Sunday, September 13, 2015

why more than halving the rig count has not diminished the oil glut

our crude oil inventories, which normally fall during the summer months, rose for the 2nd week in a row this week, but unlike last week, where we saw the glut was driven by increase in imports, this week saw a larger drop in refinery throughput than we've seen anytime this summer....our commercial inventories of crude oil, which are watched closely by oil traders and hence influence oil prices, increased by almost 2.6 million barrels in the week ending September 4th, from 455,428,000 barrels at the end of the last week in August, to 457,998,000 in the current report, following a jump of 4.7 million barrels last week, giving us the largest increase 2 week increase in inventories in 5 months....those increases lifted our crude oil in storage to a level 27.7% higher than the 358,598,000 barrels we had stored the first reporting week in September the last year, and the highest for any September in the 80 years that such records have been kept, which had never seen the 400 million barrel level breached before this of that inventory build sent oil prices tumbling, with the near term contract for US crude oil closing the week at $44.63 a barrel, down from $46.05 a barrel last Friday...

underlying this week's inventory building was a further slowdown in refinery operations....although the Whiting Indiana refinery was restarted last week, it may not have hit full stride for this week's report, which showed that refinery inputs of crude oil averaged 16,110,000 barrels per day during the week ending September 4th, 279,000 barrels per day less than the previous week, and the 5th weekly drop in a row...over that 5 weeks, US refinery throughput of crude has dropped by nearly 6%, while our refinery utilization rate has dropped from 96.1% of capacity to 90.9% of operable capacity in the 1st week of September, the lowest refinery usage rate since April 3rd....while production of both gasoline and distillate fuel oils thus both fell, inventories of both major products rose, as our exports of gasoline fell from 835,000 barrels per day last week to 589,000 barrels per day this week, also the lowest level since April 3rd...

while both output of US wells and our imports of crude fell, neither really fell enough to impact that inventory buildup....our field production of crude oil fell from to 9,218,000 barrels per day in the week ending August 28th to 9,135,000 barrels per day in this week's report, which was almost 4.9% below the modern record production of 9,610,000 barrels per day set in the first week of June this year...nonetheless, that was still 6.3% higher than our 8,590 ,000 barrels per day production during the first week of September last year, when the growing global glut had already precipitated a drop in oil prices...meanwhile, our imports of crude oil fell by 396,000 barrels per day to 7,459,000 barrels per day during the week ending September 4th, but the weekly Petroleum Status Report (62 pp pdf) shows our 4 week average of imports still at 7.6 million barrels per day, which is now 0.5% above the same four-week period last year...

lower oil prices are apparently starting to bite, because frackers were again pulling rigs from the field last week, leading to the second week of double digit decreases in the rig count for the first time since the beginning of May...Baker Hughes reported that the total rig count fell by 16 rigs to 848 in the week ending September 11th, the largest drop since May 1st, with oil rigs down by 10 to 652 and gas rigs down by 6 to 196; that's now down from the 1592 oil rigs and 338 gas rigs that were operating in the US during the 2nd week of September last year...of those rigs shut down this week, a net 11 were horizontal rigs, 4 were directional rigs, and one was vertical, leaving the total count at 648 horizontal, down from 1342 a year ago, 81 directional, down from 217 a year ago, and 119 vertical, down from 372 a year ago...of vertical rigs idled this week, 2 were platforms in the Gulf of Mexico, leaving 29 working in the Gulf, and one each offshore of Alaska and California, for an offshore total of 31, down from 66 a year earlier...

once again, more than half of the rigs stacked this week had been operating in Texas, which saw a net of 9 rigs idled, leaving 366 in the field, down from the 905 rigs that were working Texas fields the same week last year...both the Permian basin in the west and the Eagle Ford in the southeast part of the state saw 3 rigs go, while one was also shut down in the Barnett shale of north central Texas...that left the Permian with 250 rigs, down from 566 a year ago, the Eagle Ford with 90, down from 203 a year ago, and the Barnett with 6, down from 25 a year ago....4 other major basins saw a reduction by one rig this week: the Williston of North Dakota, now with 71 rigs running, down from 194 a year earlier; the Niobrara of Colorado, down to 29 rigs from 62 a year ago, the Mississippian of Kansas, now down to 19 rigs from 77 a year ago, and the Cana Woodford of Oklahoma, which was reduced to 38 rigs this week, still up from 36 a year ago, and the only shale basin to have seen an increase in rigs since last year...other changes not accounted for by the shale basin counts included the loss of 2 offshore rigs from the Louisiana count, where the state now has 73 rigs, down from 115 a year ago, Wyoming, where the rig count was down 1 to 24 and down from 57 in the same week of 2014, Colorado, which was down 2 to 32 and down from 75 a year ago, and Alaska, which saw an additional rig this week and now has 13, up from 10 a year ago, and is the only state with a year over year increase....

Baker Hughes also released the international rig count with the regional averages for August, which showed the global rig count at 2,226, up 59 rigs from 2,167 in July but down 1,416 from the 3,642 rigs that were operating a year earlier, with most of those year over year reductions in North America...the August gain included an increase of 23 rigs in Canada, which was largely due to rig additions in late July, which boosted the August average over that of July...likewise, all other regions saw increases in their active rig averages; the Middle East netted an increase of two rigs for an average of 393 in August, which was down from 406 in August of 2014...changes in the region included Iraq, which was up 4 rigs to 48, Kuwait, which was up 2 rigs to 46, Qatar, which was up 2 rigs to 9, and Saudi Arabia, which was down 3 rigs to 120...Latin American countries added 6 rigs in August and now total 319, down from 410 a year ago; notable changes there include Columbia, up 5 rigs to 30, and Mexico, down 4 rigs to 41...the Asia-Pacific region added 8 rigs in August and at 220 are down 35 from 255 last year; that included an addition of 3 rigs in Indonesia, which now has 25, 3 more rigs in Malaysia, which is now running 9, and a reduction by 3 to 15 in Thailand...Europe saw a net increase of 1 rig to 109, down from 143 a year earlier; August changes in Europe included an addition of two rigs in the Netherlands, which now has 7, and a reduction by 4 rigs to 16 in Norway...lastly, African nations increased their August count by 2 to 96, which was still down from 125 a year earlier; Algeria, adding 2 rigs to 52, was the only nation on the continent to see a rig count change greater than 1…

when we first started tracking US rigs counts weekly in December of last year, it was because those counts were the only obvious, if imperfect, way to estimate if the extent of the environmental damage being done by the oil & gas industry was changing from week to week; ie, there are no weekly spill counts, no weekly air and water pollution measurements, no weekly count of tanker truck of the rather simplistic assumptions we made early on, as the oil rig count specifically quickly crashed from a high of 1609 in early October to half that by early April, was that we would soon see a corresponding reduction in oil output, knowing that it is the nature of the wells now being drilled for fracking is that there is an initial burst of gas or oil production in the first weeks after a well is fracked, which quickly falls off over the first couple of years, such that output of a typical shale well 2 years after the well is fracked is around 80% lower than it was in the initial months, and gradually tapers off thereafter...however, a number of minor nuances about production that we overlooked have conspired to turn this simplistic rig count to oil output calculus that we once felt was logical on its head...

first and most obviously, the rigs that were pulled out and stacked early on were those drilling in the less productive areas of the respective basins anyway, so their removal had a correspondingly minor impact on the output of the basins from which they were being pulled....then there's the delays to production resulting from the increasingly common practice of drilling multiple wells from a single pad; it's usually not until the drilling is complete on the last of those wells that the rig is taken down that the fracking begins; that meant that a large portion of the record number of wells that had been drilled in early 2014 when prices were high had not yet been fracked when prices began to fall, and a result, many operators delayed the expensive fracking, hoping for higher prices for that initial burst of output, resulting in what came to be called "the fracklog", wherein by early March over 3,000 wells had been drilled but not fracked when oil prices first fell below $50 a barrel, a count which quickly grew to more than 4,700 uncompleted wells by late addition, over the period of lower prices for oil, drillers laid off their slowest rig crews, cut costs, developed enhanced drilling and fracking procedures, such that they're now getting more wells drilled by each rig they're operating; by earlier this year, the average time to complete a well fell from 21 days to 17 days in the Eagle Ford, while drill times in the Bakken dropped from 15 days per well late last year to 13 days per well by the second quarter...more recently we've read of the introduction of walking rigs, which move around on hydraulic legs, greatly reducing the time & expense of dismantling a rig and trucking it to a nearby site...other are developing “supersize” fracking techniques, whereby multiple laterals are extended by thousands of feet more than usual to frack a much larger area from the same well; if lateral lengths can be doubled, output per well can be quadrupled...the August Drilling Productivity Report (pdf) from the EIA has complete details for the current productivity changes in 7 major basins which are being drilled horizontally, including the Marcellus and the Utica, for both oil and gas in each, based on drilling data through July and projected production through there's been quite a decoupling between the number of rigs drilling and the output of oil, something we can best illustrate with a few graphs..

the first graph below, which comes from Zero Hedge, includes the US oil rig count and US crude production over the last 30 years on the same graph; the rig count is in red and is noted by the first column of figures on the right, while our crude oil production in thousands of barrels per day is in dark blue and is shown in the farthest right column on graph...note that because EIA production figures are for the week prior to their release and that rig count figures from Baker Hughes are for the current week, the latest change in the rig count is not shown, so that the end date of both graphs reflect data as of September 4th...also note that although the rig count graph shows zero, the production figures begin at 4 million barrels per day so that the two graphs line up over the years prior to 2005...since then, we can see that the rig count has actually been relatively elevated as compared to production, with the 2009 to 2014 period representing an eight-fold increase in drilling activity which was only accompanied by a doubling of our oil output...clearly, despite all the hype accompanying the shale revolution, the ultimate production per drilling rig was much greater in the prefracking era that it was at the height of the fracking boom...

September 11 2015 rig count vs production

the second graph from this week that we found relevant comes from a widely distributed article by petrogeologist and oil market analyst Arthur Berman titled The Biggest Red Herring In U.S. Shale...the graph clearly shows oil production per drilling rig in tan, in barrels of oil per day as shown on the left margin, and oil production per well, also in barrels of oil per day, as shown on the right margin...Berman is accurately showing, with a slight degree of deception, that despite that fact that production per rig is going up (his red herring), production per well (and hence profits per well) has been declining...that production per rig would increase while the rig count in dropping should be intuitively obvious; it's a simple fraction wherein the denominator is shrinking...that production per well would shrink is what we already knew about fracking; since production is all in a rush in the early months, and tapers quickly thereafter, the only way to increase production would be to drill increasingly more wells to replace the production from those wells that are being depleted...if you look at that blue line, it appears that production per well is declining rapidly; however, if we look closely at the barrel counts on the right margin, you see they're from 110 to 135 in increments of 5; whereas the production per rig metrics on the left are in increments of 100...what the graph shows is accurate, of course, as long as you're aware of the optical distortion resulting from the different scales..but the bottom line to all this is that the rigs drilling for oil today have nothing to do with the amount of oil being produced during the same time frame, and those that are bragging that production per rig is climbing are telling you nothing more than that the rig count is falling...

September 11 2015 production.per rig, production per well


Mahoning board of elections hires attorney to defend its decision on anti-fracking proposal: The Mahoning County Board of Elections hired outside legal counsel to defend its decision to not put an anti-fracking charter amendment on Youngstown’s Nov. 3 ballot. The reason for hiring Vorys, Sater, Seymour and Pease LLP is because the board’s Aug. 26 vote conflicted with the legal opinion of the county prosecutor, who serves as the board’s attorney. “The opinion differed from what the board decided,” said Mark Munroe, board chairman and head of the county Republican Party. “Because of a conflict, we’re hiring outside legal counsel.” The board met Tuesday and declined a request from The Vindicator to vote on making the opinion, in letter form, public. “It’s subject to attorney-client privilege,” Munroe said. County Prosecutor Paul J. Gains declined to make the letter public without a vote of the board of elections. The city of Youngstown filed a complaint Aug. 28 with the Ohio Supreme Court contending the elections board acted “illegally” when it refused to put the citizen-initiative amendment on the ballot. The complaint also named Secretary of State Jon Husted

Tuppers Plains water district shares injection concerns with state - The Tuppers Plains-Chester Water District sent a letter to the Ohio Department of Natural Resources this summer expressing concerns about fracking injection wells, asking that public hearings be made mandatory for approval of such wells, and restrictions enacted on the amount of waste received. The Tuppers Plains-Chester Water District is based out of Reedsville in neighboring Meigs County, and the letter cited the DuPont C-8 contamination of water that led to 15 years of litigation against the company and around 3,500 personal injury lawsuits, the first of which comes to trial this month. “Our 13,000 customers and neighboring water systems that were contaminated by the chemical C-8 have learned the political process of large government entities and huge private corporations do not always operate in our best interest,” District Manager Donald C. Poole wrote the ODNR on June 25.

Water system raises concerns about injection wells - — Tuppers Plains-Chester Water District has raised concerns with state officials about the disposal of fracking waste in injection wells in the region. A response from the Ohio Division of Oil and Gas Resources Management maintains that injection wells are safe.  This summer, water district General Manager Donald Poole wrote a letter to James Zehringer, director of the Ohio Department of Natural Resources, outlining concerns about injection wells. The letter — which was provided to the water system’s customers in July — also was sent to the governor, Ohio Environmental Protection Agency, and the heads of other water systems in the area.  Tuppers Plains-Chester Water district’s service area covers about one-third of Athens County, including Coolville, and about two-thirds of Meigs County. In his letter, Poole asks that public hearings be required for all injection wells, that limits be put on the amount of material that can be injected, that groundwater monitoring wells around all injection wells be required and that fees be placed on all waste disposed of in injection wells. “Let us be the most expensive dumping ground, not the cheapest,” Poole wrote, arguing that current rules provide an economic inventive for oil and gas well waste to be trucked into Ohio.

Marcellus and Utica shale: Possibly biggest play in US? - — The Utica and Marcellus shale plays are considered to be young oil and gas plays, but there is little doubt that the plays’ production is significant. As of June 15, according to the U.S. Energy Information Agency, the Marcellus shale play produced 16.48 Bcf per day, which makes it the largest gas-producing area in the country. The Eagle Ford was behind the Marcellus shale with 7.18 Bcf. The Utica was seventh on the list of eight with a reported production of 2.60 Bcf per day. Brackett said it is clear the Marcellus and Utica are going to grow to be perhaps the largest producing plays. The U.S. EIA reported the Marcellus and Utica is responsible for 85 percent of the gas production since 2012. “The Appalachian basin with the Marcellus and Utica shale is going to be center of the shale production here in the United States, at least the rest of this century and for a long time to come,”  Some challenges are unique to the Appalachian region. Operators are unfamiliar with the Appalachian region and the residents of the Appalachian region are not familiar with how the oil and gas industry works. Another challenge has been educating people living in the Appalachian region about the oil and gas industry. This meant launching a constant public relations campaign, from the start of leasing to the construction of pipelines. Landowners and residents have had to learn how the leasing process works, what dangers there are to drilling and fracking, and companies have had to earn public support for pipeline construction.

How sound are Pennsylvania's oil and gas wells? ---Hundreds of oil and gas well owners failed to submit required reports this year that are meant to document whether Pennsylvania’s active wells are structurally sound or showing signs of leaks and decay. The roughly 450 well owners who were sent violation notices for the missing reports by the Department of Environmental Protection represent a small fraction of the roughly 5,600 oil and gas operators with active wells in the state. But some types of well owners had a dismal compliance rate, especially companies that keep old wells pumping but rarely drill new ones and homeowners and small businesses that have wells for use only on their property, DEP officials said. This year was the first time operators had to submit the annual reports, which detail the results of their quarterly inspections of all of their wells for signs of defects or excess pressure. The reports are due each year on Feb. 15. The inspection and reporting requirement was added to Pennsylvania’s oil and gas regulations in 2011 so the state could ensure that every well is routinely monitored even if DEP oil and gas inspectors can’t reach every one every year. But the state delayed implementing the mechanical integrity assessments for years as regulators developed methods for collecting the information that would be practical for even the least sophisticated operators or those with the largest inventories of wells. DEP also wanted to receive as many of the results as possible through electronic forms that could easily be analyzed.

Local Ordinance Blocks Frackquake Injection Well! --And court upholds it. Surprise, surprise. Frackers will have to go make frackquakes somewhere else. Attorney John Smith: “The DEP should continue to recognize its obligation to respect local ordinances that comply with statutory and constitutional directives that serve to protect local residents from negative environmental impacts, and the fact they’re acknowledging local zoning is an essential part of considering these permits is how it should be.“ The Pennsylvania Department of Environmental Protection rejected a permit in Indiana County for Pennsylvania General Energy Co. to build a hydraulic fracturing wastewater injection well Aug. 12, citing the authority of a local ordinance banning frack filth injection wells. Thomas Linzey, executive director for the Community Environmental Legal Defense Fund, said it was an unprecedented step for the DEP to take in recognizing Grant Township’s local ordinances as having authority in local affairs.PGE Co. sued Grant Township in June 2014 to overturn the community’s “Bill of Rights” ordinance which, among other things, bans frackquake injection wells.  The Legal Defense Fund helped draft those ordinances. PGE argued its corporate constitutional rights were violated and is seeking reimbursed attorneys’ fees and damages from Grant Township. The rejection letter from DEP said “as part of its permit application review, the department has an obligation to consider applicable local ordinances related to environmental protection and the commonwealth’s public natural resources.”

Shale gas production in retreat amid low prices, shortage of pipelines - Pennsylvania shale gas production is starting to show the effects of a partial retreat by drillers struggling with low prices and a shortage of pipelines.  The 2.25 trillion cubic feet of natural gas that companies pulled from the Marcellus and other shale formations beneath Pennsylvania during the first six months of the year was about 5.6 percent higher than the last six months of 2014, the most recent state data show. That compares to double-digit increases for every previous six-month reporting period dating to 2009.  Statewide production posted monthly drops in April, May and June, falling to nearly 360 billion cubic feet from more than 395 billion cubic feet in March. The state only required monthly reports from producers starting this year.  The record growth that producers generated in the Marcellus and other shale plays during the past seven years fueled a glut of supply that started pushing prices to three-year lows this year. Without enough pipelines to carry the gas to higher-demand markets, prices as low as $1 per thousand cubic feet in Pennsylvania could stick around for a few more years.  Producers first cut their capital budgets for the year, dialing back drilling programs. State Department of Environmental Protection records show companies drilled 42 percent fewer shale wells during the first half of the year compared to the same period last year. During the past few months, companies focused on the northeast corner of the shale — including Cabot Oil & Gas and Seneca Resources — announced they would curtail production, restricting or shutting down wells if local prices or space on pipelines were too low.  “Curtailment may mean an entire section of wells is shut in, meaning no gas is flowing,” said Rob Boulware, a spokesman for Seneca, whose Pennsylvania shale production was down 27 percent compared to the second half of 2014.

Study: Marcellus shale industry has 'modest impact' on creating local jobs -- Up to half of the drilling jobs associated with the Marcellus shale industry don’t go to local residents, and the industry has had only “modest impact” on overall employment numbers in the state, a new study commissioned by a Penn State University economist suggests. Tim Kelsey studied tax data from the state Department of Revenue from 2002 to 2011, the last year the data was available. He studied the tax data in an attempt to pin down exactly where Marcellus shale workers lived, and what he found was that many drilling jobs did not go to people already living in counties where drilling took place. Kelsey cautioned that doesn’t mean the jobs are going to outsiders from far-away states. It does mean, though, that the gas drilling industry isn’t having as big an impact locally as some might suggest, he said. The numbers in his study show a discrepancy to back up his claim, Kelsey said. Based on his data, Kelsey said Marcellus development “increased the aggregate employment of local residents between 7,346 to 9,602 jobs” in the average Pennsylvania county, despite Bureau of Labor Statistics information that predicted between 18,761 and 20,385 jobs in the average county. Furthermore, Kelsey said in an interview, those jobs that are created aren’t necessarily going to local workers. “We know a lot of workers are from non-Marcellus counties who commute into work, as well as the stereotype of people coming from Texas and Oklahoma,” Kelsey said. “And those folks make up about half the jobs.”

Most Comprehensive Appalachian Region Study Finds Water Quality Issues Long Before Fracking --A new study, which can boast of having one of the most comprehensive water quality datasets in the Appalachian basin prior to Marcellus and Utica shale development, was recently released in the journal, Applied Geochemistry. The study, led by Don Siegel of Syracuse University, analyzed over 21,000 samples of groundwater collected by third party contractors from individual domestic or stock water-supply wells before Chesapeake Energy Corporation drilled nearby Marcellus and Utica shale oil and gas wells. According to the study’s summary: “Our comparison of these results to historical groundwater data from NE Pennsylvania, which pre-dates most unconventional shale gas development, shows that the recent pre-drilling geochemical data is similar to historical data. We see no broad changes in variability of chemical quality in this large dataset to suggest any unusual salinization caused by possible release of produced waters from oil and gas operations, even after thousands of gas wells have been drilled among tens of thousands of domestic wells within the two areas studied.” The study falls in line with previous studies from the United States Geological Survey (USGS), which also found major ions and metals in exceedance of federal drinking water standards in a majority of private water wells in Pennsylvania, West Virginia and Ohio prior to development.  Of course, it also bolsters the findings of the Environmental Protection Agency’s (EPA) comprehensive five year study, which found that “hydraulic fracturing activities have not led to widespread, systemic impacts to drinking water resources.” Due to a lack of water well standards in Pennsylvania, residents have always had water quality issues throughout the Commonwealth. Now, because of regulatory framework for oil and gas development, operators are required to take a baseline sample of water wells near drilling operations.

Study: O&G not a threat to Marcellus and Utica water quality - Study: O&G not a threat to Marcel: For people living near oil and gas development in the Marcellus and Utica formations, the safety and quality of their drinking water is understandably a major concern. Though some residents may worry about oil, gas and their byproducts contaminating groundwater, Applied Geochemistry recently released a study that may comfort neighbors of the oil and gas industry.  Energy InDepth reports the study, led by Don Siegel of Syracuse University, analyzed more than 21,000 groundwater samples collected from well by third parties before Chesapeake Energy Company began drilling the formations. The summary of the study points to current chemical levels in northeastern Pennsylvania that are similar to “historical data”: We see no broad changes in variability of chemical quality in this large dataset to suggest any unusual salinization caused by possible release of produced waters from oil and gas operations, even after thousands of gas wells have been drilled among tens of thousands of domestic wells within the two areas studied. These findings reiterate those of the similar studies from both the U.S. Geological Survey and Environmental Protection Agency, which found not only that most private well water contained ion and metal levels that exceed federal drinking water standards before shale development, but also that fracking had not caused ‘widespread, systematic impacts’ to sources of drinking water.” However, the new study challenges the findings of a Duke University study (Warner et al 2012), which sourced the metal-rich brine in the area’s water to oil and gas development. “The saline water is naturally-occurring connate brine or salt water which has not been flushed away by circulating meteoric water,” writes Bert Smith, an author of the new study. “Ratherthan vertical migration of salt water from deep strata such as the Marcellus shale as suggested by Warner et al (2012).”

Giving the Frackers the Finger (Lakes) - Let’s amend the famous line from Joni Mitchell’s “Yellow Taxi” to fit this moment in the Finger Lakes region of New York State. There, Big Energy seems determined to turn paradise, if not into a parking lot, then into a massive storage area for fracked natural gas. But there’s one way in which that song doesn’t quite match reality. Mitchell famously wrote, “Don’t it always seem to go that you don’t know what you’ve got till it’s gone.” As part of a growing global struggle between Big Energy and a movement focused on creating a fossil-fuel-free future, however, the residents of the Finger Lakes seem to know just what they’ve got and they’re determined not to let it go. As a result, a local struggle against a corporation determined to bring in those fracked fuels catches a changing mood not just in the United States but across the world when it comes to protecting the planet, one place at a time, if necessary. .There’s a battle brewing between the burgeoning clean-energy future embraced by this region and the dirty energy sources on which this planet has been running since the Industrial Revolution.  Over the last six years,Crestwood Midstream Partners, a Texas-based corporation, has been pushing to build a gas storage and transportation hub for the entire northeastern United States at Seneca Lake.  The company’s statements boast about settingup shop “atop the Marcellus Shale play,” a hydraulic fracturing, or fracking, hotspot.  It plans to connect pipelines that will transmit two kinds of fracked gas — methane and liquefied petroleum gas (LPG) — probably from areas of the Marcellus Shale in Pennsylvania, Ohio, and West Virginia.  These will be stockpiled in long-abandoned salt caverns, the remnants of a nineteenth-century salt-mining industry that capitalized on the remains of a 300-million-year-old ocean that once was here.

Armed with proof of oil shipments, activists say they will press the issue - CSX Transportation said Thursday it still moves crude oil by train through Maryland via downtown Baltimore occasionally, but not as many as the five 1 million-gallon trains a week it estimated in documents released this week by the state. Environmental groups and community activists said they hope the new disclosure about trains carrying the explosive crude though the city will spark public pressure and lead officials to act. The state released documents on Wednesday in which CSX estimated it moves up to five trains a week, each carrying at least 1 million gallons of the volatile crude oil, through Baltimore City, as well as through eight Maryland counties. The information, disclosed after CSX and Norfolk Southern lost a court battle to keep it private, is outdated, said Rob Doolittle, a spokesman for Jacksonville, Fla.-based CSX. The railroad has not moved trains carrying 1 million gallons of so-called Bakken crude — the volume that triggers federal reporting and disclosure requirements — through the Howard Street Tunnel since the third quarter of 2014, he said. Trains carrying less than 1 million gallons continue to travel that route “on occasion,” he confirmed. He declined to be more specific about the amounts or frequency. It takes roughly 35 tank cars to carry a million gallons of crude.

Natural-gas pipeline to Florida draws environmental concerns - A Florida environmental group has joined the opposition against a $3 billion natural-gas pipeline that would extend from Alabama through Georgia and into Central Florida. The Sabal Trail Pipeline has drawn opposition from a Florida group affiliated with WWALS Watershed Coalition Inc., which is based in Georgia. A chief concern is that the pipeline could impact Florida waterways and the drinking-water supply, said John S. Quarterman, director of the Florida and Georgia WWALS groups. “It’s impacting the most vulnerable area of the Floridan Aquifer, and that whole area indeed extends down to Orlando,” said Quarterman said Tuesday. Environmental opponents have already issued pipeline concerns to the Florida Department of Environmental Protection and the federal government. A state administrative-hearing officer will oversee the WWAL group’s complaint, although a date hasn’t been set. On Friday, the federal Energy Regulatory Commission issued a draft environmental-impact statement on the project. Proposed in 2013, the pipeline would transport fuel for Florida Power & Light and Duke Energy Florida. Together with Duke, Spectra Energy and NextEra Energy Inc. are seeking federal permits by early next year, with construction expected to start on the pipeline in a year. As proposed, the pipeline would start operating in 2017.

Enbridge’s Aging Tar Sands Pipelines Beneath Great Lakes Are ‘A Ticking Time Bomb’ -- The Straits of Mackinac is a narrow waterway that separates Michigan’s lower peninsula from its upper peninsula. The straights connect two of the Great Lakes: Lake Huron and Lake Michigan. But underneath this iconic part of the Great Lakes are two 62-year old pipelines. The pipelines have never been replaced, despite the well-documented risk of a rupture. “If just one of the pipelines ruptured, it would result in a spill of 1.5 million gallons of oil—and that’s if Enbridge, the company that owns them, is able to fix the pipeline immediately,” says Motherboard. “I can’t imagine another place in the Great Lakes where it’d be more devastating to have an oil spill, University of Michigan research scientist Dave Schwab told Motherboard.  Enbridge does not have a good record when it comes to spills either. It’s responsible for more than 800 spills between 1999 and 2010, totaling 6.8 million gallons of spilled oil. And in 2010, it spilled more than 800,000 gallons into the Kalamazoo River in Michigan—creating the biggest inland oil spill in the country’s history. It did not receive as much national attention because the country was fixated on another oil spill: the BP oil spill in the Gulf of Mexico. Enbridge maintains that the pipeline, which was only supposed to last 50 years, is still in working order. Others beg to differ. After nearly two years of pressing Enbridge and pipeline regulators to release information about the integrity of the pipelines, the National Wildlife Federation was finally fed up and conducted its own diving expedition to survey them in 2013. Their footage revealed “some original supports broken away—indicating the presence of corrosion—and some sections of the suspended pipelines covered in large piles of unknown debris.” Last month, Motherboard correspondent Spencer Chumbley went to Michigan to investigate. Watch here to find out what he discovered:

AP Exclusive: Fracking Boom Responsible for 175 Million Gallons of Toxic Wastewater Spilled Since 2009 -- Among the litany of risks posed by the continued extraction and use of fossil fuels, an Associated Press analysis published Tuesday exposes yet another harmful side effect of the oil and gas drilling boom: an uptick in toxic wastewater spills. According to data obtained from leading oil- and gas-producing states, “more than 175 million gallons of wastewater spilled from 2009 to 2014 in incidents involving ruptured pipes, overflowing storage tanks and other mishaps or even deliberate dumping,” Associated Press reports, tainting agricultural land, poisoning drinking water and sparking the mass die-off of plant and animal life. Most of the incidents involved the spill of fracking wastewater, which is a combination of underground brine mixed with a slurry of undisclosed chemicals. As the story notes, “A big reason why there are so many spills is the sheer volume of wastewater” produced, which according an organization of state groundwater agencies, amounts to roughly 10 barrels for every barrel of oil or more than 840 billion gallons a year. The report details a sampling of incidents, which help illustrate the scope of the problem. In one instance, a roughly 1 million gallon spill in North Dakota in 2006 caused a “massive die-off of fish, turtles and plants in the Yellowstone River and a tributary.” In another case, a decades-long seepage of toxic brine onto Montana’s Fort Peck Indian Reservation polluted a river, private wells and the municipal water system, making the water “undrinkable.” What’s more, the amount of toxic byproduct spilled along ranch land, streams and forests has grown each year since the so-called fracking boom began. “In 2009, there were 2,470 reported spills in the 11 states; by 2014, the total was 4,643. The amount of wastewater spilled doubled from 21.1 million gallons in 2009 to 43 million in 2013 before dipping to 33.5 million last year"

States rarely punish companies for oil wastewater spills -— In April 2013, a malfunctioning oil well in the countryside north of Oklahoma City caused storage tanks to overflow, sending 42,000 gallons of briny wastewater hurtling over a dike, across a wheat field and into a farm pond. State regulators ordered the oil company to clean up as much of the spill as possible and repair the site. But they didn’t impose fines or other punishment against Moore Petroleum Investment Corp., a tiny company in Norman that operates only a few wells. Regardless of the damage done, the no-penalty policy is standard practice across the country after oilfield wastewater accidents by companies of all sizes. Spills by the tens of thousands have denuded farm and ranch lands and polluted waters in oil-producing areas for decades, yet only a small minority resulted in discipline. Regulators’ approach toward oil spills is largely the same. “We certainly believe there’s a time and a place for that hammer, but we want to be very judicious in its use,” said Matt Skinner, spokesman for the Oklahoma Corporation Commission, which oversees the industry in that state. Moore Petroleum promptly arranged cleanup of its spill, which was accidental, he said. Environmental activists and groups representing landowners contend the lack of punishment helps explain why the industry hasn’t done more to prevent spills, and shows regulators’ deference to oil and gas producers. “It’s almost a coddling relationship,” said Jill Morrison of the Powder River Basin Resource Council, an environmental advocacy group in Wyoming, adding that it takes large court judgments or settlements for companies to mend their ways. “The industry looks at spills as a cost of doing business.”

We were a small Texas town that banned fracking — then the oil industry stepped in - The issue of local control has its roots in the emergence of modern cities and their relationship with centralized organs of power like the crown. In the 17th century, Thomas Hobbes argued that we must have a Leviathan, a single ruler, to quash disagreements and ensure peace. . These are the origins of contemporary talk by the industry and our legislators in Austin about the need for “regulatory certainty” and the supposed ills of a “patchwork of local regulations.” I couldn’t help thinking of Austin as the Leviathan – ironic given all the lip service paid down there to small government. From the perspective of the state, Denton (or any other city on the shale) is not a community – it’s a node on an energy network.  Soon there were about 20 protesters on site holding banners and signs, breaking out in spontaneous chants. There must have been at least eight police officers there too. A few of them started issuing verbal warnings that we were trespassing and needed to vacate the premises. Other officers were talking through the window of a pickup truck with its driver who had stopped in front of our seated bodies. Two large tanker trucks had pulled up behind him and were parked on Nail Road, which runs alongside the entrance gate to the frack site.   The chief of police, Lee Howell, is a friend of my family and he briefly checked in on us. I thanked him for the way his team was handling the situation and assured him our intentions were peaceful. I would later learn he had been texting my wife, Amber, from his position at the southern police checkpoint on Nail Road. He let her know I was all right and even apologized for the fact that it appeared he was going to have to arrest me.

Oil bust -- The number of drilling rigs working in the Eagle Ford dropped by half in the past year, from 203 to 93. Across the country, more than 1,000 drilling rigs have been stacked. McMullen County pumped 2.7 million barrels of oil in June, down from 3.6 million barrels the same month last year.DeWitt County’s total property value, much of it based on oil and gas wealth, fell by $1.15 billion this year, down 16 percent.The Eagle Ford’s biggest oil producers have issued a series of gloomy announcements. Houston-based EOG Resources made just $5.3 million in the second quarter, down 99 percent from the same period last year. ConocoPhillips last week said it would lay off 10 percent of its workforce. Marathon Oil Corp. posted a $386 million net income loss for the second quarter. Dennis Elam, associate professor of accounting at Texas A&M University-San Antonio, said the smaller, more overleveraged shale companies are drilling wells just to pay debt. “They’re chasing the water right down the drain,” he said. South Texans track other economic measures — traffic jams on rural roads or the advertised prices for hotel rooms in the region, now as low as $40.A few years ago, DeWitt County Sheriff Jode Zavesky lost seven employees in three weeks to the oil field. The police academy in Victoria had to cancel classes because everyone was going to work in the oil field instead. “We’ve got great benefits,” Zavesky said. “But a young guy can’t buy diapers on great health insurance.” Now, Zavesky has hired some of his old deputies back and said the police academy has seen a bump in enrollment.He’s also seen an uptick in oil field crime — the theft of tools from work sites and people stripping copper from the drilling rigs parked along the side of the road.

New Mexico AG calls on feds to address natural gas waste — New Mexico’s attorney general is calling on the federal government to move quickly in adopting new rules to curb the waste of natural gas and the resulting loss of millions of dollars in royalties that could benefit education and other public programs. Attorney General Hector Balderas sent a letter to Interior Secretary Sally Jewell this week, saying New Mexico has lost nearly $43 million in royalties since 2009 because of leaks and the venting and flaring of gas wells on federal lands. Balderas says the technology is available and both industry and states stand to benefit. The Bureau of Land Management, which oversees oil and gas development on federal and Indian lands, has indicated that a proposed rule to address the issue will be released later this year.

Oil boom a loser for North Dakota cities, counties, study finds — While the massive Bakken oil boom drew hordes of job seekers and international attention to the remote prairies of North Dakota and Montana in recent years, it’s turned into a money loser for most cities and counties in the region. Crime in Dunn County, N.D., in the heart of the nation’s oil boom, skyrocketed 60 percent in just three years, and the road maintenance budget soared from $1.5 million to $25 million. The local government couldn’t keep up, with demand for services outpacing the growth in tax revenue by as much as 40 percent. The problem continues as the drop in oil prices in the past year means increasingly less money for the county to spend on projects — while drilling, the truck traffic that eats up the roads, and demand for community services haven’t stopped. “The gap between revenues and needs is still fairly large,” Daryl Dukart, a Dunn County commissioner, said in an interview. “It will take many years to balance out.” Dunn County is far from alone. Analysis from researchers at Duke University found that “most local governments in North Dakota and Montana’s Bakken region have experienced net negative fiscal effects” from the shale drilling boom. “Because of the very rural nature of North Dakota and Eastern Montana, and the very large scale of the activity that’s been taking place, population growth has essentially outstripped local government’s ability to provide services,” .

Again? Continental Resources cuts budget, Bakken rig count -- Continental Resources, North Dakota’s second largest oil producer, announced that it will be cutting its budget for 2015 yet again amidst the persisting slump in oil prices. However, the company does anticipate continued production growth. As reported by Reuters, last year Continental CEO Harold Hamm cancelled all of the company’s oil hedges. He called Saudi Arabia, the de facto leader of OPEC, a “toothless tiger” and placed his bets on an oil price rebound. Alas, oil prices have yet to climb significantly, which has spurred thousands of layoffs as well as budget reductions across the industry. Continental’s goal for the remainder of the year is to save up to $350 million by reducing its North Dakota rig count from 10 to eight and temporarily halting the completion of most wells. In a statement, Hamm said, “We are reducing capital expenditures to protect our balance sheet and to preserve the value of our world-class assets until commodity prices improve.”  For 2015, the company plans to spend between $2.35 billion and $2.4 billion, compared to the previously forecast $2.7 billion. Continental Chief Financial Officer John Hart said, “We believe it is in the interest of shareholders to defer new production growth until we see stronger commodity prices.” The goal is to not spend more than the company takes in, but executives said oil prices would need to be above the $50 per barrel for this to happen. Hart added, “Obviously we are in a dynamic environment, and our outlook could change.”Although the budget has been reduced further, Continental anticipates that its output will climb between 19 and 23 percent this year, thanks in part to increases in efficiencies and the use of new technology. The company now projects its output for 2015 to be between 200,000 and 215,000 barrels of oil equivalent per day (boe/d). Previous projections had the low end of its production guidance set at 210,000 boe/d, but because of delayed completions, that figure was reduced.

Pipe staged ahead of permits for proposed ND oil pipeline — Mountainous piles of steel pipe are being staged across four states in anticipation of building the biggest-capacity pipeline proposed to date to move crude from North Dakota’s prolific oil patch. But stockpiling the pipe is a gamble for the Dallas-based Energy Transfer Partners’ Dakota Access Pipeline, a $3.8 billion, 1,130-mile project that still needs approval from regulators in North Dakota, South Dakota, Iowa and Illinois. “What the company does is at their own risk,” said Julie Fedorchak, chairwoman of the North Dakota Public Service Commission. The three-member panel has signaled its approval of the company’s project in North Dakota, the pipeline’s longest leg, but Fedorchak said a final decision is several weeks away. If approved, the Dakota Access Pipeline would move at least 450,000 barrels of North Dakota crude daily through South Dakota and Iowa to an existing pipeline in Patoka, Illinois, where shippers can access Midwest and Gulf Coast markets. Energy Transfer Partners announced the project last year, just days after North Dakota Gov. Jack Dalrymple urged industry and government officials to build more pipelines to keep pace with the state’s oil production. He said doing so will reduce truck and oil train traffic, curb natural gas flaring and create more markets for the state’s oil and gas.Energy Transfer Partners spokeswoman Vicki Granado said Thursday the company is optimistic the necessary permits will be obtained in all states, with construction expected to start late this year or early 2016. Granado said so far Energy Transfer Partners has acquired 72 percent of the easements needed along the route, which crosses 50 counties in the four states. The company has said it would use the eminent domain process to acquire other easements if agreements with landowners can’t be reached voluntarily.

Energy Pipeline Boom Ebbs - WSJ: Falling U.S. oil production and low crude prices are casting a shadow over one of the bigger energy-infrastructure building sprees: pipeline construction. The shale boom that began in 2008 created a huge need for new pipelines in places like North Dakota and West Texas—but many of those lines now have been built. Meanwhile, oil output has finally started to decline, according to federal estimates, in the wake of a 50% drop in the price of crude. “It’s hard for us to paint a scenario where, at least for the foreseeable future, any additional long-haul pipelines are needed,”  A slowdown would be bad news for investors who bought pipeline partnerships that pay out most of their available cash in dividend-like payments. Investor pressure to keep those distributions growing means that these companies are constantly on the prowl for new sources of income—which is harder to find without new projects. “If you’re structured to grow and growth opportunities are in short supply, something’s got to give,” Between 2009 and 2014, U.S. companies added nearly 14,000 miles of crude-oil pipeline, a 26% increase. The stalled Keystone XL Pipeline project, which would move Canadian oil roughly 2,000 miles to Texas, has become less pressing since it was first proposed.  Not everyone agrees that the pipeline-building party is over. In some pockets of the country, more are still needed: New England, for example, doesn’t have enough access to nearby natural-gas fields to run its power plants. And in the crowded Permian Basin area of Texas, some companies continue to build. But any hint of a slowdown can send pipeline stocks tumbling.

There will be blood & oil TV shows -- by Izabella Kaminska - In our Christmas podcast and this post, we warned of the eery similarities between the oil market of today and the oil market of JR Ewing and Blake Carrington in the 1980s. We even predicted that if history tells us anything we might soon be blessed with a modern equivalent of a Dynasty and Dallas TV series, something along the lines of “North Dakota Millionaires”. Well. It’s happening.  Via John Kemp’s energy note on Wednesday:  How do you know the oil industry is turning from boom to bust? The first episodes of “Dallas” were shown in 1978 as oil prices were climbing to their 1980 peak at $100 per barrel in real terms, but most of the series were aired in the 1980s, in time for the spectacular bust of the Texas oil industry. Now comes “Blood and Oil” featuring the oil boom in North Dakota. For those of you in the U.S., the series premieres on September 27. Wikipedia has some good background on the show’s gestation …

Company wants to expand energy project on Columbia River — A Houston-based energy company has unveiled plans to expand its proposed energy project along the Columbia River in Longview. In addition to an $800 million proposed oil refinery, Waterside Energy says it also wants to build a $450 million liquefied petroleum gas on private property. The Daily News reports that about one train a day would bring propane and butane from Canada and North Dakota to the terminal. The facility could receive up to 75,000 barrels per day. The company says the projects together will create 700 construction jobs and 180 jobs after construction. The proposed oil refinery would process 45,000 barrels a day, including 30,000 barrels of crude oil and 15,000 barrels of seed oil and used cooking oil. Most of that product will be sold into the greater Portland market. Environmental groups have raised concerns about potential train derailments and other risks.

Earthquake and Tsunami Risks Ignored at Proposed LNG Facility on Oregon Coast - The most shocking fact about earthquake and tsunami risks on the coast of Oregon is their inevitability. We buy fire insurance—spending good money though our house is unlikely to burn. Meanwhile, the geologic record indicates beyond scientific doubt that a major tremor and Fukushima-style tidal wave is due. And it’s going to be the big one. The really big one—many times greater than the infamous 1906 San Francisco disaster. All credible science indicates that a major event approaching or exceeding magnitude 9 at Coos Bay, on the coast of Oregon, has a return cycle of 243 years. The last one was 315 years ago. We’re not just due, we’re overdue. As an Oregonian who lives in the danger zone, I have to say that denial is our most common modus operandi. We hope it won’t happen. But taking a personal risk, with knowledge of the consequences, is one thing and taking a public gamble by forcing the entire community and region to be at risk is quite another. That’s what’s happening at Jordan Cove just north of Coos Bay. Three years ago the State Department of Geology and Mineral Industries provided maps to the county that clearly define the area of the LNG proposal as a “hazard” zone. Yet planning for the facility proceeds on a path greased by the county and the Federal Energy Regulatory Commission. The inevitable earthquake and tsunami will shatter and pound at full force directly on the LNG site with its tanks, tankers and pipelines loaded with one of the most explosive and flammable substances known.

These Popular Fruit and Veggie Brands May be Grown With Oil Wastewater - Mother Jones: Was your California orange irrigated with wastewater from oil wells? Quite possibly yes. Under a 20-year-old water recycling program, wastewater that is generated as a byproduct from oil extraction is treated and sold to some 90 Southern California landowners—including one with certified organic operations—which use it to grow crops such as citrus, almonds, apples, peaches, grapes, and blueberries sold in major grocery chains around the country.As California's epic drought wears on, Southern California farms are using an increasing amount of oil wastewater. In 2014, oil companies such as Chevron provided half the water that went to the 45,000 acres of farmland in Kern County's Cawelo Water District, up from about 35 percent before the start of the drought in 2011. And California Resources Corp., the state's largest oil company, recently announced plans to quadruple the amount of water it sells to farmers. Another reason for that increase is tighter rules around oil wastewater disposal. Though oil companies usually get rid of wastewater by injecting it back underground, the practice has come under increased scrutiny in recent months after regulators admitted that injections occurred near aquifers that supply drinking water. Environmental groups have sued the state to stop the practice at 2,500 sites considered most sensitive. Water officials praise the practice of using oil wastewater on farms as a model for water conservation at a time when California needs every drop, but there are unanswered questions about its safety. The State Water Resources Control Board requires periodic testing of oilfield water that is used for irrigation but has not set limits for many contaminants. Recent tests of irrigation water supplied by Chevron, for instance, turned up benzene, a carcinogen, at higher concentrations than what is allowed in California drinking water. The state has not set a standard for benzene in irrigation water.

Notes from Underground: Out of Our Sight, Out of Their Minds - Appropriate – is it not? – that the word “underground” carries connotations of secrecy, subversion, and conspiracy. In the context of fossil fuel production and transportation, underground is home to a number of activities about which the public has a dire need to be well informed. Instead, we remain largely misinformed, or not informed at all. The focus of Notes from Underground will be issues surrounding the use of pipelines and hydraulic fracturing (“fracking”). This first post will provide a foundational overview of the problems associated with fracking and pipeline use, referencing some relevant events of the recent past.Both fracking and pipeline use take place out of sight of critics, regulators, and local populations. Hidden there under our feet, problems and dangers associated with fracking and pipelines can be difficult to spot, or easy to conceal (up to a point — see here and here, for example). The potential difficulty of timely detection is only one of the dangers posed by a pipeline leak or a fracking mishap. When there is an observed accident, there may be obvious consequences, such as contamination of water or agricultural lands. There may also be consequences that are not clear or predictable, such as long-term health and environmental impacts. Then there is the difficulty of ascribing liability, as proving knowledge of underground occurrences is naturally challenging. These issues will recur as themes throughout these posts.

Walking Oil Rigs Spur Cheaper, Quicker Drilling in Supply Glut - Have you ever seen an oil rig walk? Some of the newest rigs can travel hundreds of yards to the next well under their own power, lurching along like 150-foot-tall robots on hydraulic legs that raise the equipment five inches at a time, nudging forward at about a foot per minute. While that sounds slow, it is faster and cheaper than dismantling a rig and trucking the parts to a new site nearby. More efficient drilling rigs that cost a third less than just a year earlier are changing the face of the U.S. shale industry, helping boost per-rig output in the four largest fields by at least 40 percent since the crude price plunge began in 2014. While helping producers pump more oil, the new rigs have a downside.   Producers “are being incentivized to continue drilling to keep cash coming in the door because costs have come down so much,” . “Even though the rig count is down by half, you can do more with the half that’s still working.” Even though the number of rigs has dropped by more than half since prices began falling in June of last year, U.S. output is down just 3.3 percent from a four-decade high. The rigs aren’t the only factors increasing efficiency in U.S. oil fields. Over the past few years, service companies such as Schlumberger Ltd. and Halliburton Co. have also been crafting more efficient systems to complete wells, including the use of 3-D seismic imaging that can track where cracks are going in the oil-soaked rock underground. The newest rigs, though, are making a substantial difference at a time when producers, historically heavy users of debt to fund exploration, need to keep cash flowing as prices remain mired below $50 a barrel.

US shale industry braced for bankruptcies - The world may run on oil, but the oil industry runs on capital, and for US shale producers that capital is starting to dry up. Earlier in the year it was still relatively easy for US exploration and production companies to raise capital by selling debt or equities, in spite of last year’s oil price crash caused by a global glut. Now those sales have slowed sharply, and the financial strain on the industry is growing. The next turn of the screw is approaching, in the shape of another round of redeterminations of “borrowing bases”: the valuations of companies’ oil and gas reserves used by banks to secure their lending. The shale industry, which has been responsible for rapid growth in US oil production since 2009, is not about to die. There are plenty of strong companies that have healthy balance sheets, low costs, or both, and they should be able to ride out the downturn. But there are very wide differences in resilience between companies. Those with high costs or high debts, or both, face a turbulent future. “In retrospect, easy money and a difficult time for finding the right thing to invest in led to an overshoot in US [oil] production growth,” . “Companies that should never have been brought to life were brought to life.” Now that overshoot is heading for a correction. Analysts expect a wave of asset deals, acquisitions and corporate bankruptcies, as weaker companies struggle to avoid collapse, not always successfully. Already 16 US oil production companies have defaulted this year, according to Standard & Poor’s, the rating agency. The biggest failure has been Samson Resources, which was bought by a consortium led by KKR in 2011 for $7.2bn, and said last month it intended to seek bankruptcy protection in September. There are eight oil producers with credit ratings of triple-C or lower, meaning that “they’ve got about a year or less before they burn out of cash”. The next hurdles facing many of those companies will be their borrowing base redeterminations, which typically take effect on October 1. The previous round in March and April was less brutal for the companies than some had feared. This one is likely to be significantly tougher, draining liquidity away from struggling companies.

US shale oil industry hit by $30bn outflows - US shale producers reported a cash outflow of more than $30bn in the first half of the year, in a sign of the challenges facing the US’s once-booming industry as the slump in oil prices begins to take effect. The shortfall points to a rise in bankruptcies and restructurings in the US shale oil industry, which has expanded rapidly in the past seven years but has never covered its capital expenditure from its cash flow. Capital spending by listed US independent oil and gas companies exceeded their cash from operations by about $32bn in the six months to June, approaching the deficit of $37.7bn reported for the whole of 2014, according to data from Factset, an information service. US oil production fell in May and June, according to the US Energy Information Administration, and some analysts expect it to continue falling as financial constraints limit companies’ ability to drill and complete new wells. Companies have sold shares and assets and borrowed cash to increase production and add to their reserves. The aggregate net debt of US oil and gas production companies more than doubled from $81bn at the end of 2010 to $169bn by this June, according to Factset.  “The capital markets have been so strong and so open for these companies that a lot of them were able to raise a lot of debt.” Capital markets have remained open for US oil and gas companies despite the crude price more than halving in the past year. However, there are now signs that the flow of capital is slowing. US exploration and production companies sold $10.8bn of shares in the first quarter of the year, but that dropped to $3.7bn in the second quarter and under $1bn in July and August, according to Dealogic. Similarly, those companies were selling an average of $6.5bn worth of bonds every month in the first half of the year, but the total for July and August was just $1.7bn. The next hurdle facing many US oil companies is the resetting of their borrowing base: the valuation of their oil and gas reserves that banks use to determine how much they will lend. Borrowing bases are generally set twice a year, and the new levels, which will typically take effect from October 1, will reflect significantly lower expectations for oil prices than the round agreed in the spring.

Oil and gas M&A at record pace amid oil rout - M&A in the oil and gas industry is running at a record pace this year, as the slump in oil prices sparks a wave of acquisitions and consolidation. The total $321.2bn spent on deals so far this year easily surpasses the previous year to date record of $227.7bn seen in 2010, according to Dealogic data. It is roughly double the $162bn spent in the same period last year, writes Joel Lewin. The largest deal of the year so far has been Royal Dutch Shell's £47bn swoop on its smaller rival BG Group, the biggest deal the energy sector has seen in more than a decade and one that could potentially transform Shell into the world's largest non-state oil company by output. The M&A wave spread to Australia on Tuesday with news that Perth-based Woodside Petroleum has launched a A$11.6bn bid (US$8.1bn) for explorer Oil Search. With oil prices down by more than half since June 2014, there has been much anticipation of a wave of consolidation that would echo the series of mergers and acquisitions that formed today's supermajors during a period of similarly depressed prices in the late 1990s. During that period, BP joined forces with Amoco and Arco, Chevron with Texaco and Exxon with Mobil. With many of the world's most easily and cheaply accessible oil resources already used up or discovered, dealmaking offers large companies a shortcut to growth. The US has been the top targeted nation for oil and gas M&A this year, accounting for $159.6bn, almost half the total.  May saw the first acquisition of a large US shale oil producer since prices collapsed, with US oil and gas group Noble Energy nabbing Rosetta Resources for about $3.7bn. If prices remain low, the US shale sector could see a rise in acquisitions as balance sheets weaken.

Falling prices force cutbacks and delays to exploration - Even by the standards of past oil price collapses, the latest is shaping up to be momentous. And the world’s biggest oil companies have responded in unison — slashing spending, shedding jobs, and axing or deferring billions of dollars worth of projects. The most recent set of company results reflects the damage inflicted on profits and revenues by a slide in the price of crude of 60 per cent since last summer. This drop from more than $115 a barrel to less than $50 has been triggered by a US supply glut, and accelerated by Opec’s November decision not to cut output. In July, ExxonMobil, the US supermajor, reported a 52 per cent decline in second-quarter profits and its worst quarterly performance since 2009, while Chevron’s earnings plunged 90 per cent, hitting their lowest in more than a decade. In Europe, Royal Dutch Shell took drastic cost-cutting action in July, warning of a “prolonged downturn” as it cut capital spending by 20 per cent and disclosed a 6,500 fall in staff numbers. And BP revealed that it was deferring projects in order to benefit from falling supplier costs. Behind all the noise and numbers is a common theme: a laser-like focus on capital discipline. Even before the oil price began to fall last year, energy groups were under pressure from shareholders to rein in spending and place greater emphasis on “value” over “volume”, after soaring cost inflation eroded returns during the boom years of crude prices at beyond $100 a barrel. That pressure has only increased. So, just as in past downturns such as 1986, oil companies are scrambling to shore up cash flow in order to protect dividends — for which their shares have traditionally been held by investors. The first and easiest button to push is capital spending, or the investment that companies make in exploration and in developing resources that will meet demand years from now. According to energy consultancy Wood Mackenzie, about $200bn of spending on new oil and gas projects has been shelved, at least in part because of the plunge in the price of crude.

US oil producers thirsty for cash eye wastewater unit spin-offs (Reuters) – Some U.S. oil producers are trying to sell parts of their lucrative saltwater disposal businesses in a sign that cheap crude is already forcing cash-starved companies to sell assets so oil can keep flowing. Many oil companies rely on outside contractors, which tend to be small, privately-held companies, to inject the briny byproduct of crude production hundreds or thousands feet deep into the earth, well below the water table. But for producers which own such facilities, the high-margin business has served as a source of cost savings and steady revenue, factors that also make them appealing to yield-seeking investors in master limited partnerships (MLPs) and private equity funds. SandRidge Energy Inc and Oasis Petroleum Inc are two publicly traded oil producers openly marketing their saltwater divisions. SandRidge is planning to raise cash by listing it as an MLP and Oasis is seeking at least a partial sale. “The psychology of the market is pretty bad right now,” said Andrew Coleman, an energy analyst at Raymond James. “Any sale of these assets gives financial visibility without having to carry the cost of the asset on their books in what could be a rocky next few months.” Putting even a part of such businesses on the block suggests some energy executives are coming under increasing pressure to part ways with good, albeit non-core, assets to ride out the crude market slump and finance core oil operations.

The Biggest Red Herring In U.S. Shale -- Rig productivity and drilling efficiency distract from the truth that tight oil producers are losing money at low oil prices. Pad drilling allows many wells to be drilled from the same location by a single rig. Rig productivity reflects the increased volume of oil and gas thus produced by each of a decreasing number of rigs. It does not account for the number of producing wells that continues to increase in all tight oil plays. In other words, although the barrels produced per rig is increasing, the barrels per average producing well is decreasing (Figure 1). Rig productivity is a potentially deceptive measurement because it does not consider cost and apparently it always increases. It gives a best of all possible worlds outcome that seems to defy the laws of physics. Drilling productivity gives the false impression that as the rig count approaches zero, production approaches infinity. Barrels per rig is interesting but the cost to produce a barrel of oil is what matters. Similarly, drilling efficiency measures the decrease in the number of days to drill a certain number of feet. This is also interesting but, unless we know how it affects the cost to produce a barrel of oil, it is not useful. First-half 2015 SEC filings for Pioneer, EOG* and Continental show that these companies are all losing money at an average realized crude oil price of $48 and range of $44-52 per barrel that includes hedges. I chose these companies to study because they have good positions in the best tight oil plays, and provide a weighted cross-section of Bakken, Eagle Ford and Permian production performance (Table 1).

Shale’s dirty little capital market secret - Izabella Kaminska - "Many shale producers outspend cash flow and thus depend on capital market injections to fund ongoing activity." That’s from Citi’s Richard Morse and Edward Morse (related?), plus team, on the way capital markets rather than cartels are driving commodity prices these days. The note is titled: “From Cartel to Capital Markets: Investors Join OPEC Shaping Oil Market Dynamics.” This of course relates to our point on Monday that even the big commodity traders have been forced to turn to market-based funding in lieu of a dearth of bank finance in the sector. This is important because back in the old days it was Opec which acted as the balancing agent of last resort for the market. But today it’s not Opec which balances supply. It’s not even specialist banks. It’s the capital markets, which for the most part are made up of a melange of passive, active, risk averse and risk-on investors. As a collective they either provide financing to help withhold commodities from the market so as to keep sector investment flowing or alternatively which withdraw financing so as to release stored or pent-up commodities to the market to cover shortages. The problem with capital markets, however, is that unlike politically-motivated cartels which at least pretend to adhere to cartel rules that act in the interest of sovereign nations (motivated as they are by the desire to extend the value of their natural resource endowment for as long as possible), capital markets don’t have any such protocols or long-term aspirations. They are motivated simply by profit. Consequently, the only reason to provide financing to withhold commodity supply from the market is the assumption you can one day profit in a period of scarcity or shortages. Joseph and the Pharaoh stuff. Except, unlike with Joseph and the Pharaoh, capital markets don’t have access to prophetic dreams which can de-risk the cost of over-accumulation in times of plenty for anticipated shortages that never actually transpire. To wit, here’s Citi on how it was capital markets which helped to bridge the shale producing “funding gap,” but how that capital might not be as forthcoming if general capital costs rise:  Easy access to capital was the essential “fuel” of the shale revolution. But too much capital led to too much oil production,and prices crashed.  The shale sector is now being financially stress-tested, exposing shale’s dirty secret: many shale producers depend on capital market injections to fund ongoing activity because they have thus far greatly outspent cash flow. In the aggregate North American crude producers do not generate positive free cash flow (Figure 1), although some stronger producers do.

Citigroup Sees U.S. Oil Output Losing 500,000 Barrels a Day - A funding squeeze threatens to cut U.S. oil output by as much as half a million barrels a day by the end of the year, with shale producers among the worst affected, Citigroup Inc. said. “Capital markets thus far have plugged shale’s funding gap but are showing signs of tightening, with impacts for drilling, oil supply and global prices,” Richard Morse and Ed Morse, analysts at Citigroup in New York, said in a note. Access to high-yield credit markets for debt-strapped producers is “sharply contracting,” they said. High-cost oil producers in the U.S. have been forced to scale back in the past year after members of the Organization of Petroleum Exporting Countries decided to maintain output to defend their market position. U.S. crude prices have dropped almost 40 percent since OPEC announced its policy change in November to trade at about $45 a barrel Wednesday. “The U.S. could lose up to 500,000 barrels a day of output by year-end, half from shale,” Citigroup said in the note dated Tuesday. That loss almost matches Ecuador’s daily production, which was about 536,000 barrels last month. Ecuador is the 11th-biggest producer in OPEC, whose 12 members supply about 40 percent of the world’s oil. Cuts to reserve-based lending, which allows companies to secure loans with undeveloped oil resources, will remove an important source of liquidity, according to the bank. Weaker producers may face bankruptcy, while those with “high-quality” assets should be more resilient, it said. The number of oil rigs in the U.S. has shrunk by almost 60 percent since reaching a record-high last October, Baker Hughes Inc. data show. Production in the country fell for a fourth week on Aug. 28, the longest declining streak since January 2012, according to the Department of Energy.

Blue Dog Democrats endorse oil export bill - — A coalition of fiscally conservative Democrats on Wednesday declared their support for legislation to lift longstanding oil export restrictions. The 14-member Blue Dog Coalition said they backed the bill the night before a House subcommittee is expected to approve the measure.  Oil export advocates said the endorsement is a sign of growing support for the push to lift the ban, though substantively, it may not represent many new “aye” votes for the legislation. Eight members of the group had already signed on as cosponsors of the bill. One of them, Rep. Kurt Schrader, D-Ore., said oil exports can be a force for stability in volatile regions of the world “by creating competition on the global market and limiting the ability of countries like Russia to use crude . . . as a political weapon.” Rep. Joe Barton, R-Ennis, has been working with lead Democratic cosponsor (and Blue Dog member) Henry Cuellar, D-Texas, to build support for the bill. The House Energy and Power Subcommittee is slated to vote on the legislation Thursday, paving the way for a full committee’s consideration as early as next week.

U.S. House panel passes bill to repeal oil export ban -  A bill to repeal the U.S. ban on oil exports gained momentum on Thursday, when it passed a House of Representatives subcommittee, an initial step to overturn the 40-year-old trade restriction in the full chamber. The House Energy and Power subcommittee passed the bill by a voice vote. The legislation, sponsored by Republican Representative Joe Barton of Texas, is expected to go to a vote by the full Energy and Commerce committee next week. Passage by the full panel would set it up for a wider vote by the Republican-led House, where it is expected to pass. The measure, however, still faces an uphill battle in the U.S. Senate. Barton said the energy landscape has changed since 1975 when the ban was imposed and a repeal would provide jobs and help allies diversify their oil supplies. The bill is supported by oil producers who say they need access to global markets to keep the domestic drilling boom alive. But several Democrats on the panel expressed reservations about the measure. Representative Frank Pallone, a New Jersey Democrat, said repealing the ban would lead to a “significant pay day for oil producers,” but it was less certain that it would benefit U.S. consumers and that a repeal would put oil refinery jobs in jeopardy. Democratic Representative Mike Doyle of Pennsylvania said repealing the ban would shift U.S. refinery jobs overseas.

Alberta’s oil and gas land sales revenue takes a beating - Alberta is on track to post its worst annual oil and gas land sales revenue in more than two decades. As of late August, auctions in which the province leases out land rights to energy companies have pulled in $209-million. “It’s absolutely the worst that we’ve seen the 21 years that I’ve been doing this,” said Winston Gaskin, president of Standard Land Co., which assists companies in buying land rights.In 2014, Alberta sold $494-million worth of energy land tenures, the lowest since 2002. Given the current pace of sales, Alberta could see its lowest land sales revenue since 1992, when it sold a paltry $149-million in land rights. That compares with a high-water mark of $3.5-billion in 2011 as excitement in the Duvernay shale formation drove up prices. “Exploration budgets are the first things that get cut in times like these, so that impacts the sales,” Mr. Gaskin said. B.C., meanwhile, had sold only $8.5-million worth of petroleum and natural gas tenures as of mid-August, compared with $383-million in all of 2014 and a bumper year of $2.7-billion in 2008. In Saskatchewan, the government had pulled in $35.7-million from exploration licences and leases as of mid-August, while last year it received $197.9-million.

Alberta regulator lets Nexen reopen some Long Lake pipelines - Alberta’s energy regulator said late on Sunday it will allow Nexen Energy, the Canadian subsidiary of China’s CNOOC Ltd, to reopen some pipelines ordered closed following a major spill. The Alberta Energy Regulator said it would allow a restart of 40 of 95 pipelines closed at Nexen’s Long Lake oil sands operations after reviewing maintenance and monitoring documentation. “The remaining 55 pipelines affected by the order, which contain several products, including crude oil, natural gas, salt water, fresh water and emulsion, continue to be suspended,” the regulator said in a statement. “These pipelines … will not return to service until Nexen can demonstrate that the pipelines can be operated safely and within all requirements.” The provincial regulator last month ordered Nexen to shut in the pipelines at the Long Lake facility as part of an investigation into one of the largest-ever oil-related pipeline spills on North American soil, discovered in July.

Inside Ground Zero Of Canada's Burst Oil Bubble --In the past year, we have extensively profiled the collapse of ground zero of Canada's oil industry as a result of the plunge in the price of oil, in posts such as the following:

Since then it has gotten far, far worse for Canada. In fact, as of September 1 it culminated with the first official recession in 7 years. And it's only downhill from there. As Mark Thornton of the Mises Institute points out, in a report from the Financial Post shows that Calgary in Alberta Canada now has 1.7 million square feet of empty office space, the most in North America with another 5.2 million under construction! After years of booming construction, the natural resource rich country is starting to feel the pinch. To wit:  The number of half-empty office buildings in Alberta is projected to spike, as Colliers International predicts an “ill-timed” building boom should push up vacancy rates in Calgary and Edmonton. 

Oil falls more than 3 percent on oversupply, China equity losses | Reuters: Oil fell more than 3 percent on Monday, hit by weaker Chinese equities and record North Sea crude production data that added to global oversupply concerns. China's main indexes closed down on Monday as investors sold shares in the aftermath of a four-day market holiday, during which further restrictions on futures trading were announced. "Oil is only taking its cues from China,". "The price is taking little notice of constructive data like stronger (European) equities, stronger base metals and last Friday's fall in U.S. rig count," he said. Brent futures contracts for October fell $1.98 to settle at $47.76 a barrel, a 3.73 percent loss. U.S. crude fell $1.80 to $44.25 per barrel by 2:48PM, with trading volume of around 75,000 lots less than one-quarter the norm due to the U.S. Labor Day holiday. Oil has fallen almost 60 percent since June 2014 on a global supply glut, with prices seesawing in recent weeks as concerns about a slowing Chinese economy caused turmoil in global stock markets. "For commodities, the key demand-side figure to care about is not China’s GDP growing at 7 percent instead of 9 or 10 percent, it is the manufacturing price index, which has been falling for more than 40 months in a row," JBC Energy said. The Organization of the Petroleum Exporting Countries is producing close to record volumes to squeeze out competition, especially from U.S. shale producers, which have so far weathered the price plunges to keep pumping oil.

WTI Crude Tumbles To $44 Handle (As Algos Forget US Closed) -- Despite US markets being closed for Labor Day, WTI Crude futures traders algos appear to be following the post-EU close run-the-stops pattern. Despite rising tensions in the middle-east and China promising their market is stable, WTI Crude is down almost 4%, back to a $43 handle...

API crude oil inventories: up 2.1 mln barrels - American Petroleum Institute (API) crude oil inventories for the week to September 4

  • Stock build last week of 2.1 million barrels
  • Refineries cut output
  • Gasoline inventories and distillate inventories up
  • Crude stocks at Cushing fell 1.1 million barrels

The API data is closely watched as a guide to the U.S. Energy Information  Administration (EIA) data due tomorrow morning (US time). The consensus estimate for tomorrow's EIA report is currently for +872.73Kbbls (i.e. an inventory build).

WTI Tumbles On Crude's Biggest 2-Week Build In 5 Months -- Following last night's 2.1mm barrel build forecast from API, DOE reported a bigger than expectd 2.6mm barrel inventory build. This is the largest 2-week build in crude stocks since April and has sent crude prices tumbling. Charts: Bloomberg

Crude Oil Price Dips as Inventory Rises, but Refineries Slow Down - The U.S. Energy Information Administration (EIA) released its weekly petroleum status report Thursday morning. U.S. commercial crude inventories increased by 2.6 million barrels last week, maintaining a total U.S. commercial crude inventory of 458 million barrels. The commercial crude inventory remains near levels not seen at this time of year in at least the past 80 years. Wednesday evening, the American Petroleum Institute (API) reported that crude inventories rose by 2.1 million barrels in the week ending September 4. The API also reported that gasoline supplies rose by 700,000 barrels and distillate stockpiles rose by 800,000 barrels. For the same period, analysts surveyed by Platts had estimated an increase of 300,000 barrels in crude inventories. Total gasoline inventories increased by 400,000 barrels last week, according to the EIA, and remain in the middle of the five-year average range. Total motor gasoline supplied (the agency’s measure of consumption) averaged over 9.3 million barrels a day for the past four weeks, up by 3.8% compared with the same period a year ago. The U.S. House of Representatives Energy and Power subcommittee has been lining up votes to lift the 40-year ban on exports of U.S. crude. On Wednesday, 14 Democrats known as the Blue Dogs said they supported lifting the ban on oil exports. What all this means is not terribly clear, although the most likely options are an up or down vote on legislation to lift the ban or adding the export language to other legislation, such as the spending bill or the highway funding bill.

OilPrice Intelligence Report: Does This Mean OPEC Is Winning The Oil Price War? -- The EIA’s weekly data showed a surprise uptick in oil inventories, the second consecutive week of gains. Crude stocks jumped by 2.6 million barrels. After around three months of slow but steady drawdowns in inventories since the beginning of May, crude stocks have been largely unchanged (despite week-to-week movements) since the beginning of August. It is not coincidental that the pause in drawdowns overlapped with another dive in oil prices. The latest inventory build puts more pressure on prices. However, we are finally seeing meaningful reductions in actual output, the most important indicator for investors watching for a balancing in the oil markets. All summer, the world has been left in a confused state over how long U.S. oil production would remain steady. But in the last two weeks, the EIA has published new data that points to a much deeper and more definitive slowdown in U.S. oil production. The best guess from the agency says that the U.S. is producing just 9.13 million barrels per day (mb/d), down around 500,000 barrels per day since peaking in April. The loss of around half a million barrels per day in production is equivalent to the entire output of individual countries, such as OPEC member Ecuador, or even Libya’s current production level. It is a significant reduction, and one that is accelerating. In June, the U.S. saw oil production dip by 100,000 barrels per day, but a few months later, the losses have grown to 140,000 barrels per day for the month of August. With investment on behalf of exploration and production companies shrinking, not expanding, the cutbacks will continue.The IEA released its monthly report on September 11, and its conclusions largely back up the latest predictions from the EIA. The Paris-based organization believes that non-OPEC production will fall by 500,000 barrels per day in 2016, which will be the sharpest drop in the past quarter century. “Oil's price collapse is closing down high-cost production from Eagle Ford in Texas to Russia and the North Sea,” the report concludes. U.S. shale “is likely to bear the brunt” of the contraction, losing 400,000 barrels per day next year.

U.S. crude inventories might be tighter than they look – U.S. oil markets have been transformed over the last decade by the emergence of oil trading and storage as a major business in its own right, separate from production and refinery operations. At the end of 2014, there were more than 390 million barrels of crude stored at refineries and tank farms as well as in transit in pipelines and barges and in storage tanks at oilfields. Commercial crude stockpiles had climbed by more than 100 million barrels since the end of 2004, almost 38 percent, according to annual data published by the U.S. Energy Information Administration (EIA). By the end of April 2015, commercial stocks had climbed by another 105 million barrels to a record 491 million as the oversupply in the global oil market ended up at refineries and tank farms. Even after a strong summer driving season, with U.S. refineries processing record amounts of crude into gasoline and other fuels, stockpiles remained at 455 million barrels at the end of August. But the focus on rising inventories as a sign of the cyclical supply-demand imbalance has obscured deeper structural changes which have resulted in the industry holding higher stocks than a decade ago.Some of the increase in stocks stems from operational requirements linked to the increase in domestic oil production, which means more crude stored in field tanks as well as in railroad tank cars and in pipelines on the way to refineries.The futures markets are also providing incentives to store more crude in the form of a much wider and more consistent contango structure. Before 2005, the U.S. oil futures market traded in backwardation about two-thirds of the time, and contango around one-third of the time. Whatever the cause, the shift from backwardation to contango trading as the norm has coincided with a large increase in stockholding. And the physical market has moved to accommodate an increased desire to hold stocks by building much more storage capacity. The amount of storage available at tank farms, most of which is leased either long-term or short-term to traders, has surged.  Tank farm and underground storage capacity jumped to 391 million barrels in March 2015, from 307 million in March 2011, according to the EIA.

Crude Jumps After Biggest 2-Week Rig Count Decline In 4 Months -- With Saudis blowing off an OPEC leaders meeting, Iran slashing prices to 3 year lowsinventories rising rapidly but US production dropping quickly, and Goldman calling for $20 oil possible, it has been a busy (and mixed) week for oil news. Add to that the seasonal lull amid refinery slowdown/repairs and Today's 10 rig drop in US oil rig count to 652 (following last week's 12 rig drop) is the biggest 2-week drop in 4 months just adds to the noise with Texas rig count dropping most (-9 to 366). Crude prices are rising modestly as US rig count drops back to 2-months lows. This is the lowest total rig count since January 2003...  and the result... Finally, just a "thinking out loud" chart....  Charts: Bloomberg

U.S. oil drillers cut rigs with crude price decline - Baker Hughes - U.S. energy firms cut oil rigs for a second week in a row, data showed on Friday, a sign the latest price declines may be causing some drillers to put on hold their recently announced plans to return to the well pad. Drillers removed 10 rigs in the week ended Sept. 11 and 13 rigs in the week ended Sept. 4, bringing the total rig count down to 652, after adding rigs in six of the past eight weeks, oil services company Baker Hughes Inc said in its closely followed report. That was the biggest two-week decline since early May. Those additions since the start of July showed some drillers had followed through on plans to add rigs announced in May and June when U.S. crude futures averaged $60 a barrel. U.S. oil prices this week, however, averaged $45 a barrel, down from an average of $47 last week. Earlier Friday, U.S. crude prices were down more than 2 percent after two banks, Goldman Sachs and Commerzbank, both slashed their crude forecasts, citing lingering oversupply concerns and worries over China’s economy.  “The oil market is even more oversupplied than we had expected and we forecast this surplus to persist in 2016,” Goldman said in a note entitled “Lower for even longer.” Drillers this week cut one oil rig in each of the four major U.S. shale oil basins: the Eagle Ford in South Texas, Niobrara in Colorado and Wyoming, Bakken in North Dakota and Montana, and Permian in West Texas and eastern New Mexico.

Near-Term Forces Could Push Oil Prices Lower -- Meanwhile, the North Sea oil industry is facing an existential crisis. Low oil prices have forced spending cuts and contraction across the world, but the offshore oil and gas fields in the North Sea are some of the world’s costliest. Mature fields have been in decline for years, and companies have to constantly invest capital to keep the decline merely at a slow pace, rather than a precipitous one. However, persistently low oil prices could send the North Sea oil and gas industry into a sort of death spiral. According to the FT, the North Sea is at “serious risk” of shutting down. The problem is that many companies share certain infrastructure, so when one company shuts down its operations and pulls out, that leaves the cost of maintaining collective infrastructure (such as pipelines or processing facilities) much greater for the companies that remain. As such, the more fields that are shut down, the greater the pressure on existing operators to leave the region as well. The British government has tried to help the industry through lower taxes, but it may not be enough. More companies are clamoring for the exits. Royal Dutch Shell (NYSE: RDS.A) announced this summer that it would shrink its footprint in the North Sea. Total (NYSE: TOT) announced in August that it would sell $900 million worth of North Sea assets in order to raise cash. Greater cooperation between companies could slow the decline, an industry trade group says. For example, companies could share data on dry wells. However, such cooperation is foreign to operators who are so used to competing, and salvaging the region as a major source of oil and gas production appears increasingly difficult.

The Decline Of Oil: Head-Fake Or New Normal? -- In May 2008 I proposed the Oil "Head-Fake" Scenario in which global recession pushes oil demand down as oil exporters pump their maximum production in a futile attempt to fund their vast welfare states and thus retain their precarious political power. The terrible irony of the head-fake, of course, is that the exporters' efforts to pump more oil exacerbates the oversupply, further depressing prices. As exporters receive fewer dollars for their production, they attempt to compensate by pumping even more oil. Perniciously, this suppresses prices even more, setting up a positive feedback loop which pushes prices to the point that exporters are no longer able to fund their welfare states and Elites. Something has to give, and that something is the existing power structure in oil exporting nations. The majority of exporting nations under-invest in their oil production and exploration infrastructures, essentially guaranteeing declining production once the easy oil has been extracted. This cycle of spending the fruits of current production while starving investment for the future is part of what is known as the resource curse: nations with an abundance of resources rely on the income generated by the sale of their resources which effectively stunts the development of a diverse economy and the institutions which such a diverse economy requires as a foundation. The net result of the resource curse is national impoverishment as the resources are depleted. Diverting the majority of the oil revenues to support welfare states and Elites dooms the oil exporters to under-investment in future production. In other words, the decline in the price of oil does not mean oil will remain cheap for years to come; it's a head-fake that fools the unwary into assuming the glut is The New Normal.

Oil production in US seen tumbling due to price drop - Oil supply from the United States, Russia and other non-OPEC countries is expected to drop sharply next year — possibly the steepest decline since the Soviet Union collapsed — because of low prices, the International Energy Agency forecast Friday. In its latest monthly report, the IEA says non-OPEC production is expected to drop nearly half a million barrels to 57.7 million barrels a day. It said that would be the largest annual drop since 1992, when non-OPEC supply shrank 1 million barrels after the USSR fell apart. Amid booming U.S. production and high OPEC output, the benchmark price of oil plunged from over $100 last year to about $45 this week. Global oil demand has also grown, but not enough to absorb the high supply. The agency forecast global oil demand would grow this year to a five-year high of 1.7 million barrels a day, before dropping to 1.4 million next year. The low price is particularly hurting U.S. production, with the decline in output speeding up over the summer, the IEA said. Russian and North Sea supply is also forecast to shrink. The report said OPEC supply remains higher than last year and well above the group’s own production targets. There have been only slight declines in Saudi Arabia, Iraq and Angola, which edged down OPEC’s daily crude supply by 220,000 barrels in August to 31.6 million barrels a day.  So despite the IEA’s forecast for a drop in production in places like the U.S. next year, experts say it is unlikely that prices will rebound any time soon.

Global Economic Fears Cast Long Dark Shadow On Oil Price Rebound -- Aside from supply and demand fundamentals in the oil markets, central bank policymaking is another major factor determining the trajectory of oil prices. The European Central Bank hinted that it might consider more monetary stimulus to help the stagnant European economy. Oil prices rose on the news. The markets, however, are waiting on a much more significant announcement from the Federal Reserve this month on whether or not the central bank will raise interest rates.  On September 4, the U.S. government released data for the month of August, revealing that the U.S. economy added only 173,000 jobs, a mediocre performance that missed expectations. Although an economic slowdown is no doubt a negative for oil prices, the news could provide enough justification for the Fed to hold off on raising interest rates. A delay in a rate hike could push up WTI and Brent.  Although a slew of Canadian oil sands projects have been cancelled due to incredibly low oil prices, several large projects were already underway before the downturn.With the costs of cancellation too high, these projects continue to move forward. When they come online – several of which are expected by 2017 – they could add another 500,000 barrels per day in production, potentially exacerbating the glut of supplies not just in terms of global supply, but more specifically in terms of the flow of oil from Canada. Canadian oil already trades at a discount to WTI, now at around $15 per barrel. That means that when WTI dropped below $40 per barrel last week, Western Canada Select was nearing $20 per barrel. With the latest rebound to the mid-$40s, WCS is only around $30 per barrel. But with breakeven prices for many Canadian oil sands projects at $80 per barrel for WTI, oil operators in Alberta are no doubt losing sleep over their current situation. One important caveat to remember is that unlike shale projects, Canada’s oil sands operate for decades, so the immediate downturn does not necessarily ruin project economics. However, with a strong rebound in prices no longer expected in the near-term, high-cost oil sands projects are probably not where an investor wants to be.

Oil absolutely friggin everywhere - The monthly IEA oil market report puts things about as simply as they can be put: As they note: The big story this month is one of tightening supply, with the spotlight firmly fixed on non-OPEC. Oil’s price collapse is closing down high-cost production from Eagle Ford in Texas to Russia and the North Sea, which may result in the loss next year of half a million barrels a day – the biggest decline in 24 years. While oil’s recent volatility has been unnerving – Brent crude jolted from a six-year low below $43 /bbl to above $50/bbl in the space of days – the lower price environment is forcing the market to behave as it should by shutting in output and coaxing demand. US oil production is likely to bear the brunt of an oil price decline that has already wiped half the value off Brent. After expanding by a record 1.7 mb/d in 2014, the latest price rout could stop US growth in its tracks. A sharp decline is already underway, with annual gains shrinking from more than 1 mb/d at the start of 2015 to roughly half that level by July. Rigorous analysis of our data suggests that US light tight oil supply, the engine of US production growth, could sink by nearly 400 kb/d next year as oil’s rout extends a slump in drilling and completion rates. Critically, the IEA notes that inventories are continuing to build with global supply — towering 2.4 mb/d above a year ago, outpacing demand. Furthermore, the IEA says it only sees the world beginning to siphon off record-high stocks in the second half of 2016. Here, meanwhile, is a nifty chart representing how the crude supply battle is currently being fought out between Opec and non-Opec producers:

$20 Oil? Goldman Says It's Possible -- We’ve long framed collapsing crude prices as a battle between the Saudis and the Fed.  When Saudi Arabia killed the petrodollar late last year in a bid to bankrupt the US shale space and secure a bit of leverage over the Russians, the kingdom may or may not have fully understood the power of ZIRP and the implications that power had for struggling US producers. Thanks to the fact that ultra accommodative Fed policy has left capital markets wide open, the US shale space has managed to stay in business far longer than would otherwise have been possible in the face of slumping crude. That’s bad news for the Saudis who, after burning through tens of billions in FX reserves to help plug a yawning budget gap, have now resorted to tapping the very same accommodative debt markets that are keeping their competition in business as a fiscal deficit on the order of 20% of GDP looms large. But even with a gaping hole in the budget and an expensive proxy war raging in Yemen, it’s not all bad news for Saudi Arabia as evidenced by King Salman’s lavish Mercedes procession upon arrival in DC last week and as evidenced by the fact that, as The Telegraph reports, non-cartel output is beginning to fold under the pressure of low prices. The only remaining question then, is how low will oil go in the near- and medium-term and on that point we go to Goldman for more: Oil prices have declined sharply over the past month to our $45/bbl WTI Fall forecast. While this decline was precipitated by macro concerns, it was warranted in our view by weak fundamentals. In fact, the oil market is even more oversupplied than we had expected and we now forecast this surplus to persist in 2016 on further OPEC production growth, resilient non-OPEC supply and slowing demand growth, with risks skewed to even weaker demand given China’s slowdown and its negative EM feedback loop.  Given our updated forecast for a more oversupplied oil market in 2016, we are lowering our oil price forecast once again. Our new 1-, 3-, 6- and 12-mo WTI oil price forecast are $38/bbl, $42/bbl, $40/bbl and $45/bbl. Net, while we are increasingly convinced that the market needs to see lower oil prices for longer to achieve a production cut, the source of this production decline and its forcing mechanism is growing more uncertain, raising the possibility that we may ultimately clear at a sharply lower price with cash costs around $20/bbl Brent prices, on our estimates. While such a drop would prove transient and help to immediately rebalance the supply and demand for barrels, it would likely do little for the longer-term capital imbalance in the market with only lower prices for longer rebalancing the capital markets for energy.

Energy job cuts approaching 200,000 worldwide - The oil bust’s toll on corporate payrolls continues to grow. Job cuts in the petroleum industry reached nearly 196,000 globally last week, according to a Houston energy consultant, after ConocoPhillips said it would cut 10 percent of its workforce and other energy firms announced more layoffs. Nearly half of the oil industry’s reductions over the past year have come from the oil field service industry, firms that provide oil and gas producers with drill bits, well casing, hydraulic fracturing pumps and other technology, says John Graves, president of Graves & Co., who has tracked the layoffs closely. Though most of the reductions have come from oil field service firms so far, analysts believe oil producers could spur the next wave of layoffs. “While there remains additional force reduction potential in the OFS sector, upstream organizations within the producer community appear to be just getting started with their layoff programs,” analysts at Tudor, Pickering, Holt & Co. said in a note to clients Tuesday. The analysts said a handful of other producers have cut general and administrative costs, but most haven’t indicated whether layoff are taking place or not. There is also anecdotal evidence firms are rescinding offers to new hires in petroleum engineering, they said.

End Of Cheap Fossil Fuels Could Have More Severe Consequences Than Thought - The characteristic feeling of the post-2008 world has been one of anxiety. Occasionally, that anxiety breaks out into fear as it did in the last two weeks when stock markets around the world swooned and middle class and wealthy investors had a sudden visitation from Pan, the god from whose name we get the word "panic." Pan's appearance is yet another reminder that the relative stability of the globe from the end of World War II right up until 2008 is over. We are in uncharted waters. Here is the crux of the matter as expressed in a piece which I wrote last year: The relentless, if zigzag, rise in financial markets for the past 150 years has been sustained by cheap fossil fuels and a benign climate. We cannot count on either from here on out.... Another thing we cannot necessarily count on is the remarkable geopolitical stability that the world experienced for two long stretches during the fossil fuel age. The first one lasted from the end of the Napoleonic Wars in 1815 to the beginning of World War I in 1914 (interrupted only by the brief Franco-Prussian War). The second lasted from the end of World War II in 1945 until now. Following the withdrawal of U.S. military forces from Iraq, the Middle East has experienced increasing chaos devolving into a civil war in Syria; the rapid success of forces calling themselves the Islamic State of Iraq and Syria which are busily reshaping the borders of those two countries; and now the renewed chaos in Libya. We must add to this the Russian-Ukranian conflict. It is no accident that all of these conflicts are related to oil and natural gas.

The Petrostate Hex: Visualizing How Plunging Oil Prices Affect Currencies -- (infographic) Every day, the world consumes 93 million barrels of oil, which is worth $4.2 billion. Oil is one of the world’s most basic necessities. At least for now, all modern countries rely on oil and its derivatives as the backbone of their economies. However, the price of oil can have significant swings. These changes in price can have profound implications depending on whether an economy is a net importer or net exporter of crude. Net exporters, countries that sell more oil abroad than they bring in, feel the sting when prices plunge. Less revenue gets generated, and this can impact everything from balancing the budget to the value of their currency in the world market. Net importers, on the other hand, benefit from lower prices as it decreases input costs for production. For example, a country like Japan only meets 15% of its energy needs domestically, and must import 3.5 million barrels of oil each day. A lower oil price significantly decreases these costs. For many major net exporters of oil, changes in oil prices are highly correlated with their currencies. With oil prices crashing over the last year, currencies such as the Canadian dollar and Russian ruble have been highly impacted in terms of USD. But the impact of oil on currency depends on how central banks approach to policy.

Low oil price forces Saudi Arabia to cut spending amid record budget shortfalls - Saudi Arabia will cut spending and issue more bonds as it faces a record budget shortfall due to falling oil prices, the finance minister said on Sunday. The kingdom - the biggest Arab economy and the world's largest oil exporter - is facing an unprecedented budget crunch after crude prices dropped by more than half in a year to below $50 a barrel. It has so far relied on its huge fiscal reserves to bridge the gap but Finance Minister Ibrahim al-Assaf said more measures would be necessary. "We are working... to cut unnecessary expenditure," He provided no details on the scale of the cuts but insisted key spending in education and health and on infrastructure would not be affected. "There are projects that were adopted several years ago and have not started yet. These can be delayed," Assaf said. He said the government would issue more conventional treasury bonds and Islamic sukuk bonds to "finance the budget deficit" - which is projected by the International Monetary Fund at a record $130bn (£86bn) for this year. The kingdom has so far issued bonds worth "less than 100 billion riyals (£17.8bn)" to help with the shortfall, he said, without providing an exact figure. "We intend to issue more bonds and could issue sukuk for certain projects... before the end of 2015," Assaf said. Saudi Arabia has projected an official budget shortfall for this year of $39 billion, but the IMF and other institutions believe the actual deficit will be much higher.

Expectations of Saudi oil shake-up stir uncertainty - A shake-up of Saudi Arabia’s oil leadership by King Salman has introduced a new element of unpredictability to its energy policymaking at a moment when Riyadh is grappling with slumping crude prices and its war in neighboring Yemen. State oil giant Aramco has been without a permanent chief executive since April, when Khalid al-Falih was made health minister, and the old Supreme Petroleum Council, where energy policy was historically made, was abolished in January. While the world’s top crude exporter has always prized stability and consistency in crafting oil policy, the changes, alongside a shift in market strategy that contributed to the world price slump, have left analysts and traders guessing as to King Salman’s long-term vision. The main tenets of Saudi oil policy – maintaining the ability to stabilize markets via an expensive spare-capacity cushion and a reluctance to interfere in the market for political reasons – are still set in stone, say market insiders. But the uncertainty has led to speculation over the fate of both veteran Oil Minister Ali al-Naimi and the wider composition of the kingdom’s energy and minerals sectors, with rumors abounding that a sweeping restructure could be imminent. “There will be changes (at the oil ministry), but no one knows when or what will happen next. It could be tomorrow, next week or a month from now,” said a Saudi insider. “The decisions are being taken by a small circle of people and a few advisers.” The key person in that small circle is Prince Mohammed bin Salman, the young deputy crown prince who without having any previous oil experience has emerged since his father’s accession to power as the most powerful figure in Saudi economic and energy policy.

Saudi oil maintains Asian market share - Saudi Arabia maintained its market share among Asian oil importers in the first half of this year but threats to its long-term standing loom, according to the US energy department. The share of these crude oil imports from Saudi Arabia averaged 23.2 per cent from January to June, compared with 23.9 per cent in the same period in 2014, the Energy Information Administration said on Wednesday. The world’s largest crude exporter and biggest Opec producer “increased production and kept its export levels high, enabling it to maintain its market share”, the EIA said. Saudi Arabia exported on average 4.4m barrels a day of crude oil to seven major trading partners in Asia in the first half of this year. Total crude oil imports for these countries averaged 19.1m b/d, about 700,000 b/d higher than during the same period in 2014. The kingdom’s import share to China (16 per cent), Japan (33 per cent), India (20 per cent), South Korea (33 per cent), Taiwan (33 per cent) and Thailand (19 per cent) were almost unchanged. Its share declined in Singapore, down to 18 per cent from 26 per cent. Previously during periods of oversupply, Saudi Arabia has adjusted its production to bolster prices. But last November the kingdom led a decision by the Opec producers’ cartel not to cut output and instead focus on maintaining its market share among core customers. Saudi Arabia’s output rose sharply in the first six months of the year to 10.6m b/d in June, according to the JODI oil database. Exports, meanwhile, have fluctuated between 7m-8m b/d, with Asia making up more than half of the total.

Saudis Are Winning the War on Shale  If you believe all the recent stories about how Saudi Arabia is losing the price war it started against U.S. tight oil producers last year, the new Oil Market Report from the International Energy Agency offers a reality check. The Saudis are winning, though they're paying a heavy price for it. The narrative about U.S. shale's resilience in the face of the Saudi decision to drive up production, prices be damned, centers on the American industry's ability to cut costs and use innovative technology to repel the brute force onslaught. There is a kind of David versus Goliath charm to this story, but the data don't bear it out. The IEA, the world's most respected independent source of information about the oil market, has changed its methodology for measuring U.S. output: It now polls producers, instead of relying on data from states. And the switch has caused the agency to revise production data for the first half of 2015, showing a noticeable slowdown. The U.S. is still pumping more than it did last year, but the output is declining: IEA data show monthly contractions of 90,000 barrels a day in July and almost 200,000 barrels a day in August. Output is dropping for all seven of the biggest U.S. shale plays. The IEA predicts that the U.S. production of light tight oil -- the type pumped by frackers -- will go down by 400,000 barrels a day next year, about as much as Libya currently produces. That drop will account for most of the 500,000 barrels a day drop in production outside the Organization of Petroleum Exporting Countries that the agency predicts for 2016. Production is also dropping in Canada: It's below 4 million barrels a day for the first time in 20 months. The IEA doesn't believe shale oilers' incantations about drastically lower marginal cost of producing oil from already drilled wells. It points out that tight oil wells dry up much faster than traditional ones: Recent data show that output drops 72 percent within 12 months of startup and 82 percent in the first two years of operation. "To grow or even to sustain production levels requires continuous investment," the IEA report says. Low oil prices reduce frackers' access to the capital they need, and rig counts are falling again -- in early September the drop was the steepest since May.

Saudi deficit could erode reserves: IMF - The International Monetary Fund warned Wednesday that Saudi Arabia's growing budget deficit could rapidly erode its reserves unless it adapts to slumping oil prices by adopting a host of painful reforms. "With the large decline in oil prices, the fiscal deficit has increased sharply and is likely to remain high over the medium term," the IMF said in a report released after talks with Saudi officials. "These deficits will rapidly erode the fiscal buffers that have been built over the past decade," it said. The kingdom must undertake "a large multi-year fiscal adjustment" to balance the budget, the IMF said. The reforms should include comprehensive energy efficiency and price alterations, expanding non-oil revenues, reviewing capital and current expenditures and reducing the government wage bill, it added. The report projected the Saudi budget deficit to run at 19.5 percent of Gross Domestic Product, or around $130 billion, in 2015. It said the deficit is projected to be lower in 2016 but will remain high in the medium term and is estimated at 9.5 percent of GDP -- around $80 billion -- in 2020. The IMF has already cut its economic growth projections for Saudi Arabia to 2.8 percent this year and 2.4 percent in 2016.

Iran Cuts Crude 'Selling Price' To Asia To 3-Year Low -- In what appears to be a bid to lure Asian buyers to lock in longer-term supplies, Reuters reports that Iran has cut its quarterly selling price (for its flagship 'light' crude) to its lowest (relative to Saudi) since Q4 2012. According to recent tanker loading data, Iran's oil sales in September are set to hit a six-month low, and this price reduction is just one of the steps taken by the OPEC producer to ramp up output and regain market share lost since U.S. and European sanctions aimed at its nuclear program cut its crude oil exports by more than half. Iran has cut its relative prices notably over the past year... Iran set its official selling price (OSP) for Iranian Light crude for October at a 25 cents a barrel premium to Oman/Dubai, down 35 cents from the month before, two sources with knowledge of the matter said on Thursday. This puts Iranian Light OSP at a 15-cent premium to Saudi's Arab Light in the fourth quarter, the lowest quarterly price since the last three months of 2012, according to Reuters data. As Reuters reports, Asian buyers have called for lower prices amid a supply glut that has made it tougher for Iran to elbow its way to higher sales volumes despite optimism over the deal that eased some of the sanctions in exchange for curbs on Tehran's nuclear work. An executive at a North Asian oil refiner said it is in talks with the National Iranian Oil Company for next year's term supply, but that Iran's crude prices have been uncompetitive.

Secret memos expose link between oil firms and invasion of Iraq -  Plans to exploit Iraq's oil reserves were discussed by government ministers and the world's largest oil companies the year before Britain took a leading role in invading Iraq, government documents show.  The papers, revealed here for the first time, raise new questions over Britain's involvement in the war, which had divided Tony Blair's cabinet and was voted through only after his claims that Saddam Hussein had weapons of mass destruction. The minutes of a series of meetings between ministers and senior oil executives are at odds with the public denials of self-interest from oil companies and Western governments at the time. The documents were not offered as evidence in the ongoing Chilcot Inquiry into the UK's involvement in the Iraq war. In March 2003, just before Britain went to war, Shell denounced reports that it had held talks with Downing Street about Iraqi oil as "highly inaccurate". BP denied that it had any "strategic interest" in Iraq, while Tony Blair described "the oil conspiracy theory" as "the most absurd". But documents from October and November the previous year paint a very different picture.

The Economies Getting Hit by Low Oil Prices - Oil prices are still under $50 a barrel due to a glut in production and OPEC’s—the cartel of oil-producing countries—price war. Some say that the OPEC is winning: U.S. energy firms have been making cut-backs this summer due to losses from the low prices. It’s good news for U.S. consumers though: Labor Day gas prices are expected to be the lowest in 11 years. But lower oil prices are almost definitely bad news for the governments whose budgets are dependent on them being high: Saudi Arabia, ostensibly the leader of OPEC, is facing huge budget deficits this year due to decreased oil prices. According to the International Monetary Fund (IMF), the deficit will be about $140 billion. Canada’s economy has also made headlines as low crude oil prices meant that the Canuck GDP shrunk for first half of 2015—putting the country in a modest recession on the eve of an election. Major oil-producing countries—that list includes Venezuela, Libya, Russia, Qatar, and Iraq—are all taking a hit. Each of these countries have a different threshold for how low prices can go before their budget goes into deficit territory, but according to calculations by the Wall Street Journal and the IMF—only Kuwait can break even at the current prices. (In Deutsche Bank’s estimates, no one survives.) For now, it’s still unclear when the oil price war will end—some analysts are expecting low oil prices to last for a while. Perhaps what’s even more unclear is who will come out on top at the end of it.

Exclusive: Petrobras spending plan already obsolete, new cuts likely - sources | Reuters: Brazil's state-run oil company Petrobras, which slashed its five-year spending plan by 40 percent in June, will likely cut back further as growing debt costs, falling oil prices and a weak currency have already made the plan obsolete, two company sources told Reuters on Thursday. Standard & Poor's decision to cut Brazil's sovereign credit rating to "junk" grade on Wednesday was followed by a separate downgrade for Petroleo Brasileiro SA, as Petrobras is known, on Thursday. The sources said the downgrade will raise the cost of refinancing Petrobras' more than $130 billion of debt and reduce the capital available to drill wells, build production ships and refineries and pay for infrastructure to boost output and revenue. "The June plan is already obsolete, its outlook for oil prices, debt costs and the currency are no longer realistic. The plan will have to be changed," one of the sources said. In a statement released late on Thursday, Petrobras said its project financing was sound in the medium term and is not affected by a downgrade in credit risk by a ratings agency. Hailed as a return to reality after years of missed output goals, record spending and a giant corruption scandal that led to $17 billion of writedowns, the plan unveiled in June cut the 2015-2019 spending goal to $130 billion from $221 billion. Both sources are directly involved in Petrobras' planning efforts and asked for anonymity because company plans are still under discussion. Both also said a planned sale in 2015 of up to 25 percent of fuel-distribution arm Petrobras Distribuidora SA is now almost impossible.

Mexico's 'mother of all oil and gas rushes' is about to get ugly - Mexico’s energy revolution could prove to be a bitter pill for the vast rump of the Mexican population, who stand to lose out on billions of dollars of annual state funds provided by the newly privatized but financially crippled oil company Pemex. But where there are losers, there are inevitably winners. In this case the biggest beneficiaries will be some of the world’s largest oil and gas majors — particularly those in the U.S. — and well-connected local politicians. Chief among them is former Mexican President Vicente Fox Quesada, whose private equity firm Energy and Infrastructure Mexico (EIM) has just signed a joint venture with Aubrey McClendon, former CEO of natural gas giant Chesapeake Energy and current CEO of American Energy Partners (AEP). The partnership’s main purpose, according to Sin Embargo, is to exploit the vast exploration and development opportunities opened up by Mexico’s newly privatized and liberalized energy sector. “This is a significant vote of confidence in the Energy Reform program championed by current Mexican President Enrique Pena Nieto, and in the myriad possibilities offered by Mexico’s unconventional resources,” hailed a joint press release. Those resources include Mexico’s side of the Eagle Ford Shale basin. EIM Capital’s own website admits, with seemingly not even a hint of shame, that the company was “founded in anticipation of Mexico’s historic Constitutional (Energy) Reform of 2013,” a reform for which Fox himself helped pave the way during his six-year presidential mandate (2000-2006), as recently confirmed by a 2005 State Department diplomatic cable about Fox’s first visit to Alberta recently leaked by Wikileaks. Now, thanks to Peña Nieto’s landmark reforms, the pain is set to recede as Mexico prepares for the mother of all oil and gas rushes. “This is a major opportunity for Mexican energy production,” Fox said in the press release. “We look forward to working closely with the Mexican government to advance this monumental project and enhance Mexico’s current energy policy.”

"They're Making Idiots Of Us!": Eastern Europe Furious At West For Doing Gas Deals With Russian Devils -- Back in June, when Greece was still predisposed to waving around an MOU for participation in the Turkish Stream natural gas pipeline in a desperate attempt to play the Russian pivot card and force Brussels to blink, we remarked that the Turkish Stream MOU with Greece wasn’t the only preliminary energy deal Gazprom inked at the St Petersburg International Economic Forum.   The company also signed a memorandum of intent with Shell, EOn and OMV to double the capacity of the Nord Stream pipeline — the shortest route from Russian gas fields to Europe — to 110bcm/year.  That, we said, proves Russia is making progress in efforts to facilitate the unimpeded flow of gas to Europe even as the crisis in Ukraine escalates. Nearly three months later and Ukraine isn’t happy. Neither is Slovakia. Here’s Bloomberg: Eastern European nations set to lose billions of dollars in natural gas transit fees are lambasting western Europe for striking another pipeline deal with Russia that will circumvent Ukraine. The prime ministers of Slovakia and Ukraine criticized an agreement between western European companies from Germany’s EON AG to Paris-based Engie with Russian pipeline gas export monopoly Gazprom PJSC to expand a Baltic Sea link. Western European leaders and companies are “betraying” their eastern neighbors, Slovakia’s Robert Fico said after meeting Ukraine’s Arseniy Yatsenyuk in the Slovak capital of Bratislava on Thursday. Gazprom and EON, Engie, Royal Dutch Shell Plc, OMV AG and BASF SE signed an agreement last week to expand Nord Stream by 55 billion cubic meters a year, or almost 15 percent of current EU demand. Ukraine, already struggling to avoid a default amid a conflict with Moscow-backed separatists in its east, is set to lose $2 billion a year in transit fees while Slovakia would lose hundreds of millions of euros, the leaders said.

Rosneft chief Sechin damps talk of Russia-Saudi oil supply deal - Russia will not work with Opec to curb a global oil glut even after prices hit the lowest level since the financial crisis, according to the chief executive of Rosneft. Igor Sechin’s comments on Monday damped speculation that recent communications between Moscow and Saudi Arabia could yield a supply agreement. Mr Sechin, former deputy prime minister and a close ally of Vladimir Putin, the Russian president, said Opec had proposed that Russia became a member of the oil producers’ cartel. But the “golden age” of Opec had passed, he said. “The Russian oil industry is private, with a high number of foreign shareholders,” Mr Sechin told an audience at the FT Commodities Retreat in Singapore. BP owns 20 per cent of Rosneft, the Russian state-backed oil company, which is majority owned by the Kremlin. “The Russian government cannot administer the oil industry like an Opec country can,” he said, adding that Russia would also face technical difficulties in shutting production in regions such as Siberia, where extremely cold winters could cause wells to fracture if they were closed. Mr Sechin criticised Saudi Arabia and other Opec members for their role in the oil crash, following the cartel’s decision to keep the taps open last November despite rising supplies. “It needs to be recognised that Opec’s ‘golden age’ in the oil market has been lost,” Mr Sechin said. “They fail to observe their own quotas [for Opec oil output]. If quotas had been observed, global oil markets would have been rebalanced by now.”

Why Vladimir Putin Won't Be Helping OPEC to Cut Oil Production - Few things have more potential to spook the oil market than the prospect of Russia joining forces with OPEC. Speculation that such a move was afoot last month drove crude to its biggest three-day gain in 25 years. Despite the market buzz, there are sound economic and technical reasons why this is unlikely to happen. “Russia and OPEC have talked about cooperation in cutting production many times in the past, but the results of that were always dismal and disappointing,” “Russia has assumed that when oil prices go down, OPEC countries are in a weaker position and are more likely to be the first to cut its production, and they always did.” Russia vies with Saudi Arabia and the U.S. for the title of world’s largest oil producer. Kremlin officials were quick to dismiss the prospect of joint action. Making artificial cuts to output would be senseless in a long term, Russian Energy Minister Alexander Novak said Thursday. Igor Sechin, chief executive officer of Russia’s largest oil company Rosneft OJSC, also delivered a reality check, saying the nation won’t be joining the Organization of Petroleum Exporting Countries and couldn’t cut production even if it wanted to. To be sure, Russia has good reason to want crude to rise again. Energy accounts for more than 60 percent of exports and the nation’s economy is entering a recession due in large part to the price slump.  However, the nation can tolerate low prices better than many OPEC members. Russia’s budget deficit is projected to be about 3 percent of economic output this year,  . Saudi Arabia, OPEC’s largest producer, will have a budget gap of almost 20 percent, the International Monetary Fund forecasts. Russia is comfortable with an oil price above $60 per barrel, Deputy Prime Minister Arkady Dvorkovich said last week. Several OPEC members need more than $100 to balance their government budgets, according to the IMF.

Indonesia close to goal of rejoining Opec - Indonesia is close to rejoining Opec despite a continuing decline in crude output in Southeast Asia’s largest economy.   The country hopes to be readmitted to the oil producers’ cartel at the December meeting of Opec nations, seven years after Jakarta suspended its membership amid falling production. In a statement on Tuesday, Opec said Jakarta had submitted an official request to reactivate its membership, which had been circulated to cartel members for approval. Following feedback, Sudirman Said, Indonesian energy minister, would be invited to Opec’s December meeting, it said. “This will include the formalities of reactivating Indonesia’s membership of the organisation. . . Indonesia has contributed much to Opec’s history. We welcome its return,” the statement added. Although the country exports some crude, it remains a net importer because of its need for refined products. Industry analysts say re-entering the cartel has clear benefits for Indonesia, where a fast-growing population is driving demand for oil and the government is pushing ahead with plans to expand the refining industry. “Oil production is declining rapidly here,” said a Jakarta-based consultant in the oil and gas sector. “To have good contacts, which membership of Opec would give them, would help them in procuring or negotiating competitive deals.”

Sudan grants China gas production franchise in four zones -  Sudan announced Tuesday that China will explore for oil and gas in the Red Sea, Sinnar, and West Kordofan. China is the largest foreign investor in Sudan, which hosts China’s biggest investment in the African continent. Last week President Omer al-Bashir and Chinese President Xi Jinping signed a bilateral strategic partnership, including an agreement for production of natural gas in Sinnar State. Sudanese oil and gas minister Mohamed Zayed Awad confirmed that China had agreed to embark on new oil explorations and to expand its oil operations in Sudan. “China will start gas production in zone 15 in the Red Sea, in zone 4, known as Baleela field, and zone 6 north of Heglig in West Kordofan State, as well as zone 8 in Souki in the east of Sinnar State,” the minister said upon the return of a Sudanese delegation led by President al-Bashir from a visit to Peking. Gas production ushers in a new stage in the development of oil industry in the Sudan. Explorations confirmed presence of gas in many areas, particularly zones 8 and 15 in the Sinnar and Red Seas States, respectively. Last March al-Bashir announced that gas production in zone 8 in Souki, Sinnar State, would start soon.

The Petroyuan Cometh: Launch Of Renminbi-Denominated Oil Futures Contract Imminent -- Whenever one talks about the death of the petrodollar, the unspoken question lurking just beneath the surface is this: is the rise of the petroyuan just around the corner? This year, we’ve gotten quite a bit of evidence to suggest that the answer to that question may indeed be a resounding “yes.” In May for instance, Russia surpassed Saudi Arabia as the largest oil supplier to China and what’s especially notable there is that beginning in 2015, Gazprom began settling all of its crude sales to China in yuan meaning that, at least partly, the petrodollar was supplanted just as soon as its death became inevitable. Now, just as China has moved to play a greater role in determining the price of gold by participating in the LBMA auction and by establishing a yuan-denominated fix, it's moving quickly to create a yuan-denominated oil futures contract. Here’s Reuters: China's push to establish a crude derivatives contract has been met with early scepticism, but oil executives say the country's growing economic influence means a third global crude benchmark is inevitable. A derivatives contract would give the Shanghai International Energy Exchange, known as INE, a slice of an oil futures market worth trillions of dollars, offering a rival to London's Brent and U.S. West Texas Intermediate (WTI). And while others have tried and failed, China brings its might as the world's biggest oil buyer, a strong dose of political will and the alignment of its financial and banking system for a yuan-denominated contract.

Like it or not, China's crude oil futures will be a global benchmark - – China’s push to establish a crude derivatives contract has been met with early skepticism, but oil executives say the country’s growing economic influence means a third global crude benchmark is inevitable. A derivatives contract would give the Shanghai International Energy Exchange, known as INE, a slice of an oil futures market worth trillions of dollars, offering a rival to London’s Brent and U.S. West Texas Intermediate (WTI). And while others have tried and failed, China brings its might as the world’s biggest oil buyer, a strong dose of political will and the alignment of its financial and banking system for a yuan-denominated contract. “The energy industry is still manned, literally, by people from the West. But the world moves on, and there’s a change of guard,” said a senior market executive, speaking on the sidelines of a major industry gathering in Singapore this week, at which delegates spoke on condition of anonymity. “China has become the world’s biggest oil trader, and that means that an oil price will be set there, like it or not.”

No comments:

Post a Comment