few reasons to be bullish away. WTI briefly sank below $49 per barrel on Thursday, but regained a bit of ground at the start of trading on Friday.. U.S. refiners processed a record volume of crude oil last week, according to the EIA. With maintenance season over and refiners ramping up to meet summer demand, they are pulling crude oil out of storage. U.S. inventories dropped by 3.6 million barrels, the largest drawdown in quite a while. But that did very little for oil prices, which dropped sharply this week. One reason the data could be a little misleading: gasoline stocks actually jumped much higher, so all that refining is resulting in gasoline heading into storage. Goldman Sachs’ head of commodities, Jeff Currie, said that OPEC is likely to extend its deal for another six months. That could result in WTI trading between $55 and $60 for the rest of this year, which is a "substantial upside, given we are trading at roughly $49.50", Currie said on Bloomberg TV.. The IEA said on Thursday that the oil industry discovered a record low amount of oil in 2016, logging just 2.4 billion barrels in new discoveries. Also, the volume of oil given final investment decisions in 2016 amounted to 4.7 billion barrels, the lowest level in 70 years. The result could be a supply shortage towards the end of the decade, the IEA warned. In fact, the IEA has repeatedly warned about the pending shortfall, which would lead to higher prices and much more volatility by 2020.    Although there is conflicting news about what is going on in Libya, Reuters reports that several key oil fields in Libya are restarting operations, including the Sharara field that has a capacity of 300,000 bpd. That news could have been a big reason for the 1.6 percent sell off of WTI and Brent on Thursday. To be sure, there were separate reports that the Sharara field remained shut and Libyan production was still at a 7-month low at 490,000 bpd. Needless to say, Libyan production will likely seesaw for the foreseeable future, and conflicting reports will be likely.

U.S. Oil Rig Count Increases For 15th Straight Week --The number of active oil and gas rigs in the United States rose by 13 on Friday, according to oilfield services provider Baker Hughes. The total oil and gas rig count in the US now stands at 870 rigs, or 450 above the count a year ago.Oil rigs increased by 9, while gas rigs bumped up 4. This week marks the fifteenth straight build for oil rigs (+175 or +33.5% since January 13). While gas rigs haven’t enjoyed the same persistently ascending trajectory week to week, they have climbed 10 of the last fifteen weeks, for a total gain of 35 (+25.7%). The largest three-week gain in the number of active oil rigs in the US over the last decade was April 1, 2011. The rig count spiked 26 that week, for a total of 76 rigs gained over a three consecutive-week period. WTI spot price that day was $107.55. Total number of active oil rigs that week: 877.So far this year, traders have watched, mostly likely in horror, at the tug of war between OPEC’s efforts to “rebalance” the market, and U.S. shale’s efforts to take full advantage of that rebalancing effort. For every depressing API or EIA report about the lackluster results of the global inventory drawdown efforts, and for every rig count report that shows U.S. Shale keeps picking up steam, OPEC’s obedient compliance to the cuts and talks of an extension appeases at least enough of the masses to generally keep oil above $50. Many have cautioned U.S. Shale drillers that bringing too much on too quickly could keep prices depressed, or depress them to a greater degree. The chart below, looking at the weekly price (Fridays) of WTI and the rig count over the last decade does show a pretty tight correlation to price (lower correlation is seen when price swings are sharp and dramatic), but also shows that the price of WTI pulls along the rig count, and not the other way around—at least not long term.

Baker Hughes U.S. Rig Count Rises by 13 - U.S. oil and natural gas producers brought online 13 rigs in the past week, sending Baker Hughes' (BHI) rig count up to a total of 870 units. Nine oil rigs were added week over week, while the number of natural gas rigs rose by four, according to the Houston oilfield services provider. Meanwhile, just as President Donald Trump signed an executive order calling for a review of America's offshore drilling policies, Baker Hughes reported the U.S. offshore count fell by three this week. The offshore count, now at 17 overall, is down eight rigs year over year. Industry analysts don't expect Trump's executive order to have a meaningful impact on offshore rig counts for at least two years as much of the Arctic and Atlantic oceans would require extensive seismic testing and geological studies for operators to determine where profitable reserves can be drilled. All told, the U.S. land rig count is now up 450 rigs from a year ago when it stood at 420, Baker Hughes data showed. Oil rigs are up 365 in the past year, while natural gas rigs have climbed by 84 and miscellaneous rigs are up one. Contrary to the recent trend, the Permian Basin of West Texas and New Mexico did not see the largest weekly gain, adding just two rigs. South Texas' Eagle Ford Shale oil and natural gas play for the second consecutive week saw the largest uptick in drilling activity with five new rigs coming online. Still, the Permian has of late been the dominant force behind increased drilling activity as strategic operators have bolstered acreage in the play to inevitably ramp production in the most lucrative of U.S. oil basins.   Out of the 870 active U.S. land rigs, 342 are focused on the Permian, according to Baker Hughes' data. By comparison, the basin with the nearest level of activity to that of the Permian is the Eagle Ford with 83 rigs online. Overall, the U.S. land rig count's first-quarter average of 719 units was 27% above fourth quarter numbers, Stephens oilfield services analysts Christopher Denison and Brooks Braden said in a recent research note. And the firm expects the count to increase another 20% quarter over quarter in the second frame.

Oil Shortage Feared by 2020 as Discoveries Fall to Record Low - —Global oil discoveries fell to a record low in 2016, the International Energy Agency says, raising fresh concerns about the potential for a petroleum-supply shortage as soon as 2020.  The IEA—a Paris group that monitors energy trends for oil-dependent places like the U.S. and Europe—is stepping up its warnings about historically low oil-industry investment during the latest price downturn. Oil companies and producing nations curtailed spending by hundreds of billions of dollars during the price rout, resulting in the fewest new conventional oil projects being sanctioned in 2016 since the 1940s, the IEA said. The group’s assessment, shared with The Wall Street Journal ahead of a full investment report to be released in July, represents its most comprehensive study yet of how the downturn has already negatively affected spending. The IEA doesn’t forecast oil prices, but any shortage would likely cause significant crude-price increases. Don’t expect output from U.S. shale producers to fill the void, the IEA said. American shale production is expected to grow by 2.3 million barrels a day or more over the next five years, but that isn’t enough to make up for declining output elsewhere. The IEA also doesn’t expect global oil demand to stop growing any time soon, potentially turning the current glut of oil into a dearth. “The key question is how long can the surge in U.S. shale supplies make up for the declining pace of growth elsewhere?” said IEA executive director Fatih Birol. “We are worried about historically low discoveries and new projects.” A new “boom-and-bust cycle” looks increasingly likely if conventional projects—generally defined as anything that uses traditional methods to extract oil, unlike shale—don’t receive greater investments, Mr. Birol said. In 2016, oil discoveries amounted to just 2.4 billion barrels of potential oil, the lowest since the IEA’s records began in 1950. That is down from 6.4 billion barrels of discoveries in 2013, when oil prices were consistently above $100 a barrel and 16.3 billion barrels in 2010, the IEA said. The global oil industry greenlighted projects amounting to over 4.8 billion barrels of oil in 2016, down from 21.2 billion barrels in 2014.

Can An OPEC Extension Push Oil To $60? -- It now seems quite likely that OPEC will agree to an extension of November’s production cut agreement at their May meeting. The question facing analysts and market watchers is how much a cut extension will impact the market going forward, and whether it will deliver the boost in prices that OPEC is hoping for. In November, the agreement was a boon to the price, sending WTI north of $50, only for prices to fall a few months later. The impact of the deal, which was publicized for months beforehand and enjoyed blanket coverage from all major market media outlets, was significant but temporary. Inventory reports in February caused the price to crash back down, and apart from a brief swing upwards after U.S. missile strikes in Syria, an event which had analysts crowing over the return of the risk premium, prices have slumbered near $50, far below where OPEC needs them to be. Undoubtedly, OPEC is hoping an extension of cuts will have a more lasting effect, delivering true stability to markets and lifting prices up to $60. The level several OPEC members have indicated they want prices to rest over the long-term, in order to balance their budgets. But a string of bearish signs have pushed the price below $50, and barring another bout of “geopolitical risk,” it seems only significant changes in fundamentals will deliver the boost OPEC needs. The impact of the first round of cuts was blunted in part due to the ramp-up in production during the fourth quarter of 2016. Huge inventories were reported in the U.S. early in 2017, though there were declines in OECD inventories according to the IEA, evidence that the OPEC and non-OPEC cuts totaling 1.8 million bpd were having some effect, despite low compliance from non-OPEC states. American inventories were expected to fall, boosting price in the short-term. Instead, unexpectedly high gasoline inventories pushed the price to its lowest point in weeks in mid-April, despite simultaneous drops in the crude supply. The decline of about 1 million barrels was less than analysts predicted. American inventories are falling, which bode well for a price recovery if OPEC does decide to extend cuts. Yet the effect may not be immediate enough for OPEC to declare victory in June, as rising production in the fourth quarter of 2016 in OPEC and outside of OPEC in early 2017 basically obviated the cumulative effect of the cuts.

King Scales Back Austerity Plan That Set Saudis Grumbling --  Saudi Arabia’s King Salman restored bonuses and allowances for state employees, scaling back an austerity program that generated criticism among citizens accustomed to generous state handouts. The government said the perks canceled in September were reinstated because higher-than-expected revenue helped to drive down the budget deficit. Minister of State Mohammed Alsheikh said in a statement to Bloomberg that the injection of more money was expected to stimulate economic growth, but others said the kingdom’s rulers were responding to the discontent the cutbacks created. The decision “constitutes a step back in terms of forging a new social contract that no longer offers the Saudi public cradle-to-grave welfare,” said James M. Dorsey, a Saudi specialist and senior fellow in international studies at Nanyang Technological University in Singapore. It suggests the government is worried that its economic overhaul plan hasn’t been accepted “by segments of the population who have the most to lose from diversification and streamlining of the economy, including the bureaucracy,” he said. In his decrees Saturday night, King Salman also pressed on with a government shakeup that has installed his children in key positions. Prince Abdulaziz bin Salman was named Minister of State for Energy Affairs, while Prince Khalid bin Salman was appointed envoy to Washington. Additionally, Ibrahim AlOmar, a former chief executive of National Shipping Co., was appointed governor of the Saudi Arabian General Investment Authority.  The government has not said how much the bonuses were worth, but an estimated two-thirds of all working Saudis are public sector employees.

Saudi Arabia reverses austerity measure and reinstates benefits -- Saudi Arabia’s King Salman bin Abdulaziz reversed one of the kingdom’s most contentious austerity measures on Saturday, reinstating benefits to civil servants and military personnel. In dozens of royal decrees, King Salman also reshuffled the cabinet, appointing his son, Prince Khaled bin Salman, as ambassador to the US. The reinstatement of benefits to civil servants after six months underlines the limits of reform in the kingdom, where the ruling family must be seen to provide for the people in return for loyalty to the state. “The royal order returns all allowances, financial benefits and bonuses to civil servants and military staff,” the decree said. Last year’s move, which affected the take-home pay of two-thirds of working Saudi nationals, was the most severe measure taken to limit government spending in a time of low oil prices. It had an instant impact on consumer confidence and business sentiment. The reversal was also regarded as politically damaging to Mohammed bin Salman, the powerful 31-year-old deputy crown prince, who is leading the kingdom’s economic reform drive. Officials said the reinstatement of benefits was made possible by a better than expected fiscal situation after two years of cost-cutting to combat the sustained fall in oil prices. Mohammed al-Tuwaijri, the deputy economy minister, said on state television that the first quarter deficit was SR26bn ($7bn), compared with SR54bn projected at the beginning of the year.

Analysis: No sign of oil policy reversal from Saudi Arabia after royal decrees -  Saudi King Salman's surprise decrees over the weekend that reinstated allowances and bonuses for public sector employees and military personnel is not a sign that the much heralded Vision 2030 economic reforms are being put aside, according to analysts and Saudi observers. But nor is the policy reversal evidence of any return to the kind of government largesse that some Saudis had become used to. Rather, the changes amounted to a recognition of a need to correct a year of austerity measures that hit too hard, as the kingdom struggled to adapt to lower oil prices.The king on Saturday also appointed several government officials seen as close to Vision 2030 champion and Salman's son, Deputy Crown Prince Mohammed bin Salman, which would appear to cement the ambitious economic reform plan. "Vision 2030 might be detoured from time to time but it represents Plans A, B and C for the government," said Matthew Reed, vice president at Washington-based Middle East consultancy Foreign Reports. "Most Saudis recognize the system needs fixing, that there is fat to cut. But last year, when state finances looked grim, Riyadh cut to the bone when it suspended benefits and bonuses. It was probably too deep," he added. 

If Saudi Future’s So Bright, Why Can’t These Banks Find Buyers? -- Saudi Arabia is about to cast off its oil-dependence, build brand-new industries and open its economy to foreign investment, according to the government. That might make it a good time to buy into a Saudi bank. And substantial stakes in two of them are up for sale.But in both cases, it’s international lenders who are seeking to get out -- and there are no big-name global banks eager to buy, according to analysts and people familiar with the transactions; what interest there is comes from local or regional groups. That reflects concerns about prospects under Saudi Arabia’s ambitious reform program, as Deputy Crown Prince Mohammed bin Salman cuts back the government spending that’s traditionally buoyed the economy.One result of austerity is the worst growth since the world recession of 2009, and it’s forecast to slow further this year. New construction projects are scarce, and payments to builders got held up last year. That’s hurting banks that lend to them, including the two on the market. Royal Bank of Scotland Group Plc has reportedly been seeking for years to sell its 40 percent stake in Alawwal Bank, while Credit Agricole SA is considering a sale of its 31 percent stake in Banque Saudi Fransi, according to people familiar with the matter.Control of the banks isn’t on offer, and that’s one issue for buyers. But another is that banking is “basically the final stopping point you find of all the risks in the Saudi economy,” said Crispin Hawes, London-based managing director at Teneo Intelligence. “They all crystallize in the loan books of domestic banks.” So, even if there’s a “very good case” for investment in some industries, that’s less true in banking, Hawes said.

Outrage After At Least 5 EU Nations Elect Saudi Arabia On UN Women's Rights Council -  In what may have been the biggest trolling of the United Nations in recent history, Saudi Arabia was elected via secret ballot in the UN Economic and Social Council to the 45-member UN Commission on the Status of Women last week. According to Reuters, twelve other countries were also elected by the council in Geneva to serve for a four-year term, ending in 2022: Algeria, Comoros, the Democratic Republic of the Congo, Ghana, Kenya, Iraq, Japan, South Korea, Turkmenistan, Ecuador, Haiti and Nicaragua.The news promptly sparked mocking and ridicule. UN Watch, a human rights organization monitoring the performance of the United Nations, strongly condemned the appointment of Saudi Arabia to post,citing Riyadh’s poor women’s rights record and widespread gender inequality.“Electing Saudi Arabia to protect women’s rights is like making an arsonist into the town fire chief. It’s absurd,” Hillel Neuer, the UN Watch chief, said. Every Saudi woman “must have a male guardian who makes all critical decisions on her behalf, controlling a woman’s life from her birth until death. Saudi Arabia also bans women from driving cars,” Neuer added.

Exclusive: Trump complains Saudis not paying fair share for U.S. defense | Reuters: President Donald Trump complained on Thursday that U.S. ally Saudi Arabia was not treating the United States fairly and Washington was losing a “tremendous amount of money” defending the kingdom. In an interview with Reuters, Trump confirmed his administration was in talks about possible visits to Saudi Arabia and Israel in the second half of May. He is due to make his first trip abroad as president for a May 25 NATO summit in Brussels and could add other stops. "Frankly, Saudi Arabia has not treated us fairly, because we are losing a tremendous amount of money in defending Saudi Arabia,” he said. Trump’s criticism of Riyadh was a return to his 2016 election campaign rhetoric when he accused the kingdom of not pulling its weight in paying for the U.S. security umbrella. "Nobody’s going to mess with Saudi Arabia because we’re watching them," Trump told a campaign rally in Wisconsin a year ago. “They’re not paying us a fair price. We’re losing our shirt.” The United States is the main supplier for most Saudi military needs, from F-15 fighters to control and command systems worth tens of billions of dollars in recent years, while American contractors win major energy deals. The world's top oil exporter and its biggest consumer have enjoyed close economic ties for decades, with U.S. firms building much of the infrastructure of the modern Saudi state after its oil boom in the 1970s. Saudi officials could not immediately be reached for comment on Trump's latest comments.

IMPORTANT CORRECTION TO The Nerve Agent Attack that Did Not Occur - In my earlier report released on April 18, 2017 titled The Nerve Agent Attack that Did Not Occur: Analysis of the Times and Locations of Critical Events in the Alleged Nerve Agent Attack at 7 AM on April 4, 2017 in Khan Sheikhoun, Syria, I misinterpreted the wind-direction convention which resulted in my estimates of plume directions being exactly 180° off in direction. This document corrects that error and provides very important new analytic results that follow from that error.When the error in wind direction is corrected, the conclusion is that if there was a significant sarin release at the crater as alleged by the White House Intelligence Report issued on April 11, 2017 (WHR), the  immediate result would have been significant casualties immediately adjacent to the dispersion crater.The fact that there were numerous television journalists reporting from the alleged sarin release site and there was absolutely no mention of casualties that would have occurred within tens to hundreds of meters of the alleged release site indicates that the WHR was produced without even a cursory low-level review of commercial video data from the site by the US intelligence community. This overwhelmingly supports the conclusion that the WHR identification of the crater as a sarin release site should have been accompanied with an equally solid identification of the area where casualties were caused by the alleged aerosol dispersal. The details of the crater itself unambiguously show that it was not created by the alleged airdropped sarin dispersing munition.These new details are even more problematic because the WHR cited commercial video as providing information that it used to derive its conclusions that there was a sarin attack from an airdropped munition at this location. As can be seen by the corrected wind patterns in the labeled photographs on the next page, the predicted direction of the sarin plume would take it immediately into a heavily populated area. The area immediately adjacent to the north northwest of the road is may not be populated, as there was likely heavy damage to those homes facing the road from a bombing attack that occurred earlier at a warehouse to the direct east of the crater (designated on map below). However, houses that were immediately behind those on the road would have been substantially shielded from shock waves that could have caused heavy damage to those structures.

Boris Johnson’s foreign policy in Syria is based on wishful thinking -- There is nothing surprising in Boris Johnson saying that it would be difficult for the UK not to join US military action in Syria against President Bashar al-Assad’s forces in response to a chemical weapons attack. Since the Second World War British governments have been trying to strengthen the UK’s status as the most important military ally of the US. But after 9/11 this obeisance became more craven and knee-jerk, despite producing failed British military ventures in Iraq and Afghanistan. With the Trump administration in power in the US, these British efforts to prove to Washington the usefulness and reliability of its links to the UK have become ever more desperate. Britain’s departure from a major alliance like the EU, and likely confrontation with it over the terms of Brexit, is bound to make Britain less of a power in the world. It therefore needs to foster closer relations with Trump’s America along with an unsavoury list of countries such as Turkey, Saudi Arabia and Bahrain. This may be a little more dangerous than it looks because nobody quite knows what the Trump foreign policy will amount to in Syria and Iraq. Is it, for instance, going to confront Iran and tear up the nuclear agreement with Tehran? Has it reverted to giving priority, at least nominally, to getting rid of Assad? These questions are worth thinking about, if only so as not to repeat the ill-thought-out flippancy with which British governments plunged into such dangerous places as Basra in southern Iraq in 2003 where it ended up signing a humiliating truce with the Mehdi Army Shia militia.

As Conflict Rages On, Russia Lands Oil Deals In Syria -- Russia’s brazen confidence in its victory in propping up Syrian President Bashar Al Assad’s once-failing regime grows day by day, as evidenced by Moscow’s latest oil deals with the Syrian government.Sputnik news reports that Russian Deputy Prime Minister Dmitry Rogozin visited Damascus in November to get the ball rolling on the fossil fuel deals. “We already started with some of the companies after his visit … the Syrian market is free now for Russian companies to come and join and to play an important part in rebuilding Syria and investing in Syria," Assad said, according to a report last week. “The process of signing the contracts, the final, let's say, steps of signing the contracts is underway.”This isn’t the first we have heard of Russia’s interest in Syria’s fossil fuel resources. In February, Dmitry Sablin, a lawmaker from the Duma, confirmed that Assad had greenlighted Moscow’s energy projects in the country."With regard to oil and gas production, he said that neither Iran nor China have companies with a worldwide reputation in this field, as Russia has, so in the oil and gas production, he [Assad] sees only the work of Russian companies," Sablin said. To be fair, Iran’s “worldwide” reputation was likely maimed due to six years of international sanctions against the nation’s oil sector, which were only lifted in January of last year. As the world’s largest energy consumer, China is occupied with making sure locally produced fuel remains available for domestic use. Beijing’s foreign efforts have been focused on securing access to reserves in African countries, such as Angola, Nigeria, and Sudan.

US Deploys Troops Along Syria-Turkey Border - Just three days after Turkish warplanes killed at least 20 US-backed Kurdish fighters along the Turkey-Syria border as well as several Kurdish peshmerga troops on Mount Sinjar in northwestern Iraq, footage posted by Syrian activists showed the US has deployed troops and APCs in the contested region, in a move that could potentially drag the US in a conflict where it already finds itself mediating between two so-called US ally forces in the proxy war against Syria. The Turkish airstrikes also wounded 18 members of the U.S.-backed People's Protection Units, or Y.P.G., were criticized by both the U.S. and Russia. The YPG is a close U.S. ally in the theatrical fight against the Islamic State (whose real purpose is destabilizing the Assad regime); it is seen by Ankara as a terrorist group because of its ties to Turkey's Kurdish rebels. The problem is that Turkey is also an ally of the US, although over the past two years relations between Turkey and all western NATO allies have deteriorated substantially for numerous familiar, and extensively discussed in the past, reasons.On one hand, further clashes between Turkish and Kurdish forces in Syria could potentially undermine the U.S.-led war on the Islamic State group. On the other, it risks taking an already unstable situation in Syria and escalating it substantially, should Turkey again find itself invading Turkey and/or Iraq. Which is why the US appears to have deployed troops along the border: to serve as a deterrent to further Turkish attacks.

Reddit Allows “Syrian Rebel” Group To Promote Al-Qaeda Affiliates  -- An investigation has revealed that terror groups operating out of Syria have taken to Reddit, utilizing the online messageboard as a forum for individuals who support Islamic terror groups operating inside Syria. Disobedient Media has determined that the subreddit r/SyrianRebels lists at least one moderator who appears to support extremist-aligned groups in Syria and has recently announced that they will host an "Ask Me Anything" session with a senior Al-Qaeda militant in charge of media outreach for the terror group. Reddit has refused to remove the subreddit, claiming that it does not violate their site's rules. The front page of r/SyrianRebels sports a number of posts that are anti-Assad and support the contention that the Syrian government was behind the April 4th chemical weapons attack in Khan Shaykhun, Syria. They also feature several articles from the Atlantic Council. Disobedient Media has previously noted that the Atlantic Council is a think tank which has in the past taken money from special interests in return for pushing specific policy objectives that benefit their donors.Multiple members of the subreddit's moderating team appear to be either supporters or members of groups within Syria who have ties to Islamic extremist groups fighting in the country's civil war. Several moderators espouse support for the Syrian White Helmets, who Disobedient Media has tied to war crimes committed by rebel groups in Aleppo and other areas of Syria. Another supports the Al Bunyan al Marsous Operations Room, a coordinated organization of rebels in Daraa, Syria. Observers have noted that members of the Al Bunyan al Marsous Operations Room include Hay’at Tahrir al Sham, who have been described by BBC News as being Al-Qaeda's latest incarnation in Syria. The subreddit has also linked to their own dedicated Telegram channel. Telegram has been reported to be a favorite medium of communication for jihadists due to its encrypted messaging system and has been criticized for hampering anti-terror units in their efforts to combat extremists.

Somehow The US Has Killed 70k ISIS Fighters - Twice As Many As It Says Exist --  In June 2014, around the time ISIS was making headlines across the world, the Wall Street Journal reported that the terror group had 4,000 fighters in Iraq. In September 2014, the CIA released an estimate claiming ISIS had between 20,000 and 31,500 fighters combined in both Iraq and Syria, including 15,000 who were foreign fighters. Almost half were foreign fighters? That’s some organic uprising taking place in Syria.   One month before the CIA’s estimate, the Syrian Observatory for Human Rights (SOHR)released an estimate of their own that placed ISIS’ membership at well over 50,000 fighters in Syria, alone (including 2 0,000 non-Syrians.) But SOHR is run by one man who owns a clothing shop in Coventry, England. He was once quoted as saying “I came to Britain the day Hafez al-Assad died, and I’ll return when Bashar al-Assad goes.” This bias is rarely reported in the corporate media, which regularly cites SOHR.Regardless of the exact numbers, the U.S.-led re-intervention into Iraq had already begun in June 2014 (before these estimates had been released.) Understandably, the total number of ISIS fighters in Iraq and Syria has fluctuated somewhat — it has both increased and decreased over time — since the U.S. began a bombing campaign in both countries that was supposedly designed to “degrade and destroy” them. But they left the terrorists’ $50 million a month oil revenue completely intact. That’ll show them. For some reason, the U.S. decided to leave this task to the Russians, who targeted ISIS’ lucrative source of revenue on America’s behalf (only for a NATO member to shoot down their jets in response).The number of ISIS fighters supposedly killed by the U.S.-led coalition has also been somewhat disputed. At the end of last year, U.K. Defense Secretary Michael Fallon estimated that the coalition had killed a whopping 25,000 fighters during the campaign. However, a senior military official told CNN at around the same time that the Pentagon’s conservative estimate was that the U.S. air campaign had killed a staggering 50,000 ISIS fighters.In its most recent published numbers, the Pentagon claims to have killed over 70,000 militants since June 2014 while only killing a mere 229 civilians. That’s an alleged hit rate of over 99 percent.  Of course, we know this to be a false estimate. I’m not just referring to the ludicrously low number of civilians killed; the idea that the U.S. killed 70,000 ISIS militants is so outlandish it begs the question: What would actually remain of a terror group that initially had 30,000 fighters, if a total of 70,000 fighters (more than double their estimated membership) were killed just for good measure?

How North Korea gets its oil from China: lifeline in question at U.N. meeting | Reuters: As the United Nations Security Council decides whether to tighten the sanctions screws on North Korea, the country's increasingly isolated government could lose a lifeline provided by state-owned China National Petroleum Corp (CNPC). For decades, the Chinese oil giant has sent small cargoes of jet fuel, diesel and gasoline from two large refineries in the northeastern city of Dalian and other nearby plants across the Yellow Sea to North Korea's western port of Nampo, five sources familiar with the business told Reuters. Nampo serves North Korea's capital, Pyongyang. CNPC also controls the export of crude oil to North Korea, an aid program that began about 40 years ago. The sources said the crude is transported through an ageing pipeline that runs from the border town of Dandong to feed North Korea's single operational oil refinery, the Ponghwa Chemical factory in Sinuiju on the other side of the Yalu river, which splits the two nations. The plant makes low-grade gasoline and diesel, the Chinese sources said. The five people outlined previously unreported details about CNPC's deals with Pyongyang and how it came to dominate that business, giving insight into the two countries' relationship and what's at stake as decades of close ties sour badly because of growing concerns about North Korea's missile programs and development of nuclear weapons. U.S. Secretary of State Rex Tillerson will press the U.N. Security Council on Friday to swiftly impose stronger sanctions in the event of further provocations by the reclusive state, including a long-range missile launch or sixth nuclear test.

China Seeks Help to Find Oil, Gas in South China Sea -- The Chinese government is looking to foreign businesses to help find oil and natural gas under the South China Sea. Last week, China’s state-operated China National Offshore Oil Corporation made an appeal for foreign help. Yet China expects to meet resistance because other countries dispute Chinese territorial claims to much of the sea. In addition, observers say any oil and gas discoveries might not be very profitable. The company said it wants to work with foreign businesses in exploring for fossil fuels in 22 areas south of the country’s coast. When combined, that represents more than 47,000 square kilometers of territory. The governments in Taiwan and Vietnam also claim those waters. Foreign oil companies are now studying the Chinese offer, which closes in September. Experts say the companies may be worried that any work they do for China could hurt their ability to work for other countries. And they say the companies may also be worried that any oil or gas they find could be claimed by China’s neighbors.