Bonds of a Malaysian offshore oil rig contractor have dropped to distressed levels, the latest sign that crude’s rebound this year hasn’t been enough to stave off pain in an industry beset by prices still about half their decade average.

Perisai Petroleum Teknologi Bhd, which contracts out drilling rigs and charters vessels for towing equipment, said on Thursday it will start discussions with holders of its Singapore dollar notes, without providing further details. Its S$125 million securities due Oct. 3 have dropped 17 cents this month to a record low 60 cents, according to prices from DBS Group Holdings Ltd.

Smaller Southeast Asian firms in the oil and gas industry are struggling along with global peers after a 49 percent collapse in oil prices in the past two years leaves them strapped for cash to pay off debt. In Singapore, Swiber Holdings Ltd. was placed under interim judicial management earlier this month and Kris Energy Ltd. said on Sunday it is exploring asset sales and refinancing as its debt covenants may come under stress.

Perisai had 36 million ringgit ($9 million) of cash and bank balances as of March 31, according to company results.

http://www.bloomberg.com/news/articles/2016-08-19/oil-debt-woes-reach-malaysia-as-offshore-rig-bonds-in-distress

The acute state of oversupply in Asian LPG markets can be best described by the title of a 1966 song by The Beatles -- "Here, There and Everywhere."

A steady influx of cargoes from the US, Iran's aggressive move to push cargoes at competitive prices, slower-than-expected demand growth in China on the back of a sluggish economy and Japan's inventory levels hovering at multi-year highs have all contributed to supply in Asia far outweighing demand, creating a glut not seen in recent years.

"For a region that is structurally short of LPG and experiences the strongest demand growth globally, Asia is currently awash with LPG supplies," Andrew Echlin, global oil products analyst at Energy Aspects, wrote in a research report on LPG titled "Hero to Zero" published this month.


Plentiful US exports, aided by VLGC rates falling to multi-year lows, have prompted gas carriers to put LPG into floating storage off Singapore. Energy Aspects said in the report that at least seven VLGCs were parked off the coast of Singapore, with some anchored for weeks.

The precarious oversupply situation has pulled down prices sharply. The price of refrigerated propane on a CFR Japan basis first plunged to a record low of $271.50/mt on July 29, dragged down by a sluggish crude complex and chronic LPG oversupply. This was the lowest since Platts started publishing this assessment in October 2006.

The first cycle propane price breached this level again on August 11. It has since rebounded and was assessed at $284.50/mt on August 15, underpinned by a firmer crude complex.

In addition to bulging supplies and slower-than-expected Chinese demand growth, propane in Asia has come under significant downward pressure as third-quarter consumption is seasonally weak, in the absence of support from winter demand.

IRAN AND CHINA

Adding to the oversupply situation is fast rising exports from Iran, from where LPG exports grew by about 54% to 1.195 million mt in 2015 from 776,000 mt in 2014, data from Joint Organizations Data Initiative showed. Over January-May this year, exports totaled 459,000 mt.

In addition, the US shipped more than 1 million mt of LPG to Asia in both June and July, well above the normal monthly volume of about 700,000 mt, Energy Aspects said.

"The supplies are also arriving [in Asia] at a time when onshore inventories of LPG are at very high levels: inventories in Japan, for example, are the highest they've been since 2008 and were almost 11% higher year on year by the end of June. Inventories are also at multi-month highs in South Korea, Australia and Thailand," Energy Aspects said, describing the oversupply scenario in the region as "Asia's all-you-can-eat buffet."

Sri Paravaikkarasu, head of downstream for Asia at Facts Global Energy, said that a few US LPG cargoes scheduled to arrive in Asia were facing the threat of being cancelled because of the lack of incremental demand.

Chinese demand for LPG has also not grown as much as expected this year, due to sluggish macroeconomic conditions and the delayed commissioning of some downstream PDH plants. LPG supplies in the past one to two years have steadily outstripped demand growth.

"China's LPG demand has not grown as quickly as some had earlier expected, mainly because new PDH capacity startups have not materialized," said Song Yen Ling, senior analyst at Platts China Oil Analytics.

Apparent demand for LPG in China could grow at a similar pace in 2016 as 2015, when it expanded by 20.5%, according to Platts China Oil Analytics.

THE SUBSTITUTION EFFECT

High LPG inventories in Asian countries had caused domestic prices in China to fall to a level at which the residential and commercial sectors had incentive to switch away from LNG-derived natural gas, analysts said.

"LNG substitution is likely already happening at refineries and petrochemical plants in Japan and South Korea, where access to storage makes switching a lot easier," Energy Aspects said. "LPG should also be attractive to Chinese buyers, although given the lack of heating demand at this time of year, switching volumes should be modest."

Gordon Kwan, head of regional oil and gas research at Nomura, said naphtha continued to take a part of the demand away from LPG. With demand for naphtha for blending soft due to weak gasoline prices, a lot of the naphtha was being diverted to the petrochemical industry.

"Until crude oil prices rise to about $60-$70/b, we might see that trend continuing," he said.

Saudi Aramco lowering its August propane contract price by $10 to $285/mt and butane CP by $20 to $290/mt was expected to trigger an influx of cheap cargoes into the region.

WINTER UPTICK HOPES

Looking ahead, buying interest could improve in Q4 on the back of the start-up of a new PDH plant in China, as well as better seasonal demand, sources said. "Everyone is piling their hopes on winter," said a Singapore-based source.

China's Oriental Energy is due to bring online its 700,000-800,000 mt/year PDH plant in October. The company is expected to increase its LPG imports by one to two shipments of 44,000 mt/month from its current imports to feed this new plant, a source noted.

The current low price and upcoming winter demand were also likely to spur the market higher from October levels, sources said.

"We remain bearish on LPG prices relative to crude throughout the remainder of Q3, but see some upside to prices in Q4 ... as a result of higher crude prices, winter heating demand and the possibility that US supply will start to fall at around that time," Energy Aspects said.

Some industry participants said the market had almost hit bottom. Chinese PDH plant operators, some of whom were ordered to stop production ahead of the G20 summit in Hangzhou, are expected to resume production and imports of LPG after the summit. The production stoppage is a move to curb pollution ahead of the summit over September 4-5.

Historical data showed that outright prices of propane rose in Q4 compared with Q3 each year between 2012 and 2015, with the exception of 2014.

Q4 usually receives a boost from winter demand for the heating fuel. In 2014 however, prices fell in Q4 due to Brent crude futures hitting 28-month lows and an abundance of cargoes arriving from the US, West Africa and Algeria, data from S&P Global Platts showed.


http://www.platts.com/latest-news/oil/singapore/analysis-for-asian-lpg-buyers-its-an-all-you-26525023

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Attached Files

Petroleos Mexicanos’ deteriorating finances are poised to get much worse, signaling no end in sight to years of declining oil production.

The company’s output may dwindle to about 1.6 million barrels a day by 2020, less than half its 2004 peak, because it lacks the technology and funds to revamp aging fields, Morgan Stanley analysts led by Martijn Rats said in a July 24 report obtained by Bloomberg. Pemex has had cash flow shortfalls for the past three years, and this year the gap will almost double to a record $22 billion, from $13 billion in 2015, according to data and estimates compiled by Bloomberg.

Once a bigger supplier to the U.S. than Saudi Arabia, Mexico’s weight has waned as the shale boom reduced American imports and the oil crash dealt a blow to hopes of luring billions in foreign investment. The country is now stuck in a vicious cycle where declining revenues from its traditional cash cow have led the government to slash Pemex’s budget, reducing further its ability to reverse the fall-off. Given insufficient liquidity and investment, Pemex will continue to shrink as it fails to restore output in areas where it lacks technical expertise, the Morgan Stanley analysts said.

“We expect some mind-the-gap issues, the private sector being hesitant in terms of long-term commitment in Mexico,” the analysts said. “Lower oil prices have exposed important shortfalls that will need to be addressed over the coming years.”

‘Reform 2.0’

The Morgan Stanley output estimate for 2020 would represent a decrease of about 700,000 barrels a day from current levels. The continued output declines have exposed flaws in the fiscal framework of the country’s 2014 regulatory overhaul that ended decades of state monopoly to seek much-needed foreign investment, according to the report. Those flaws are likely to require modification or an "energy reform 2.0," the analysts said.

The investment bank expects “a revised energy reform to be on the agenda for the next administration beyond 2018," requiring provisional measures such as additional capital injections from the finance ministry.

On May 15, the Finance Ministry assumed 184.2 billion pesos ($10 billion) of Pemex pension liabilities and transferred 47 billion pesos in bonds known as Bondes D to the company in an effort to boost its liquidity. The government also gave Pemex a capital injection of 73.5 billion pesos to pay off outstanding debts to oil service providers and absorb some of the company’s pension liabilities in April.

The cash flow shortfalls, which mean the company is spending more than it earns from operations, will further complicate efforts by Chief Executive Officer Jose Antonio Gonzalez to seek joint ventures, stabilize production and improve ailing refineries. The company’s total debt has ballooned to almost $100 billion, and it may lose its investment-grade rating from Moody’s Investors Service, which has put it on a negative watch for a possible downgrade. Pemex has also had to weather cuts of 162 billion pesos from its budget in the past two years amid the oil market rout. It’s output is set to decline for a 12th straight year.

Tax Burden

“The sharp decline in oil prices that began in late 2014 has had a negative impact on our ability to generate positive cash flows,” the company said in a May filing. A “heavy tax burden” limits Pemex’s ability to fund capital expenditures and the company “will need to raise significant amounts of financing from a broad range of funding sources,” according to the filing.

Pemex forecasts production to fall to about 2.1 million barrels a day this year, which the company aims to stabilize and slowly increase in the following years, according to an e-mailed response to questions.

Pemex’s cash gap contrasts with positive projections for Russia’s Rosneft PJSC and Colombia’s Ecopetrol SA and far exceeds an estimated $1.4 billion cash flow shortfall expected for Petroleo Brasileiro SA and the $1 billion dollar deficit for Argentina’s YPF SA, according to analysts’ estimates compiled by Bloomberg.

"There is little chance that Pemex will be able to slow the decline of production in the short term," George Baker, an analyst and publisher of Mexico Energy Intelligence, said in a phone interview. "There are opportunities to increase production, but there isn’t the money to do it."

http://www.bloomberg.com/news/articles/2016-08-18/pemex-woes-snowball-as-cash-crunch-deepens-production-plunge

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Attached Files

Exxon Mobil Corp., Chevron Corp. and Hess Corp. have agreed to bid together for rights to drill for crude in Mexico’s deepwater oil areas, according to a person with direct knowledge of the plans.

The three U.S.-based producers have reached a Joint Operating Agreement, which allows the consortium to bid to produce oil in the 10 areas up for auction on Dec. 5, according to the person, who asked not to be identified because the information isn’t public. A Joint Operating Agreement is a contract that establishes the role and obligation of each company in the accord, and designates the party that will act as the operator of a production area should it be awarded in the auction.

Mexico hopes to raise $44 billion in its first-ever sale of deepwater drilling rights in the Gulf of Mexico, located in the Perdido area near the maritime border with the U.S. and in the southern Gulf’s Cuenca Salina. Seventy-six percent of the country’s prospective oil resources are located offshore in deep waters, according to Energy Minister Pedro Joaquin Coldwell.

The country approved final legislation in 2014 to allow foreign crude producers to operate in Mexico for the first time since 1938, in an effort to reverse an 11-year decline in production. The Dec. 5 auction has been lauded by the government as the most likely to attract large foreign oil operators that possess the expertise and capital to produce crude miles below the surface of the Gulf, which Pemex has been unable to exploit because it lacks the technology to do so.

All of the 26 companies that qualified to bid in the auction, including Royal Dutch Shell Plc, Statoil ASA, and BP Plc, are expected to sign similar agreements because the government’s capital requirements for bidding are considered too large for individual producers to do so alone. Petroleos Mexicanos, the country’s state-owned oil company, announced in May that they were in talks with Exxon, Chevron and Total SA to sign agreements of mutual interest to consider the possibility of bidding together in the deepwater round.

A Joint Operating Agreement can be dissolved if one of the companies withdraws its intention to participate in the contract, and the companies may opt not to bid even if the consortium is still in place.

A Chevron spokesperson said that the company could not comment on “speculation.” Hess spokesmen didn’t immediately respond to calls and e-mails after normal business hours. Exxon would not comment on the proceedings, according to a press official at the company’s Mexico offices.

http://www.bloomberg.com/news/articles/2016-08-18/exxon-chevron-hess-said-to-be-in-joint-bid-for-mexican-oil

Saudi Arabia raised its combined crude oil and refined-product exports to 8.83 million barrels a day in June, the highest on record for that month and the latest sign of the expansion of the kingdom’s share of global markets.

The world’s largest crude exporter typically ships less oil overseas from June to September as it burns more crude to power local electricity stations and meet extra demand for air-conditioning during the sweltering summer. The surge in June exports, as reported Thursday by the Riyadh-based Joint Organisations Data Initiative, suggests the extra output went beyond what was needed to cover this seasonal increase in domestic consumption.

“The only way for Saudi Arabia to maintain oil exports and avoid loss of market share in the summer is to increase production,” said Anas Alhajji, an independent oil analyst based in Houston. “Without record high production, the Saudis would lose market share" so they will keep boosting output for at least the rest of this year, he said.

Saudi Arabia supplied its overseas customers with 7.46 million barrels a day of crude and 1.37 million of refined petroleum products in June. The combined total is the most for that month since JODI started tracking flows in 2002. Output rose to 10.55 million barrels a day from 10.27 million in May, the data show.

Market Battle

Saudi Arabia is engaged in a battle for market share with Iran and Russia and has cut prices to its customers in Asia. Iran is pushing for an increase in production following the loosening of international sanctions in January. Despite the growing competition, OPEC officials have hinted at a potential deal, including a production freeze, during the next meeting of the International Energy Forum in Algiers in late September.

Brent crude, the international benchmark, has rallied above $50 a barrel on talk of a potential freeze, despite skepticism from several analysts after a similar proposal failed in April.

“At this stage we view the mentions of a freeze as a diversion from a continued drive from Saudi Arabia to gain as much market share as it can," said Olivier Jakob, an analyst at consultants Petromatrix GmbH in Switzerland.

Saudi crude and refined products exports were 450,000 barrels a day higher in June than in the same month of 2015 and up more than 1.1 million barrels a day from June 2014. Over the same period, Iran and Iraq have also boosted exports.

Saudi Arabia told the Organization of Petroleum Exporting Countries last week that its production rose further in July, reaching an all-time high of 10.67 million barrels a day. Khalid al-Falih, the kingdom’s energy minister, last week said the country was boosting oil production not only to meet the surge in local consumption during the summer, but also "in part to meet higher demand" from overseas customers.

"We still see strong demand for our crude in most parts of the world, especially as supply outside OPEC has been declining fast, supply outages increasing, and global demand still showing signs of strength," he told the Saudi Press Agency.

Saudi Arabia’s crude oil exports in the first six months of 2016 averaged 7.52 million barrels a day, compared with 7.46 million barrels a day in the same period last year, JODI data show. Production for the period climbed to an average 10.29 million barrels a day from 10.14 million barrels a day.

http://www.bloomberg.com/news/articles/2016-08-18/saudi-arabia-s-oil-exports-at-three-month-high-as-output-climbs

A prominent Texas lawyer was acquitted on Thursday of charges he made up thousands of fake clients to sue BP Plc for damages that the oil company caused in the 2010 Gulf of Mexico spill, court records show.

Mikal Watts was among five defendants found not guilty by a Mississippi federal jury of charges related to an alleged scheme to defraud a program set up by BP to compensate people who suffered economic losses from the spill. Two other defendants were found guilty.

The U.S. Department of Justice had accused the defendants of submitting claims on behalf of more than 40,000 people who had not agreed to be represented by Watts' firm, or else were identified with stolen or bogus Social Security numbers and other personal information.

According to the indictment, one alleged victim, named Lucy Lu, who supposedly was a deckhand on a commercial seafood vessel, was actually a dog.

The convicted defendants were Gregory Warren and Thi Houng "Kristy" Le, who prosecutors said helped collect names and information.

Also acquitted were Watts' brother David Watts and Wynter Lee, who both worked for Mikal Watts' San Antonio law firm, and field representatives Hector Eloy Guerra and Thi Hoang "Abbie" Nguyen, who was Le's sister-in-law.

The Justice Department did not immediately respond to requests for comment. Mikal Watts, who represented himself at trial, and lawyers for Warren and Le did not immediately respond to a request for comment.

http://www.reuters.com/article/us-bp-spill-verdict-idUSKCN10T2JQ

Weak oil and gas prices hammered half-year profits at Australia's Woodside Petroleum and Santos Ltd on Friday, but investors sent their shares higher as both companies reported progress on cost-cutting.

Woodside, Australia's biggest independent oil and gas producer, reported a worse-than-expected 50 percent slump in first-half profit, but tweaked up its output forecast for 2016, thanks to a strong performance at its Pluto liquefied natural gas (LNG) project.

"It's really about squeezing our existing assets," Chief Executive Peter Coleman said on a conference call.

Woodside managed to cut its gas production costs by 41 percent in the June half from a year earlier.

"Those reductions are impressive," Deutsche Bank analyst John Hirjee told Woodside executives on a conference call after its earnings.

Woodside's net profit fell to $340 million for the six months to June from $678 million a year earlier, well below an average of six analysts' forecasts around $391 million.

It announced an interim dividend of 34 cents, down from 66 cents a year ago, but said it expects to produce between 90 and 95 million barrels of oil equivalent (mmboe) in 2016, up from an earlier forecast of 86 to 93 mmboe.

Despite the profit fall, Woodside's low debt means it is in a much stronger position than many peers in the battered oil industry. It has been able to snap up assets cheaply, including a recent agreement to buy a 35 percent stake in three potentially oil rich blocks off Senegal for $350 million from ConocoPhillips.

Santos Ltd, in contrast, slid to a loss in the first half of 2016, and is scrambling to slash costs and debt.

Santos reported a loss of $5 million before one-offs for the six months to June, down from an underlying profit of $25 million a year ago. Analysts forecasts were in a wide range, but most were expecting a bigger loss.

At the bottom line, Santos slid to a net loss of $1.1 billion, after booking a huge writedown on its Gladstone LNG stake, which it flagged on Monday. The project has been squeezed by a weaker outlook for LNG, having to rely on gas from other companies to help feed the plant and higher costs for that gas.

Santos cut net debt in the first half by $220 million to $4.5 billion from December last year.

Chief Executive Kevin Gallagher, in the job since February, said on Friday the company was on track to slash costs to be breakeven at an oil price of $43.50 a barrel this year. That compares with current oil prices just over $50.

Woodside shares jumped 3.3 percent, while Santos shares rose 0.8 percent. Both outpaced the broader market's gains.

http://www.reuters.com/article/woodside-results-idUSL3N1AZ5CA

Iraq has resumed pumping oil from fields operated by state-run North Oil Company (NOC) via a Kurdish pipeline to Turkey, a spokesman for the oil ministry in Baghdad said on Thursday.

About 70,000 barrels per day (bpd) are being pumped through the pipeline controlled by the Kurdish regional authorities, spokesman Asim Jihad told Reuters, giving no further details.

Pumping stopped in March due to a dispute between the government in Baghdad and the Kurdistan Regional Government (KRG) over the control of Kurdish oil exports.

The resumption of crude flows through the Kurdish pipeline should ease the financial burden on the Kurdish government that was hard hit by the collapse of oil prices two years ago.

Kurdish officials in February warned that the economic crisis could increase desertions from their Peshmerga fighters that battling Islamic State group which controls vast swathes of territory just west of their region.

The new oil minister in Baghdad, Jabar Ali al-Luaibi, expressed optimism on the day of his appointment on Monday that the problem with the Kurds could be resolved.

Kurdish forces took control of the long-disputed Kirkuk and its oilfields in June 2014 after the Iraqi army's northern divisions disintegrated in the face of Islamic State's advance.

The Peshmerga and the Iraqi army have taken back territory from the militants in northern Iraq and are preparing the final onslaught on their capital Mosul, with the backing of a U.S.-led international coalition. Iranian-backed Iraqi Shi'ite militias are also fighting Islamic State near the Kirkuk fields.

Former oil minister Adel Abdul Mahdi in March demanded that the Kurds return to a previous oil agreement or sign a new agreement in order to resume pumping through their pipeline.

The previous agreement provided for the KRG to transfer to Iraq's central state oil marketing company 550,000 bpd produced in their region, in return for a 17 percent share in the federal budget. The Kurds stopped oil transfers to the government last year, at which point they also stopped receiving federal funds.

OPEC's second-largest crude producer after Saudi Arabia, Iraq produces 4.6 million bpd, of which about 500,000 bpd from the Kurdish region and the rest from the oil-rich south.

In comments on Thursday, Luaibi said he would focus on increasing the nation's oil and natural gas output and also develop its refining capacity in order to cut its fuel imports bill, the ministry said in a statement.

http://www.reuters.com/article/iraq-oil-pipeline-turkey-idUSL8N1AZ4GY

U.S. crude oil production is holding up better than the government previously thought.

The output estimate jumped by 152,000 barrels a day for last week, the biggest increase since May 2015, according to the Energy Information Administration. Production didn’t actually increase by that amount but was modified to incorporate a “re-benchmarking” versus the agency’s Petroleum Supply Monthly, according to Jonathan Cogan, an EIA spokesman.

The weekly data could also be adjusted after the release of the agency’s monthly Short-Term Energy Outlook. The next release is scheduled for Sept. 7, according to the EIA website.

"The weekly data is based on models, with the exception of Alaska,” Cogan said. “When the monthly data or Short Term Energy Outlook differ from the weekly data, we re-benchmark”

Alaskan crude production rose by 52,000 barrels a day to 477,000 barrels in the week ended Aug. 12, the EIA said. Alaskan output has been erratic week to week the last two months amid maintenance work.

"I would caution anyone who takes the production number from one of our monthly reports and takes it as the beginning of a trend, and that’s certainly the case with the weeklies," Cogan said.

The hottest oil play in the western world is the Delaware sub-basin of the Permian in SW Texas. Producers are seeing huge increases in flow rates as they figure out proper fracking techniques. Rates are doubling from 1500-3,000 boepd! And payout times for wells are now as low as seven months-at $45 oil.

Nobody saw this coming-especially the Saudis.

Junior producers especially need fast payout times on their wells so they can recycle that money back into another well. If they have longer than 12-15 month payouts, they really can't grow within cash flow, and end up diluting shareholders through debt and continued equity raises.

In the heart of this Shale Revolution-Resolute Energy. I added it to the OGIB portfolio on July 12, and added 10,000 shares on Monday Aug. 8 at $7.32 and added another 1000 shares Monday Aug 16 at $16.27. Here is my original notice to subscribers:

The stock of Resolute Energy (REN-NYSE) has doubled in three trading days, going from $2.80 - $6.07 on the strength of huge flow rates from its Permian Basin play.

And it may double again as the market understands

This is fortuitous, as I'm studying the juniors in the Permian right now. This is the low cost oil play in North America and Permian stocks are receiving the highest valuation.

Resolute has just 15,000 bopd of production, and a whopping $490 million of long term debt-a Zombie Stock, like I wrote about last week with Athabasca Oil, Birchcliff Energy and PennWest Energy.

Investors have forsaken these heavily indebted companies for good reason. But as Resolute Energy showed us this week, when a Zombie comes back to life it can be explosive for share prices.

Now, I'm writing about this stock because I did buy 2000 shares at $5.60 today. It took me that long to notice the stock rocketing up, do the research, figure out what this thing could be worth & decide if I wanted to play or not-because this stock could still double from $6/share-IF oil holds up.

Everything changed for Resolute with just one press release (July 8) proclaiming amazing drill results- but first let me give you some quick background on Resolute.

Since the oil crash in 2014 Resolute has been selling off assets to try and stay alive. In 2015 the company sold three assets to bring down debt:

March 2015 sold non-core Midland Basin assets for $42 million
September 2015 sold its Powder River Basin assets for $55 million
November 2015 sold the rest of its Midland Basin assets for $177 million

Besides good drilling results, Resolute's most recent press release said it had sold some midstream assets and would be getting $32.5 million in cash ASAP. That hardly moves the needle on the company's $520 million of total long term debt.

A Step Change In The Permian

These recent drill results were awesome (don't worry, details are coming...) and this will significantly increase the amount of cash flow that Resolute can generate-and improve its net asset value.

A company's total leverage is determined by how much debt it has relative to its cash flow. Just as shrinking debt reduces leverage, so does increasing cash flow.

Resolute did this by getting a whole lot better at drilling wells into the Permian.

Resolute's main remaining Permian acreage is located in Reeves County in the Delaware Basin. The primary formation that Resolute is chasing on this land is the Wolfcamp A.

The last time that Resolute had released details on its Reeves county Permian production was on May 9, 2016. The company was then able to give IP30s on two recent 7,500 foot lateral wells-which came in at 1,552 boe/day and 1,475 boe/day.

Friday's release on its most recent Permian wells blew the prior (good) wells completely out of the water.

Resolute has now moved to 9,000 foot laterals and production rates are much higher. The initial production rates on these wells are hitting 3,000 boe/day with the IP30 rates expected to double those of the 7,000 foot laterals previously drilled.

With these new data points on its wells and with results from competitors with offsetting acreage, Resolute has significantly updated its Wolfcamp A type curves.

The 7,500 foot laterals are now expected to recovery 56% more oil and gas and the 10,000 foot laterals 51% more than previously believed. That is like night and day.


In addition to getting 51% more oil, Resolute said they were able to lower cost 12-18%.

Lower capex and increased flows puts the PV10 value of $10 million per well at these low oil prices. Wells costs on the longer laterals are $9.4 million and the shorter ones they're targeting $8.2 million. Ideally I want to see a PV10 that's 130-150% of the well cost, but that's...ok.

Resolute has 22,420 gross / 12,940 net acres under lease in Reeves County where it believes it has identified 255 gross Wolfcamp A and Wolfcamp B locations to drill. The company has 80% of 2016 hedged at $80/b and 25% of 2017 production at $54/b.

What is the stock worth? The secret here is that Resolute has only 15.5 million shares out. Callon has 118 million. At $6/share the Resolute market cap is $93 million. Add $490 million debt to get Enterprise Value (EV) of $583 million. Divide that by 15,000 boepd to get a per flowing barrel valuation of $38,866.67.

Per flowing boe is the weakest valuation metric to use, but consider Callon paid $80,000 per flowing boe for its latest acquisition, you get a sense Resolute stock could still run up.

If all the increase in EV to get to $80K/per flowing boe came from the stock -well, here's the stockbroker monkey math-15K x $80K=$1.2 billion - $490 million debt = $710 million market cap / 15.5 million shares = $45.8/share.

That sounds ludicrous doesn't it? That math shows why per flowing boe is the weakest metric to use.

But this is the Permian and there is a comparative bubble in the Permian. If someone paid $10/share for Resolute today, that's only $43K per flowing boe.

That's hugely accretive to Callon or Diamondback (FANG-NYSE) or Matador (MTDR-NYSE)-why wouldn't they take it over now just as type curves and EURs are increased dramatically, reducing leverage-and before the Market really catches on.

The Bonds Are Also Responding

Stock market investors weren't the only ones cheering the news from Resolute. Bond investors also like what they see. Resolute bonds that were trading for not much more than twenty cents on the dollar just a couple of months ago are now over seventy cents.

Another thing I have preached on and on about is...share counts matter. I LOVE finding low float companies with big revenues. I think it's incredible to find a 15000 boepd producer with only 15.5 million shares out. That is real leverage! That's why some monkey math takes this stock to $24-$42...of course commodity prices have to co-operate. But a low float stock in the highest value play in North America can be a lucrative and beautiful thing.

The other thing I really liked about the stock was how well it traded today-in a straight line, not all over the map. Steady and real accumulation, not a flood of profit taking from daytraders throughout the day.

The company should be able to use this news to almost get out of the woods and on the path to recovery. The value of its Permian acreage has permanently increased and will give the company several additional options to bring its balance sheet even more in line.

http://www.oilvoice.com/n/The-Saudis-Did-NOT-See-This-Coming-From-US-Oil/e5b2a3dfdf92.aspx

The Argentine government has gone back on a promise to cut crude oil prices, after last week it emerged it had reached an unofficial agreement with oil producers and refiners to cut prices at the wellhead in order to trim the gap between local and international crude prices and make life a little bit easier for refiners. The cut would have been by 2 percent a month over the next three months.

The oil industry got on board with the proposal, agreeing to put a ceiling on retail fuel prices in exchange. Prices at the pump have jumped 31 percent since the start of the year in Argentina, together with a 35-percent devaluation of the local currency. The devaluation followed the removal of capital controls, undertaken by the new government.

As Omar Gutierrez, the governor of oil-rich Neuquen region, said following a meeting with stakeholders in the oil price issue, “The national government does not have in its agenda any type of decrease in the subsidy.”

His words were echoed by Neuquen senator Guillermo Pereyra, who is also leader of the local oil workers’ union. Perreyra added that “A technical energy committee will be formed where the provincial government, producers, unions and the national government will participate.”

Crude oil prices in Argentina are being held artificially at levels higher than those on international markets in a bid to stimulate the industry and avoid large-scale job losses. The subsidies also aim at controlling inflationary pressures that have seen Argentina record an inflation rate of 46 percent in the 12 months to July.

As the deal fell through, local oil producers will continue to get US$67.50 for each barrel of Medanito crude they sell to local refineries and US$54.90 per barrel of the heavier Escalante blend. This is 10-12 percent lower than prices were in January, thanks to a cut the new government, which came into power last December, implemented.

Opposition to the removal of subsidies was expected: communities in Argentina’s oil-rich regions depend on the royalties that international oil producers pay for the crude they pump there. This leaves refiners at a crossroads: if they can’t get oil cheaper, they would have to sell their products at higher rates, which excludes lowering prices at the pump.

http://oilprice.com/Latest-Energy-News/World-News/Argentina-Reneges-on-Lower-Oil-Prices-Promise.html

Continental announced today that it has signed a definitive purchase and sale agreement with an undisclosed buyer to sell non-strategic properties inNorth Dakota and Montana for $222 million. The sale includes 68,000 net acres of leasehold primarily in western Williams County, North Dakota, and 12,000 net acres of leasehold in Roosevelt County, Montana. The sale also includes net production of approximately 2,800 barrels of oil equivalent (Boe) per day. The agreement provides for customary closing conditions and adjustments.

"This is our third sale of non-strategic assets this year, with total expected proceeds of more than $600 million. We plan to apply proceeds to reduce debt and strengthen our balance sheet," said Harold Hamm, Chairman and Chief Executive Officer.

In May 2016, the Company announced the sale of approximately 132,000 net acres of leasehold in theWashakie Basin in Wyoming for $110 million. On August 3, 2016, Continental announced it had signed a definitive purchase and sale agreement with an undisclosed buyer to sell approximately 29,500 net acres of non-strategic leasehold in the eastern SCOOP play in Oklahoma for $281 million.

"Our guidance for the year has not changed. The combination of Continental's high quality drilling inventory, strong balance sheet and $560 million investment in drilled but uncompleted wells (DUCs) provides the Company with a robust platform for high-value future growth," Mr. Hamm said. The $560 million investment includes both operated and non-operated DUCs, approximately 80% of which are inNorth Dakota.

Continental currently has approximately ­­­215 gross operated DUCs in inventory, of which approximately 165 are in the Bakken. The Company expects the total to grow to approximately 240 gross operated DUCs at year-end 2016, with approximately 190 in the Bakken. The Company said its Bakken DUCs have an average estimated ultimate recovery (EUR) of 850,000 Boe per well and can be completed at an average cost of between $3.0 million to $3.5 million per well.

http://www.prnewswire.com/news-releases/continental-resources-announces-222-million-sale-of-non-strategic-assets-in-north-dakota-and-montana-300315126.html

PTT of Thailand is set to import 5 million tons of liquefied natural gas in 2017, according to the company’s CEO Tevin Vongvanich.

In comparison, PTT is expected to import around 3 million tons of LNG in 2015.

Speaking at a news conference, Vongvanich noted that the company entered talks with a number of suppliers to work out long-term deals, Reuters reports. Among the suppliers are Shell and BP, and contract details are expected to be concluded in September.

Vongvanich added that Thailand is at the last phase of gas production due to the decline in domestic resources, and the company’s investment budget, which has been set at around US$1.25 billion will focus on the infrastructure like LNG terminal and gas pipelines.

Thailand’s energy minister Anantaporn Kanjanarat, was reported earlier in May as saying that PTT is aiming to invest about $28 million to increase the capacity of its Map Ta Phut LNG import terminal by 1.5 million tons of liquefied natural gas per year.

With the expansion completion expected in 2019, the terminal’s capacity would reach 11.5 mtpa of LNG.

http://www.lngworldnews.com/ceo-ptts-lng-imports-to-reach-5-million-tons-in-2017/

A few charterers such as Koch are looking to put naphtha on Long Range 2 tankers as floating storage in the Mediterranean region because Europe has been bursting at the seems with naphtha over the last two quarters against the background of a closed arbitrage to the Far East, sources said Wednesday.

"Koch was asking questions to put a LR2 tanker as floating storage on Tuesday, but I am not too sure if that was naphtha. Nonetheless, we declined as we don't want to lock-in the prices at such low levels given that market is very weak. But, we expect the markets to bounce back after the summer," a shipowner said.

According to market participants, there are two options for charterers to deploy a ship as floating storage. Firstly, is by putting it on time-charterer, and secondly by putting the ship on a demurrage.

The cost of putting a ship on a time-charter is around $18,000-$19,000 a day for a year, while if it goes on demurrage it's around $20,000-$21,000/day.

A few shipbrokers said Koch was looking to put naphtha into floating storage, and it's likely to get a ship on demurrage.

Sources said one LR2 loaded with naphtha was being used as floating storage in Gibraltar, while another LR2 carrying naphtha was heard on its way from the Russian Black Sea port of Tuapse to Gibraltar. This second LR2 was expected to be used as floating storage because the current contango as well as the physical discount -- CIF NWE naphtha physical cargoes were assessed Tuesday at a $6/mt discount to the September swap -- could offset the cost of demurrage.

The naphtha market has remained bearish, the September crack was trading at minus $5.70/b at noon London time Wednesday, up from minus $5.85/b at market close Tuesday, while the September/October swap spread was seen trading at minus $5.00/mt, versus minus $5.25/mt at market close Tuesday.

"We need to see the August/September spread weaken for that to be economic," a trader said when asked about the logic for keeping naphtha in floating storage.

http://www.platts.com/latest-news/shipping/london/tankers-floating-storage-eyed-for-european-naphtha-26523989

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A large shift to tight gas production in Argentina’s Neuquen basin is being driven by pricing incentives and lower costs vs. shale gas wells. However, at current costs, only the best tight gas wells break even at the incentivized $7.50/MMbtu gas price, according to analysis from research and consultancy firm Wood Mackenzie Ltd.

Tight gas production from the basin almost tripled over a 2-year period to 565 MMcfd during the first quarter, representing one quarter of the basin’s overall output, WoodMac notes, but well performance has been variable across all formations. Of the six tight gas formations studied, the median well in the Neuquen basin has a 90-day initial production (IP) rate of 2 MMcfd, with top quartile wells performing about five times higher than the bottom quartile.

Horizontal wells targeting the Mulichinco formation show the highest estimated ultimate recovery (EUR) at more than 5 bcf. The best wells in Punta Rosada are expected to achieve similar results with a vertical construction. Representative wells in the Lajas formation, meanwhile, are expected to recover a third of that volume.

“The large variability indicates that tight gas in Neuquen will continue to require a statistical development approach,” said Horacio Cuenca, WoodMac director of Latin America upstream research. “This means that large, multiwell development programs will be used to spread the productivity risk among a large number of wells. This approach is more similar to shale than to conventional developments.”

High costs, high output

WoodMac notes that longer laterals, more fracture stages, and increased water and propant usage are all factors that have been shown to enhance production but also increase well cost. Different sections of the same play also require unique considerations given variance in rock quality and thickness, pressure, and temperature.

“What is critically important is the relationship between the cost of these wells and the productivity they can achieve,” said Cuenca. “Our analysis shows that the tight gas wells with the highest costs also have the highest EURs and IP rates.”

Using type-well EURs and WoodMac’s current well-cost estimates, Mulichinco horizontal wells and Punta Rosada vertical wells, the most expensive in the basin on average, are profitable at or below the government’s $7.50/MMbtu incentivized gas price. These costs reflect a 15% reduction versus 2015 levels driven by the strong peso devaluation at the beginning of 2016. However, considerable additional reductions are still needed for type wells in these and other formations to be economic at the $5.20/MMbtu average gas price without incentives.

“Beyond discovering and focusing on the best producing sweet spots in each formation, enhancing EURs through more expensive wells—i.e. horizontal sections or targeting deep, thick formations with a high number of frac stages—seems a more plausible path for improving tight gas well economics in the short term rather than the drastic costs reductions needed with current EURs,” said Cuenca.

Capital efficiencies on IP rates in the Neuquen basin ranged $9,340-20,000/boe/d while EUR capital efficiencies ranged $13.70-29/boe. In comparison, WoodMac’s recently estimated capital efficiencies for unconventional wells within the Karnes Trough and Edwards Condensate subplays of the south Texas Eagle Ford shale showed capital efficiencies on IP rates ranging $8,000-15,000/boe/d and EUR capital efficiencies ranging $16-31/boe.

http://www.ogj.com/articles/2016/08/woodmac-tight-gas-output-triples-in-argentina-s-neuquen-basin-but-costs-still-vary.html

ExxonMobil Corp on Wednesday put off plans to shut its Baton Rouge, Louisiana refinery after it managed to start a liquefied petroleum gas (LPG) processing unit in the adjoining chemical plant, sources familiar with plant operations said.

An Exxon spokesman declined to discuss operations on specific units at the Baton Rouge refinery.

"Contrary to some reports, the ExxonMobil Baton Rouge Complex is operating," company spokesman Todd Spitler said in an email. "It is our practice not to comment on specific unit operations at our facilities. We do expect to meet contractual commitments."

Normally, the 502,500 bpd Baton Rouge refinery sends LPG to the Sorrento, Louisiana Storage Facility where it is kept underground in salt dome caverns until needed. Flooding forced the closure of the facility over the weekend, said the sources, who requested anonymity because they were not authorized to speak publicly about the matter.

The floods, centered on the Baton Rouge area, have claimed at least 11 lives and forced thousands of people from their homes.

On Tuesday, Exxon shut a 110,000 bpd crude distillation unit at the refinery to reduce LPG production and the company was prepared on Wednesday to shut the refinery if the chemical plant unit could not be started, the sources said.

The chemical plant unit will process the LPG produced by the refinery, the sources said. The refinery's production level is down to about 60 percent of capacity.

In addition to the chemical plant unit shut on Tuesday, Exxon cut production on a 210,000 bpd CDU in half for maintenance planned prior to the floods, the sources said.

Two other CDUs at the refinery have a combined capacity of 180,000 bpd. The CDUs do the initial refining of crude oil coming into a refinery and provide feedstock for all other units.

Motiva Enterprises LLC's 235,000 bpd Convent, Louisiana refinery continues to operate with only essential personnel due to flooding in the area, said sources familiar with the company's operations. They requested anonymity because they were not authorized to speak publicly about the matter.

A Motiva spokeswoman did not immediately respond to requests for comment.

Production at the refinery has been reduced since Thursday when a 45,000 bpd heavy oil hydrocracker was shut by a large fire.

https://www.yahoo.com/news/exxon-baton-rouge-refinery-shuts-cdu-due-flooding-044024758--finance.html

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The United States Federal Energy Regulatory Commission on Wednesday issued an order dismissing and terminating Downeast LNG’s applications to build an LNG import/export terminal and associated facilities in Washington County, Maine.

The project has been plagued with delays and hold-ups, with Downeast LNG requesting the commission to hold the pre-filing process in abeyance several times, first in November 2015, with the latest request filed on June 2 asking for the extension of the hold on the proceeding until September 30, 2016.

According to the FERC order, Downeast LNG requested the latest extension while it “pursued discussions with existing and potential investors to optimize the Downeast LNG project.”

Prior to the last request to hold the pre-filing process, Downeast LNG, with its majority shareholder, a private equity manager Yorktown Partners, put the company up for sale.

“We have reviewed our strategy and decided that an industrial player or a specialized investor such as an infrastructure fund is better suited to continue the permitting process and eventual build-out of the project,” George Petrides, Chairman of the Board of Downeast LNG, said at the time.

However, the commission noted that its “pre-filing process in Downeast has resulted in no significant recent progress toward the development of the bi-directional import/export project application or in stakeholder engagement.”

In the past nine months, Downeast LNG made no progress and presented nothing to persuade the commission that its situation is likely to change, FERC said, declining the latest request to hold the proceedings in abeyance until September 30.

In addition, because the project has not made progress in the pre-filing review process towards a single proposal, “its pending import application and bidirectional import/export pre-filing proceedings have become stale”, FERC said.

The proposed project was planned to have the capacity to export up to 3 million tons of liquefied natural gas per year (450 mmcf/Day) and regasify up to 100 mmcf/d.

http://www.lngworldnews.com/ferc-terminates-downeast-lng-applications/

Mad Dog, BP Plc’s drilling project deep in the Gulf of Mexico, could be Exhibit A in the oil industry’s war on cost.

When the British oil giant announced the project’s second phase in 2011, it put the price at $20 billion. Last month, after simplifying plans and benefiting from a sharp drop in everything from steel to drilling services, Chief Executive Officer Bob Dudley said he could do the job for $9 billion.

Across the industry, companies have taken a chainsaw to expenses, slashing spending for the 2015-to-2020 period by $1 trillion through cutting staff, delaying projects, changing drilling techniques and squeezing outside contractors, according to consulting firm Wood Mackenzie Ltd. That’s cushioned businesses as oil prices plunged 60 percent since 2014. Now producers seek to show they can make the savings stick, while service providers try to reverse their losses.

Industry costs “may be the defining issue of the next six to 12 months," said J. David Anderson, a Barclays analyst in New York. “As you start ramping up, the fact is you’re going to need more services and they’re going to have to come in at a higher price."

London-based BP expects 75 percent of its reductions to hold even if oil rebounds, Dudley told investors in July. In earnings reports over the last month, U.S. shale drillers said at least half of their savings are permanent improvements in efficiency. But service providers such as Schlumberger Ltd. and Halliburton Co., which perform much of the drilling and hydraulic fracturing around the globe, tell a different tale: They may have cut rates to keep business during the oil rout, but those discounts were temporary.

“Price negotiations have been a barroom brawl," Jeff Miller, president of Houston-based Halliburton, said on a July 20 conference call. “But we believe prices will recover."

Who’s right could have big implications for the oil industry and the broader economy.

U.S. benchmark oil has climbed about 18 percent since closing below $40 a barrel and slipping into a bear market this month. The grade traded at $46.77 a barrel at 12:51 p.m. Singapore time.

“A lot of the actions that we’ve taken are what we would call self-help type of things, changing the way we work,” said Stephen Riney, chief financial officer of Houston-based Apache Corp., an oil explorer. “These are things that are not dependent upon the pricing from third parties.”

While the industry has gotten more efficient, it’s likely to give back most of the gains, said Pritesh Patel, upstream director at research firm IHS Markit Ltd. About half the decline came as a strong U.S. dollar reduced the relative price of materials and labor, Patel said. Contractor discounts accounted for much of the rest, he said.

Sustaining Cuts

Producers will be lucky to sustain a third of the cost reductions, Patel predicted.

One example of a cut that may soon be lost is in the Eagle Ford Shale in south Texas, where the price to lease a drilling rig with a crew tumbled by almost a quarter in the two-year downturn to $18,208 a day, according to a Bloomberg Intelligence estimate.

Service providers say they’re getting to a point where they may no longer be able to offer such a discount. Schlumberger, Halliburton and Baker Hughes Inc., the top service companies, all reported losses in North America in the first three months of 2016.

“A large wave of cost inflation from every part of the supplier industry is now building," Schlumberger CEO Paal Kibsgaard said on a July 22 call. Profit margins, he said, are “deeply negative."

Permanent Changes

Oil explorers insist they’ve made lasting changes. In the North Sea, producers such as BP are standardizing everything from drilling equipment to the light bulbs and paint used on offshore rigs. In the U.S., companies have built out infrastructure in shale plays, installing pipelines to transport crude and wastewater rather than paying to truck it away.

In the Permian Basin in west Texas, Devon Energy Corp. has extended electricity to its well sites, allowing it to eliminate 300 rented generators, Chief Operating Officer Tony Vaughn said on an Aug. 3 call. Occidental Petroleum Corp. CEO Vicki Hollub said her company has improved well designs and can drill more quickly, accounting for about 80 percent of cost reductions.

Apache has renegotiated power, water and chemical-handling contracts and cut lease-operating expenses, a measure of drilling efficiency, by 17 percent, CEO John Christmann told analysts on Aug. 4.

Producers such as Apache and Devon are going to have to accept “the reality” of the service companies’ situation, Halliburton CEO Dave Lesar said last month.

“Some of the efficiency gains we have made with customers are in fact sustainable and will continue, but others including deep uneconomic pricing cuts are unsustainable and will have to be reversed,” he said.

http://www.bloomberg.com/news/articles/2016-08-17/bp-to-schlumberger-in-barroom-brawl-as-oil-drillers-slash-cost

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Australia's Origin Energy suspended its final dividend as it scrambles to cut debt and trimmed its guidance, after weak oil prices and spending on the A$26 billion ($20 billion) Australia Pacific LNG project nearly halved its underlying annual profit.

Australia's top power and gas retailer, whose Australia Pacific liquefied natural gas project started exporting this year just as oil and LNG prices slumped, said on Thursday it expects to cut net debt to below A$9 billion by next June.

Underlying profit fell to A$365 million ($280 million) for the year to June 2016 from A$682 million a year earlier, in line with analysts' forecasts around A$370 million.

"While the Board will review each dividend decision in light of the prevailing circumstances, the Board's view is that suspension of the dividend is in the best overall interest of shareholders," Chairman Gordon Cairns said in a statement.

The second unit of two units at the 9 million tonnes a year APLNG project is on track to start producing in the December quarter, Origin said.

The ramp up has been a bit slower than expected while the oil price slump has persisted, delaying the benefits of the massive project, one of three LNG plants that have started up side by side in Queensland since early 2015.

Origin has previously said 2015 and 2016 would be transitional years for the company, but has now pushed that out to include 2017.

"In FY2018 and beyond, as APLNG completes the transition from development to production of its LNG project, Origin expects to see significant growth in earnings and returns, strong cash flow and continuing reduction in debt," Origin Chief Executive Grant King said in a statement.

With both APLNG units operating, the company said it expects underlying earnings before interest, tax, depreciation and amortization to rise by at least 45 percent to between A$2.37 billion and A$2.6 billion in the year to June 2017, roughly matching market forecasts.

But excluding LNG, the 2017 guidance worked out to $1.8 billion to $1.95 billion, which was lower than the company flagged in February.

"We anticipate a negative reaction to the guidance downgrade," Royal Bank of Canada analyst Ben Wilson said in a note, who added that the suspension of the dividend was expected.

http://www.reuters.com/article/us-origin-energy-results-idUSKCN10T068

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The oil-and-gas well BP PLC is drilling here in the Texas Panhandle looks ordinary enough from the surface. Yet a mile-and-a-half underground, horizontal pipes shoot off for at least a mile in three directions, like a chicken’s foot.

The idea, part of an experiment by BP executive David Lawler, is to make three wells from one. It also is designed to help turn the London-based energy giant into a shale-oil innovator that can better compete with the entrepreneurial outfits that pioneered the business of hydraulic fracturing, or fracking.

Big oil companies like BP are in need of a jolt. The multibillion-dollar projects they specialize in—giant offshore oil rigs and gas-export projects—are often prohibitively expensive in a world of $45-a-barrel oil. U.S. wells are a tempting option, but major oil companies have yet to prove they can master the techniques pioneered by shale drillers, whose innovations fueled a rebirth in U.S. energy production.

London-based BP is moving into shale-oil drilling with wells such as the King Harry 1H in the Texas Panhandle, which descends 8,000 feet before splitting into three shafts. 

If BP, Exxon Mobil Corp. and others can figure out how to coax enough oil out of fracked wells cheaply enough to make it profitable, it could help them maintain production levels. Failure could make it harder to replace the oil from declining older megaprojects, and leave them further behind on innovations transforming the industry.

Six years after the Deepwater Horizon accident in the Gulf of Mexico caused the worst offshore spill in U.S. history, BP is turning again to America. Mr. Lawler, a former college football linebacker turned engineer, is in charge of the push into shale oil and gas. If the Perryton well succeeds, Mr. Lawler could try the same thing with drilling leases BP has in Oklahoma, Texas and beyond, potentially yielding oil and gas on a large scale.

He isn’t the only Lawler in the fracking business. His older brother, Robert, known as Doug, is chief executive of Chesapeake Energy Corp., the trailblazer founded by fracking pioneer Aubrey McClendon, who died in a car crash in March.

The Lawler brothers are part of the second wave of the fracking revolution: a move away from debt-fueled drilling mania to what they hope will be a more financially sustainable future.

Doug’s challenge is to take debt-laden Chesapeake and its attractive drilling leases and turn it into a profitable business. David’s mission is to crack the code of shale drilling for BP, something that the world’s biggest energy companies haven’t been good at.

Processes designed for huge offshore platforms are a poor fit for fracking, which requires endless tinkering to be successful. Frackers must also develop a substantial tolerance for failure. They often must drill dozens of wells to figure out the best techniques for particular locations.

So far, big oil companies have compiled a poor record in U.S. fracking. Their fracked wells don’t produce as much as those of industry leaders because they haven’t mastered the technology. They have taken more than $20 billion in write-downs, some stemming from top-of-the-market acquisitions of fracking companies, and the plunge in crude prices has made things worse. Exxon has lost money in its U.S. drilling business for six straight quarters.

In 2014 and 2015, shale wells drilled by BP, Royal Dutch Shell PLC, Exxon and Chevron Corp. were one-third less productive, on average, than the top 10 operators, according to data from analytics firm NavPort. Their wells have improved each year, but so have those of the top operators. Many big companies—often called “integrated” firms because they have production and refining operations—say they are getting better and have drilled some profitable wells.

“You have to be quick, you have to be nimble, you have to be flexible,” says shale pioneer Mark Papa, former chief executive ofEOG Resources Inc. “The track records of the integrateds is really not very pretty.”

David Lawler, 48 years old, acknowledges the challenges BP faces trying to go small. Exxon, Shell and Total SA all notched losses or write-downs from their shale businesses, even before oil prices began falling two years ago.

Yet Mr. Lawler says he is optimistic that BP can make shale profitable at today’s prices, even if it isn’t blessed with what others in the industry see as good rock—land in the country’s most prized oil-and-gas basins. “It’s about how fast we can change,” he says.

http://www.wsj.com/articles/too-big-to-frack-oil-giants-try-again-to-master-technology-that-revolutionized-drilling-1471362741

Last week MDN was the first to share the news that the California-based US Methanol is building at least two, rumoured up to five, methanol plants in the Mountain State.

MDN shared a rumour (based on a source) that until we disclosed it, was not public knowledge: The first methanol plant they will build will be in Institute, WV, and the second in Belle, WV–both in the Charleston region.

We now have confirmation of that rumour via several news accounts. We also told you that both plants were being disassembled in other countries and brought here.

http://marcellusdrilling.com/2016/08/us-methanol-confirms-mdn-rumor-2-or-more-plants-coming-to-wv/

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 U.S. crude oil refinery inputs averaged about 16.9 million barrels per day during the week ending August 12, 2016, 268,000 barrels per day more than the previous week’s average. Refineries operated at 93.5% of their operable capacity last week. Gasoline production increased last week, averaging 10.3 million barrels per day. Distillate fuel production increased last week, averaging over 4.9 million barrels per day.

U.S. crude oil imports averaged 8.2 million barrels per day last week, down by 211,000 barrels per day from the previous week. Over the last four weeks, crude oil imports averaged over 8.4 million barrels per day, 11.3% above the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 610,000 barrels per day. Distillate fuel imports averaged 92,000 barrels per day last week.

U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) decreased by 2.5 million barrels from the previous week. At 521.1 million barrels, U.S. crude oil inventories are at historically high levels for this time of year. Total motor gasoline inventories decreased by 2.7 million barrels last week, but are well above the upper limit of the average range. Finished gasoline inventories increased while blending components inventories decreased last week. Distillate fuel inventories increased by 1.9 million barrels last week and are near the upper limit of the average range for this time of year.

Propane/propylene inventories rose 1.8 million barrels last week and are at the upper limit of the average range. Total commercial petroleum inventories increased by 1.3 million barrels last week. Total products supplied over the last four-week period averaged about 20.8 million barrels per day, up by 1.4% from the same period last year. Over the last four weeks, motor gasoline product supplied averaged about 9.8 million barrels per day, up by 1.7% from the same period last year. Distillate fuel product supplied averaged over 3.7 million barrels per day over the last four weeks, up by 0.3% from the same period last year. Jet fuel product supplied is up 6.0% compared to the same four-week period last year.

Cushing down 800,000 Bbl

http://ir.eia.gov/wpsr/wpsrsummary.pdf

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                                             Last Week   Week Before  Last Year
Domestic Production   '000...... 8,597            8,445          9,348
Alaska '000................................. 477               425             438

http://ir.eia.gov/wpsr/overview.pdf

Eagle Ford rig productivity has doubled in 18 months, from 550 to 1,100 B/d per rig. Better than Moore’s law!



@PTertzakian

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Nissan’s new petrol engine could make advanced diesel engines obsolete.

The new engine – called a Variable Compression-Turbo (VC-T), has 27% better fuel economy than previous models but provides comparable power and torque.

It’s also cheaper than today’s advanced turbo-charged diesel engines and should meet emissions rules in most countries without requiring costly treatment systems.

“We believe this new engine of ours is an ultimate petrol engine that could over time replace the advanced diesel engine of today,” Kinichi Tanuma, a senior Nissan engineer said.

James Chao, Asia-Pacific Managing Director at consultant IHS said: “Increasing the fuel efficiency of internal combustion engines is critical to automakers. Not all consumers will accept a battery electric vehicle solution. But significant challenges remain, such as increased complexity and cost, as well as potential vibration issues.”

The VC-T powertrain is expected to be officially unveiled at next month’s Paris motor show.

http://www.energylivenews.com/2016/08/17/diesels-splutter-as-new-petrol-engine-emerges/

China's state planner has proposed new rules regulating the cost of transporting natural gas by pipeline that analysts say will lower prices in order to boost consumption of the cleaner-burning fuel.

The government will use an "allowed cost plus reasonable margin" scheme in setting the transportation cost for natural gas, the National Development and Reform Commission (NDRC) said on Wednesday on its website.

Under the proposal, natural gas pipeline operators will fix their transportation prices by compiling the cost of their fixed assets such as pipelines and storage, operating costs and depreciation, and then adding a fixed 8-percent margin to those costs, the NDRC said.

However, the 8 percent margin only applies to pipelines with a capacity utilization higher than 75 percent, the NDRC said, without stating what the margin would be for pipelines using less than 75 percent of their capacity.

The lower margin should lower the gas costs for consumers as the current margin pipelines are making is believed to be higher than the 8 percent proposed by the NDRC.

Analysts said the changes underscore Beijing's plan to lift sagging demand growth for natural gas, seen as the most efficient fuel to cut greenhouse gas emissions in the world's largest emitter and tackle air pollution. China is the world's third-largest gas consumer.

"The new regulation should help reducing the cost of natural gas," said Diao Zhouwei, a Beijing-based analyst with IHS. "China's reform of its natural gas pipeline is moving toward its planned direction. Focusing on tightening pricing regulations as well as lowering the cost through better transparency."

Previously, transportation cost were set by the NDRC based on the individual pipeline projects. This new proposal would apply across companies rather than by specific pipeline.

http://www.reuters.com/article/us-china-gas-pricing-idUSKCN10S10I

Industrial gas buyers have been forced to consider importing LNG at a Sydney or Melbourne port to ensure a competitive supply of gas due to what they say is a major failing of energy policy that has left manufacturers stranded and put jobs on the line.

Manufacturing Australia chairman Mark Chellew said initial studies showed gas could be imported from the US at a price of about $6 a gigajoule, about a third less than prices some industrial users are facing by 2018.

"If we got to that stage it would be a major fundamental policy flaw of all governments," Mr Chellew said. "It is a flaw that we've got to the stage of having to seriously consider it."

Mr Chellew partly blames the "over-zealous" drive into renewable energy by some state governments for contributing to the energy difficulties that erupted in South Australia in June and which he says risk spreading across the eastern states.

At the same time, the onshore gas ban in Victoria, difficulties with NSW gas and a tripling in demand for gas on the east coast due to the new Queensland LNG export industry have squeezed supplies for manufacturers, chemical producers and power generators.

"We jumped off a cliff around 15 years ago and we haven't yet invented the parachute," Mr Chellew said of the policy failings that led to the current fix, which has left local gas buyers short of supplies at the same time as Australia is set to become the world's biggest LNG exporter by 2019.

"We are supportive of the federal renewable energy target but we need to make sure that the energy grid in Australia is stable and able to supply electricity continuously to industry. The stability of the grid is dependent on sufficient coal or gas-fired power stations."

Seeking solutions

Mr Chellew's comments come ahead of Friday's meeting of federal and state energy ministers in Canberra which will cover potential solutions to the energy supply problems evident in South Australia in June, including new inter-state power interconnectors and boosting gas supply.

Manufacturing Australia, whose members include Brickworks sand BlueScope Steel, wants LNG imports to be among options under discussion, given government would need to take a lead in aggregating demand and making it happen. It has raised the idea with Federal Energy and Resources Minister Joel Frydenberg and the energy ministers in NSW and South Australia.

"They are aware that the level of frustration in industry has got to the point where this is on the table," said executive director Ben Eade.

The concept is based on a project in Lithuania, which started LNG imports in late 2014 to gain independence from Russian gas giant Gazprom. A re-designed LNG carrier, moored permanently at the the coastal city of Klaipeda, is refuelled by LNG tanker and turns the super-chilled fuel back into gas and feeds it into the pipeline network.

According to consultancy Gaffney Cline, gas could be supplied using a similar vessel at a port in Brisbane, Sydney or Melbourne for as little as $6 a gigajoule assuming demand of at least 100 petajoules a year. That compares to $8-$10 a gigajoule that some manufacturers face in 2018.

The analysis assumes current low US gas prices and includes processing into LNG, shipping and regasification. The cost of offloading gas from the vessel into the network and piping it to the user would add about $1 a gigajoule.

"It is something we really do not want to do," Mr Chellew said. "But maybe they've got to seriously look at that as an alternative to where we're at. We would hope there is a lifting of the ban on onshore gas development around Australia. We think that's a better solution."

The concept is similar to one raised cynically by Shell Australia chairman Andrew Smith in an address in June when he suggested importing LNG into Port Botany could be the only answer to onshore gas moratoria. But he cautioned the benefits were unlikely to outweigh the costs.

Weak spot prices

EnergyQuest consultant Graeme Bethune said the outlook for several years of weak LNG spot prices meant the idea was "certainly worth pursuing".

"The way to do it would be a floating regasification terminal; they can be put in place pretty quickly and pretty cheaply and then it would be a matter of looking at different points and the connections to infrastructure. One of the challenges would be aggregating enough willing buyers."

In early July spot prices for gas on the east cost approached $45 a gigajoule as an extended cold snap across the eastern states combined with the impact of intermittent renewables generation in South Australia and rising demand for gas from the Gladstone LNG industry. That pushed Adelaide spot prices up to average $13.90 a gigajoule in July, about 65 per cent more than the raw Japanese LNG import price. Prices to Japanese industrial users would be about 30 per cent more than the import price, Dr Bethune said.

"Gas prices are substantially higher in Australia than they are abroad," Mr Eade said. "You don't just sit back and accept that: if there are other ways you can access the true international price for gas then they need to be looked at."

Read more: http://www.afr.com/business/energy/gas/fedup-east-coast-gas-buyers-hatch-lng-import-plan-20160816-gqu01l#ixzz4HavQdtvT
Follow us: @FinancialReview on Twitter | financialreview on Facebook

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Imports of liquefied natural gas (LNG) by South Korea, the world’s second-largest buyer of the chilled fuel, dropped 15.2 percent year-on-year in July, according to the customs data.

South Korea imported 1.92 million mt of LNG in July, as compared to 2.26 million mt in the corresponding period in 2015.

The country paid US$584 million for July imports, down 44 percent on year, the data showed.

Most of the LNG imports in July came from Qatar (822,265 tonnes), down 25.8 percent as compared to July in 2015.

The rest of South Korea’s LNG imports in July were sourced from Indonesia, Oman, Malaysia, Australia, Angola, Brunei, and Russia.

To remind, state-owned Kogas that handles almost all of the LNG imports into South Korea saidlast week its sales volume dropped 2.8 percent in the first half of this year to 16.75 million mt of LNG.

The company’s sales into the power sector dropped down 8.2 percent in January-June as South Korea used more coal and nuclear for power generation.

Kogas sold 2.19 million tonnes of LNG in July,  a rise of 15.2 percent on year.

 http://www.lngworldnews.com/south-korea-lng-imports-down-15-2-pct-in-july/

A “hijacked” Malaysian oil tanker is thought to have been taken in a commercial dispute, a news report said.

The MT Vier Harmoni vessel was believed to be sailing from the Malaysian port of Tanjung Pelepas when it went missing earlier this week.

The ship, whose cargo of 900,000 litres of diesel is estimated to be worth £300,000, is now thought to be off the Indonesian island of Batam.

A Malaysian Maritime Enforcement Agency (MMEA) spokesman told Reuters that there was “no element of terrorism involved in the tanker’s disappearance”.

The authority said the ship may have been taken following a financial dispute between the vessel’s management and crew, which suggests a mutiny has taken place, not a hijacking.

https://www.energyvoice.com/oilandgas/asia/117107/update-pay-dispute-not-terrorism-behind-malaysian-tanker-hijacking/

The state can’t pay, so someone has to. And the water keeps rising.

From 5,000 feet up, it’s difficult to make out where Louisiana’s coastline used to be. But follow the skeletal remains of decades-old oil canals, and you get an idea. Once, these lanes sliced through thick marshland, clearing a path for pipelines or ships. Now they’re surrounded by open water, green borders still visible as the sea swallows up the shore.

The canals tell a story about the industry’s ubiquity in Louisiana history, but they also signal a grave future: $100 billion of energy infrastructure threatened by rising sea levels and erosion. As the coastline recedes, tangles of pipeline are exposed to corrosive seawater; refineries, tank farms and ports are at risk.

“All of the pipelines, all of the things put in place in the ’50s and ’60s and ’70s were designed to be protected by marsh,” said Ted Falgout, an energy consultant and former director of Port Fourchon.

Louisiana has an ambitious -- and expensive -- plan to protect both its backbone industry and its citizens from this threat but, with a $2 billion deficit looming next year, the cash-poor state can only do so much to shore up its sinking coasts. That means the oil and gas industry is facing new pressures to bankroll critical environmental projects -- whether by choice or by force.

“The industry down there has relied on the natural environment to protect its infrastructure, and that environment is now unraveling,” said Kai Midboe, the director of policy research at the Water Institute of the Gulf. “They need to step up.”

Every year in Louisiana, more than 20 square miles of land is swallowed by the Gulf. At Port Fourchon, which services 90 percent of deepwater oil production, the shoreline recedes by three feet every month. Statewide, more than 610 miles of pipeline could be exposed over the next 25 years, according to one study by Louisiana State University and the Rand Corporation. Private industry owns more than 80 percent of Louisiana’s coast.

The land loss exacerbates another natural threat: storm-related flooding, like that affecting Baton Rouge now. About 40,000 homes in southeastern Louisiana have been affected by devastating flooding, and at least 8 people have died. The flooding occurred after some areas received more than 26 inches of rain over a three-day period, causing water to overrun levees along several tributaries.

Barrier islands, marshes and swamps reduce storm surge and soak up rainfall like a sponge. But as the land erodes, storms advance without a buffer, and Louisiana's flood protection systems become less effective. The state estimates that damage from flooding could increase by $20 billion in coming years, if the coastline isn't reinforced.

Lots More: http://www.bloomberg.com/news/features/2016-08-17/louisiana-s-sinking-coast-is-a-100-billion-nightmare-for-big-oil

OPEC is on course to strike an output-freeze deal with fellow oil producers in Algiers next month because its biggest members are already pumping flat-out, the group’s former president said.

While a similar initiative failed in April, an agreement can now be reached as Saudi Arabia, Iran, Iraq and non-member Russia are producing at, or close to, maximum capacity, Chakib Khelil said in a Bloomberg Television interview. Khelil steered OPEC in 2008, the last time it implemented an output cut, which was announced in Algeria in December of that year.

“All the conditions are set for an agreement,” Khelil said from Washington. “Probably this is the time because most of the big countries like Russia, Iran, Iraq and Saudi Arabia are reaching their top production level. They have gained all the market share they could gain.”

While oil prices have advanced since OPEC announced it would hold informal talks in the Algerian capital next month, analysts from UBS Group AG to Commerzbank AG doubt any freeze deal will be completed, and comments from Saudi Arabia and Nigeria have kept expectations low. Talks collapsed in April as Saudi Arabia insisted Iran would have to limit its production, a condition the country rejected as it ramped up exports previously curbed by sanctions.

As producers are almost pumping at full-tilt, the impact of any accord to prevent further increases would essentially be “psychological,” Khelil said. That would nonetheless have a benefit for the market, according to the Algerian, who was also the country’s energy minister from 1999 to 2010.

The global crude oversupply is already diminishing, and markets will probably reach “complete equilibrium” next year, Khelil said.

http://www.bloomberg.com/news/articles/2016-08-17/opec-s-former-head-says-conditions-are-right-for-oil-freeze-deal

Iran's crude oil exports in July were more than 2.1 million barrels per day, the oil ministry's news agency SHANA cited a senior Iranian oil official as saying on Wednesday.

Director of the International Affairs Department at National Iranian Oil Company (NIOC) Mohsen Ghamsari told SHANA the total amount of crude and gas condensate exports by Iran reached 2.740 million bpd in July. He said 600,000 bpd out of that figure were condensate exports.

"Exports of crude are now at a good level but ... have not yet touched that of the pre-sanction level," he said, adding that Iran used to export 2.350 million barrels of crude per day before international sanctions were imposed.

Ghamsari did not give a figure for Iran's oil exports in June but a source with knowledge of the country's crude lifting plans had told Reuters exports that month were about 2.31 million bpd.

http://www.reuters.com/article/iran-oil-exports-idUSL8N1AY268

U.S. crude oil inventories are down just over 1 million barrels for the week ended 12 August, according to the weekly American Petroleum Institute (API) report, but U.S. gasoline inventories are up over 2 million barrels in the biggest increase in six months.

Cushing crude inventories were down 680,000 barrels.

Earlier today, crude oil rallied to a one-month high, but slid back down following the release of the API data. West Texas Intermediate (WTI) for September delivery closed at US$46.58 on the New York Mercantile Exchange, but was down to US$46.41 in electronic trading at the time of writing.

Analysts expectations, as carried by S&P Global Platts, were for a 200,000-barrel drawdown on U.S. crude oil inventories, with the API figures coming at roughly half that. But for gas, the API figures were unexpected. Analysts were tapping a 1.8-million-barrel drop in gasoline inventories, while the API is showing a nearly 2.2-million-barrel increase. Distillates were also up significantly over the week, with the API data showing a 2.4-million-barrel build.

This should contribute to further market volatility, though Zero Hedge notes that oil is primarily tracking the dollar right now and not paying as much attention to its own fundamentals.

More attention will be on the official inventory data coming tomorrow at 10:30am (EST) from the Energy Information Administration (EIA), which could contradict API data, as has been a recent trend.

Last week, the API reported the opposite—the biggest crude oil inventory build in three months, and a draw on gasoline stocks. That API report had crude inventories up 2.09 million barrels, and gasoline stockpiles down 3.9 million barrels, with distillates at a 1.5-million barrel draw.

The EIA last week reported a 1.1-million-barrel rise in commercial crude oil inventories for the week to August 5, with the total reaching 523.6 million barrels. The week before that also saw a 1.4-million-barrel build.

The API data should be good news for oil prices, but the surprise gasoline and distillates build skews the picture.

http://oilprice.com/Latest-Energy-News/World-News/API-Drop-in-US-Crude-Oil-Stocks-But-Surprise-Gasoline-Build.html

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China's crude oil stocks rose by 525,000 b/d in July, half the build seen in the same month of last year due to lower crude supply and higher throughput, although the country is still on its way to raise its stockpiles, calculations by S&P Global Platts based on latest official data showed.

The stock increase was 8.5% faster than the 484,000 b/d registered in the previous month, and within the range of a relatively stable build level as June, which fell significantly from a sharp build-up of over 1 million b/d each in the months of May, April and March.

China does not release official data on stocks. Platts calculates China's net crude stock draw or build for the month by subtracting refinery throughput from the country's crude supply.

The latter takes into account domestic crude production and net crude oil imports.

Crude supply in July stood at 11.24 million b/d, which was the lowest level since December and also 2.1% lower than that in last July, due to a slowdown in crude oil imports as well as lower domestic crude oil output.

Crude oil imports fell to a six-month low of 7.35 million b/d as independent refiners' buying cooled from the wave started in December last year.

Meanwhile, domestic crude oil output hit the lowest level of 3.95 million b/d since October 2011, when was recorded at 3.91 million b/d. Chinese producers have decided to cut domestic production in 2016 to reduce cost amid low crude prices.

At the same time, crude oil throughput saw a 2.5% year-on-year increase, but fell 2.7% from June.

Looking forward, China is expected to continue building crude stocks, given that throughput would stay at the July level or lower because of weak oil products demand in August.

Moreover, the country is continuing to fill its strategic petroleum reserves, including new sites in northeastern China's Jinzhou (18.9 million barrels) and southern China's Yangpu (9.69 million barrels).

Analysts also expect the new Huizhou storage in southern China and Zhoushan Phase II in eastern China, each 31.45 million barrels in capacity, to start taking in crude oil next year.

Over January-July, the country's crude stocks grew by an average 778,000 b/d, equivalent to 165.80 million barrels over the period.

This was 80% higher than the 432,000 b/d, or 91.67 million-barrel build seen in the same period last year. China had built 186 million barrels of crude stocks over 2015, averaging 510,000 b/d.

http://www.platts.com/latest-news/oil/singapore/china-data-crude-stocks-rise-by-525000-bd-in-27648644

Nigeria’s losses in daily oil production due to militant attacks have hit 900,000 barrels, said Petroleum Minister Ibe Kachikwu, speaking to CNN. He added that the federal government is in talks with the militant groups responsible for this cut in production in the Niger Delta, saying that over the next couple of months, the negotiating parties will hopefully reach an agreement that will put an end to the attacks.

“We are producing some 1.5 million barrels per day and would need on average 900,000 barrels per day to catch up on what we have lost. If we can achieve peace, this will be feasible,” Kachikwu said.

This, however, would go counter to what other OPEC members are planning, or rather hoping, to do at the next informal meeting of the cartel in Algeria next month. The minister expressed doubt as to the success of such a plan, citing the meeting in Doha earlier this year, initiated by Russia, which was ready to put a cap on oil production in a bid to prop up prices, and the participants’ failure to agree on such a cap.

Attacks on production and transportation infrastructure in the Niger Delta have taken their toll on Nigeria, which used to be Africa’s biggest exporter of crude. The groups responsible for the attacks insist that local communities are being deprived of their fair share of oil revenues, left to live in poverty and pollution.

Last week, a former federal minister, Femi Fani-Kayode tweetedthat Nigeria’s President Muhammadu Buhari was basically fed up with the attacks and was ready to split the country if oil was struck in the North.

“My prayer for Nigeria is that oil is found in commercial quantities in the core north. I am glad that @MBuhari is looking for it desperately. If he finds it he and the north will be the first to call for a break up of the country. If he fails to find it they will continue to be the greatest obstacle to the restructuring of our nation and they will continue to provide the greatest opposition to the peaceful division of our country. Why? Because without southern oil the north is nothing,” the former aviation minister wrote.

http://oilprice.com/Latest-Energy-News/World-News/Nigeria-Oil-Losses-Reach-900000-Bpd-Due-to-Militant-Attacks.html

Yesterday MDN’s favourite government agency, the U.S. Energy Information Administration (EIA), issued our favourite monthly report–the Drilling Productivity Report (DPR).

The DPR is the EIA’s best guess, based on expert data crunchers, as to how much each of the U.S.’s seven major shale plays will produce for both oil and natural gas in the coming month.

The EIA projects natural gas production cumulatively across all shale plays will once again fall in September–the seventh consecutive month it will have fallen.

However, as was the case in last month’s report, the Utica stands alone and against the trend by showing an increase in production month over month. Last month the EIA predicted the Utica would increase production by 5 million cubic feet per day, or MMcf/d.

This month’s report shows the Utica is expected to increase production by an average of 9 MMcf/d.

Also of note, last month Marcellus production was projected to drop by 26 MMcf/d, while this month the production drop is projected to be 33 MMcf/d. That is, the rate of production decline in the Marcellus is accelerating.

http://marcellusdrilling.com/2016/08/eia-august-dpr-utica-production-up-marcellus-down/

The New York Stock Exchange (NYSE) has certain minimum standards if a company wants to continue trading stocks on the exchange:

The company’s stock price must be trading for at least $1 per share, and the company’s market capitalization must be at least $50 million. Market cap is pretty easy to calculate: it’s the number of outstanding shares times the per-share price. If you have 50 million shares of stock and the price is trading for $1/share, you’re there. You meet the NYSE’s requirements.

Various companies with operations in the Marcellus/Utica have fallen short and have been warned by the NYSE that unless they get their act together, they would be de-listed. Some turned it around (see Eclipse Resources Dodges a Bullet – Stock Won’t Get De-Listed), and some didn’t (seeMagnum Hunter De-Listed from NYSE; Still Shopping Eureka Hunter).

Halcon Resources, a driller with 140,000 Utica acres it doesn’t bother to drill on, was warned in June by the NYSE that their share price, trading under $1/share, is too low. In July Halcon filed for bankruptcy. The NYSE has just issued another warning to Halcon: the company’s market capitalization has now fallen below $50 million…

http://marcellusdrilling.com/2016/08/halcons-market-cap-falls-below-50m-nyse-threatens-to-de-list/

Concho Resources Inc. today announced it has reached a definitive agreement to acquire approximately 40,000 net acres in the core of the Midland Basin from Reliance Energy, a privately held, Midland-based energy company, for $1.625 billion. The privately negotiated acquisition is consistent with Concho's opportunistic and disciplined portfolio management strategy as it expands its core Midland Basin position to more than 150,000 net acres and production of 30 thousand barrels of oil equivalent per day (MBoepd).

Acquisition Highlights

Adds approximately 40,000 net acres with an average 99% working interest to Concho's core Midland Basin position
Includes approximately 10 MBoepd (67% oil) of current production
Enhances the Company's drilling inventory with more than 530 long-lateral drilling locations targeting the Middle Spraberry, Lower Spraberry and Wolfcamp B
Provides expansive development upside across multiple zones

Tim Leach, Chairman, Chief Executive Officer and President, commented, 'This transaction demonstrates Concho's commitment to the Midland Basin as a core operating area and highlights our continued efforts to consolidate complementary leasehold. In line with the objectives of our southern Delaware Basin acquisition in the first quarter of 2016, these assets not only build scale, but more importantly high-grade our inventory with additional long-lateral locations that compete with the best projects in the Permian Basin. As we continue to enhance our ability to efficiently allocate capital across our four key assets in the Permian Basin, we are uniquely positioned to deliver attractive returns today and build shareholder value over the long term.'

The acquisition includes 10 MBoepd from 326 vertical wells and 44 horizontal wells, only one of which was completed in 2016. The present value of this stable production base at current NYMEX strip pricing is approximately $0.5 billion, with the remaining $1.1 billion of the purchase price attributable to 40,000 undeveloped acres.

Estimated proved reserves attributable to the acquisition total approximately 43 million Boe. Proved developed reserves represent approximately 69% of the total proved reserves. The estimate of proved reserves is based on the Company's internal estimates as of June 30, 2016, and utilizes the Securities and Exchange Commission's reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices of $39.63 per Bbl of oil and $2.24 per MMBtu of natural gas.

The acquired acreage is located in Andrews, Martin and Ector counties in Texas with minimal leasehold obligations. The acquisition adds more than 530 long-lateral drilling locations to the Company's inventory. Due to the contiguous nature of the acquired assets, two-thirds of these locations are two-mile laterals, and the remaining locations are 1.5-mile laterals. The engineered locations are based on eight locations per zone in the Middle Spraberry, Lower Spraberry or Wolfcamp B, with two to three of these zones targeted per drilling spacing unit. The Company believes there is substantial development upside from applying optimal drilling and completion methods, testing closer well spacing and delineating other zones.

Consideration in the transaction includes approximately $1.1 billion of cash and 3.96 million shares of Concho's common stock valued at approximately $0.5 billion and issuable pursuant to a stock payment option that the Company intends to exercise. The Company intends to fund the cash portion of the acquisition through proceeds from a potential equity market transaction, subject to market conditions and other factors. The acquisition is expected to close in October 2016, and is subject to customary closing conditions.

http://www.oilvoice.com/n/Concho-Resources-announces-Midland-Basin-acquisition/dd73c988a849.aspx?utm_source=twitterfeed&utm_medium=twitter&utm_campaign=Feed%3A+OilvoiceHeadlines+%28OilVoice+Headlines%29

Norway’s oil production hit a five-year high last month, fuelled largely by output from Eni’s Goliat field in the Barents Sea.

http://www.upstreamonline.com/live/1441461/goliat-boosts-norway-output?utm_source=twitterfeed&utm_medium=twitter

The long decline in Venezuela’s oil production is becoming a supply risk for international markets, according to a report by Columbia University’s Center on Global Energy Policy.

Exports from the holder of the world’s largest crude reserves fell more than 300,000 barrels a day in June, compared with the 2015 average, according to the report written by Luisa Palacios, a senior managing director at Medley Global Advisors LLC. While Venezuela’s output has been declining all year, the impact is only now being felt on international markets because previous losses were offset by slumping domestic oil demand amid anunprecedented economic recession.

“Venezuela will represent a growing supply risk for oil markets in 2017,” the report said. “While on average crude oil exports in the first half do not yet show an important decline from the same period a year ago, the latest data point to a deteriorating trend.”

Venezuela has been hit hard by the two-year slump in crude prices. Its economy is expected to shrink 10 percent this year, the largest contraction in more than a decade, while consumer prices rise more than 700 percent, according to the International Monetary Fund. The nation’s output dropped to a 13-year low in July as international oil services companies scaled back their activities after state-run Petroleos de Venezuela SA fell more than $1 billion behind in debt repayments.

Falling Consumption

Venezuela’s crude production in July dropped to 2.15 million barrels a day, compared with an average 2.4 million last year, the International Energy Agency said on Aug. 11.

As the nation’s economy contracted, domestic demand for oil dropped by more than 100,000 barrels a day last year compared with 2014, the Columbia University report said, citing data from the Ministry of Oil and Mining. While it’s possible that Venezuela’s domestic consumption will keep falling, there are signs the lower production is now affecting exports, it said.

Venezuela’s strategy of focusing on the expansion of oil production in a region called the Orinoco belt is also bringing in fewer dollars. The heavy crude is less desirable to refiners and typically sells for less than lighter grades of oil that are easier to process into fuels such as gasoline.

The Venezuelan crude basket, based on an average of all crudes handled by the state oil company, widened its discount to West Texas Intermediate, the U.S. benchmark, to about $9 a barrel on Aug. 12, compared with about $1 a year earlier.

Blending the heavy oil with higher-priced light crudes purchased from other exporters can make it more marketable, but is a costly option for a country that’s on the brink of debt default, the report said. Should credit concerns prevent Venezuela from importing the light oil it needs, net exports could fall by another 300,000 barrels a day, the Columbia report said.

“The continuation of this strategy will significantly eat into the government’s oil rent, and thus its ability to export its way out of this crisis,” the report said.

Venezuela’s is renewing efforts to get the Organization of Petroleum Exporting Countries and nations outside the group to cooperate. Oil minister Eulogio del Pino met his Iranian counterpart in Tehran Sunday, although the Persian Gulf nation hasn’t decided if it will attend a meeting of producers to discuss stabilizing prices on the sidelines of an energy forum in Algiers next month.

“Venezuela was already having economic problems when the oil price was at $100 per barrel,” so a price recovery is unlikely to solve its predicament, according to Columbia’s report.

http://www.bloomberg.com/news/articles/2016-08-16/venezuela-oil-exports-seen-falling-as-economic-woes-worsen

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- In the second quarter of 2016 the Corporate Group reported net income of COP $787 billion, 117% higher than in the first quarter of 2016. For the first half of the year our net income totaled COPS$1,150 billion.

- With the receipt of Rubiales and Cusiana fields, Ecopetrol achieves a new landmark as a world-class operator with more than 500 thousand barrels per day.

- We accomplished our target: the startup of the 34 units of Cartagena Refinery. Now moving forward to the stabilization phase.

In the view of Ecopetrol S.A.'s CEO, Juan Carlos Echeverry G.:

"April marked my first year leading Ecopetrol. A year characterized by a sharp drop in oil prices, challenging the oil and gas industry. We also witnessed a strong El Niño weather phenomenon, the closure of the border with Venezuela and attacks on transport infrastructure.

The renewal of the management team, the adjustment and austerity measures, as well as the focus on profitable production and the preservation of both cash flow and leverage metrics have enabled Ecopetrol to navigate the price scenario and present positive operating and financial results in the second quarter of 2016.

Net income attributable to Ecopetrol shareholders reached COP$787 billion, 117% higher as compared to the first quarter of 2016, thanks to a 34% recovery in Brent crude price, a decrease in our operational costs and structural savings efforts. Our EBITDA margin remained solid at around 39%.

In the second quarter of 2016 the Company reported savings of COP$392 billion pesos, for a cumulative COP$813 billion pesos for the first semester. The savings target for 2016 is COP$1.6 trillion pesos.

We raised COP$725 billion from the divestment of part of our stake in Interconexión Eléctrica S.A. E.S.P.(ISA) and Empresa de Energía de Bogotá S.A. E.S.P. (EEB). Further, we launched "Ronda Campos 2016", an initiative to offer our interest in 20 minor oil fields located in Catatumbo, Middle and Upper Magdalena Valley, Llanos and Putumayo regions.

Ecopetrol received Rubiales and Cusiana fields and now operates more than 500 thousand barrels per day. The Rubiales field gave us 53 thousand barrels per day of additional production, partially offsetting the impact of lower investments in other assets and the temporary suspension of some fields.

The Company successfully completed the startup process of the 34 units that comprise the Cartagena Refinery.

In the last sixteen months we have comprehensively renewed our management team, attracting people with broad experience and an important record in major international oil and gas companies.

It is the case of the Chief Operating Officer, Chief Financial Officer, Chief Transformation Officer; as well as the Vice-presidents of Refining, Social and Environmental Sustainability, Legal Affairs, and most regional Vice Presidents; additionally, new people will soon arrive to lead in Procurement and in Transportation. Finally, two vice-presidencies were created: Engineering and Projects, and Compliance.

The transformation plan has 500 ongoing tasks. These initiatives have already begun to materialize in Ecopetrol's results. For example, the dilution cost reduction initiative, which is part of the efficiency front, has reduced Ecopetrol's diluent purchases by almost 14 thousand barrels per day. The cumulative savings in 2015 and the first half of 2016 amounted to COP$726 billion pesos. This initiative is crucial for viable production projects in heavy crudes that represent 57% of the Corporate Group's oil production.

The Company's priority has been the protection of the cash flow. In the second quarter of 2016 the cash balance was strengthened with resources from divestments and the international loan with the Export Development Canada (EDC) for US$300 million as well as the reopening of the international bond due to 2023 for US$500 million, a clear sign of the capital markets' confidence. With these resources Ecopetrol has fulfilled close to 85% of its financing needs for 2016. Moreover, Standard and Poor's and Fitch Ratings reaffirmed the BBB investment grade rating for Ecopetrol.

The Company's 2017-2020 business plan is being reviewed in line with our forecasted price scenarios and our efficiency gains achieved, these gains could be even greater in the future. We hope to present our updated medium-term goals no later than October of this year.

Ecopetrol continues its transformation in order to position itself as a competitive player, strengthening its exploration and production portfolio to capture opportunities arising from a fundamental recovery in oil prices, and increasing structurally efficiency in Refining and Transport to ensure financial sustainability and creation of value for its shareholders."

http://www.prnewswire.com/news-releases/ecopetrol-group-announces-its-results-for-the-second-quarter-and-first-half-of-2016-300313892.html

The impending startup of Qatar Petroleum's new condensate-fed refinery has led to a sharp reduction of deodorized field condensate supply in the spot market, providing a much-needed boost to Asian ultra-light crude suppliers looking to clear October cargoes, market participants said Tuesday.

Lofty premiums paid for Qatar's Low Sulfur Condensate for loading in October caught some Asian end-users by surprise and the price outlook for both Asia and Middle East ultra-light crudes took a positive turn due to the shortage of DFC cargoes.

Latest market talk in Asia indicated that Qatar International Petroleum Marketing Co., or Tasweeq, has recently sold two 500,000-barrel cargoes of LSC in pre-tender deals to South Korean end-users at premiums in the range of $1.50-$1.70/b to Platts front-month Dubai crude oil assessments, sharply higher than the $1.10/b premium received for September-loading LSC last month.

S&P Global Platts assessed LSC at a premium of $1.40/b Tuesday, the highest level since posting a $1.45/b premium on June 29.

With Tasweeq's sell tender closing late afternoon is Asia Tuesday, trade sources said very little was heard on any pre-tender deals for DFC for loading in October, a possible indication that the vast majority of October DFC supply could have been set aside for the new Laffan Refinery 2.

"There's no DFC being offered, but I expect to see one done [via tender]," said a Singapore-based condensate trader.

Qatar Petroleum in its latest annual report said Laffan Refinery 2, or LR2, was expected to be fully operational in the third quarter. Industry sources this week expected this to occur in late September.

The new facility will be able to process an additional 146,000 b/d, raising Laffan Refinery's total processing capacity to 292,000 b/d, the state-run petroleum company said in the annual report.

Regional ultra-light crude traders said the number of DFC cargoes in the spot market could drop to as low as one or two per month if the LR2 condensate refinery runs at 50% or more of its capacity early in the startup phase.

"We are witnessing a severe lack of DFC supply in the market this month. Normally Tasweeq and some term lifters would sell five cargoes at least [in pre-tender deals] but there's hardly any available this time around," said a North Asian crude trader.

"When you assume LR2 running at maximum capacity of around 146,000 b/d, that would roughly equate to about 9 DFC cargoes... the market impact would be quite substantial if you consider this," the North Asian trader added.

Construction of LR2 began in April 2014, and the shareholders in the second refinery are QP (84%), Total (10%), Idemitsu (2%), Cosmo (2%), Mitsui (1%) and Marubeni (1%).

The refinery, with a nameplate capacity of 146,000 b/d, will have the capacity to produce 60,000 b/d of naphtha, 53,000 b/d of jet fuel, 24,000 b/d of gasoil and 9,000 b/d of LPG.

CONDENSATE PRICE DIFFERENTIALS SEEN SUPPORTED

Market participants said despite the tepid light distillate product margins of late, suppliers of both sweet and sour condensates around the region would likely adjust their selling ideas higher in a bid to take full advantage of the sharp decline in DFC supply.

"Many had initially anticipated another month of bear market due to the sliding naphtha cracks and the unsold August and September overhang... but I guess the tide could turn," said another Singapore-based crude trader. Last market talk in Australia indicated that Woodside Petroleum could have sold a 650,000-barrel cargo of North West Shelf condensate for loading over October 11-15 to a South Korean buyer at a discount of around $2/b to Platts Dated Brent crude assessments.

It was said to have sold a NWS cargo for loading in September 2-6 at a discount of around $2.30/b in the previous trading cycle.

"I think the splitters might pay more if they are really worried about the DFC supply," said another North Asian crude trader.

However, many traders continued to adopt a cautious stance as tepid naphtha crack values and ample condensate supply from Southeast Asia and Oceania could put a cap on any upside in cash differentials for regional ultra-light crudes.

Latest Platts data showed the second-month naphtha to Dubai swap crack fell below the minus $4/b mark to minus $4.07/b Monday, the lowest level in more than 15 months. The spread was last wider on May 8, 2015, at minus $4.20/b.

The crack value has averaged minus $2.37/b to date this month, compared with minus $1.60/b in July and minus $0.77/b in June.

The last time the average monthly naphtha crack was lower was in July 2015 at minus $2.75/b.

http://www.platts.com/latest-news/oil/singapore/qatar-dfc-shortage-a-boon-for-asian-condensate-27647927

China is expected to produce over 20 billion cubic feet of shale gas per day (bcf/d) by 2040, becoming the world's second largest producer after the United States, said the U.S. Energy Information Administration (EIA) on August 15.

The production will account for more than 40% of the country's total natural gas production by 2040, the EIA predicted.

In the past five years, China drilled more than 600 shale gas wells and produced 0.5 bcf/d of shale gas as of 2015, said the EIA in its International Energy Outlook 2016 and Annual Energy Outlook 2016.

The U.S. shale gas production will stay in the first place as it is projected to more than double from 37 bcf/d in 2015 to 79 bcf/d by 2040, accounting for 70% of total U.S. natural gas production, said the EIA.

Canada is now the world's second largest shale gas producer, producing 4.1 bcf/d in 2015. Its shale gas production is projected to continue increasing and will reach less than 10 bcf/d, accounting for almost 30% of its total natural gas production by 2040.

Shale gas will also become the major drive of the world's natural gas growth in the next 24 years, said the EIA.

The world's shale gas production by 2040 is expected to quadruple the level in 2015 and reach 168 bcf/d, accounting for 30% of world natural gas production. The world's natural gas production is expected to increase by about 62% during the same period of time.

http://old.en.sxcoal.com/0/151450/DataShow.html

Wood Group PLC shares were steady in early trade after good and bad news statements cancelled each other out.

The ‘good’ first and the landing of a US$700mln a field services contract with Tengizchevroil in Kazakhstan.

This was tempered by the interim results, which revealed the company is still hostage to the depressed oil price.

As a major supplier to the industry its unsurprising its revenues (down 17% at US$2.6bn) and its earnings (off 26% at US$166mln) have taken a battering.

Against this backdrop, and with debts of US$351mln, some will be a little surprise Wood Group managed to hike the dividend 10% to 10.8 cents per share.

The payment is perhaps echoes a sense of cautious optimism detected in the comments of chief executive Robin Watson.

“Looking further ahead, we see early indications of modest recovery in some areas and believe our customer relationships, geographic footprint, strong financial footing and relentless focus on delivering value through our asset life cycle services and specialist technical solutions, position us well,” he told investors.

http://www.proactiveinvestors.co.uk/companies/news/129365/wood-group-still-hostage-to-depressed-oil-price-129365.html

Oil exploration company Cairn Energy Plc raised its best estimate of reserves at its oilfields off the coast of Senegal by almost a third on Tuesday, following successful appraisal of the SNE-4 test well earlier this year.

The company said its 2C resource estimate, or its best estimate of contingent resources, for its Senegal wells had increased to 473 million barrels from its earlier forecast of 385 million barrels in May.

Cairn Energy also said that independently verified estimates of reserves in its Senegal fields were more than 2.7 billion barrels, with further exploration potential of about 500 million barrels in the region.

http://www.reuters.com/article/cairn-energy-outlook-idUSL3N1AX2D5

A recent judge's decision that overturned Obama administration rules on hydraulic fracturing on federal and Indian lands ignores more than a century of regulatory precedent, an attorney appealing that decision said Monday.

"The decision ignores decades of case law," said Mike Freeman, a Colorado-based attorney with Earthjustice. "We respectfully think that the judge got it flat wrong."

On Friday, Earthjustice, along with the Sierra Club, filed opening briefs with the 10th US Circuit Court of Appeals in an appeal case that may ultimately determine whether the federal government can regulate fracking.

The US Department of the Interior also filed briefs arguing that a century of legal precedent and federal regulations allow the agency's Bureau of Land Management to regulate fracking.

"BLM has the authority to oversee resource extraction on federal and Indian leases, including well-stimulation activities, to protect natural resources and the environment," Interior wrote. "BLM and its predecessors have been doing so for nearly 100 years, and modern hydraulic fracturing operations simply are a new version of historically regulated well stimulation techniques."

In March 2015, BLM finalized new rules that included new chemical disclosure, well construction, and fluid disposal requirements for fracking operations on federal and Indian land. Production on those lands currently accounts for about 5% of total US oil supply, according to the US Energy Information Administration.

Industry groups, including the Western Energy Alliance, and states, including North Dakota and Wyoming, successfully sued to have the rules overturned.

In June, US District Court of Wyoming Judge Scott Skavdahl ruled that Interior's fracking rule was "in excess of its statutory authority and contrary to law."

In his decision, Skavdahl wrote that his decision did not deal with whether fracking is "good or bad for the environment," just whether Interior had authority to regulate the practice.

Freeman with Earthjustice called Skavdahl's ruling a "legal error," and claimed that BLM was simply updating its regulations for the first time in roughly 30 years.

"These aren't radical requests," Freeman said. "Most of the requirements are industry best management practices."

Freeman said that answers from petitioners in the case to the briefs filed last week, including responses from the states and industry groups fighting the rules from taking place, are due by September 16. Replies to those answers are due October 7 and, Freeman said, he expects oral arguments in the case will begin before the end of the year.

The appeal could be decided in early 2017.

http://www.platts.com/latest-news/oil/washington/in-appeal-of-us-fracking-ruling-arguments-center-21253330?hootpostid=e543a179a923a7ea608f0539d71c4477

The Russian edition of Forbes Magazine is reporting that French Oil giant Total has laid off 70 percent of its Russian workforce through its office in Moscow.

The dismissed staff members are said to have two months’ salary in compensation. Russian media reports indicate that 200 out of 600 employees were laid off, and the balance were transferred to the state owned oil company Zarubezhneft.

Earlier in August, the company transferred 20 percent of its Kharyaga oilfield production-sharing agreement and operator’s functions to Zarubezhneft. As far as the reason behind the transfer, Total CEO Patrick Pouyanne stated: “Amid low crude prices we need optimize our assets as well as put a priority on spending management.” Pouyanne said that an experienced Russian company would be able to establish working relationships with contractors in the area.

Among the reported reasons for the move by Total was a withdrawal from the Kharyaga project and sanctions from the west that would prohibit Total from delivering equipment to the project.

The Russian edition of Forbes, citing an unnamed employee, said that Total had planned to attract technology from America and Europe to the project, but that sanctions blocked the plans. Total had been the biggest foreign investor in Russian oil prior to selling its stake in the Kharyaga project. The project itself aims to develop a pair of oilfields in the Nenets Autonomous region, which produced 1.5 million tons of crude in 2014.

In related news, while Total is in the process of pulling out of the Kharyaga project, Russian oil company Rosneft said last week that its overall hydrocarbon production for the second quarter of 2016 was up due to that country’s drilling boom. Oil production for the second quarter was at 4.1 million barrels per day, which is 0.5 increase from the prior period.

http://oilprice.com/Latest-Energy-News/World-News/French-Total-Lays-Off-70-percent-Of-Its-Russian-Workforce.html

Oil flows through the Kurdistan Regional Government's export system fell sharply in early August due to pipeline outages and production declines following recent attacks on an oilfield in northern Iraqi, a number of sources have confirmed.

While the recent pipeline outages were due to a technical glitch which may already have been rectified, analysts expect the loss of output from the Bai Hassan oil field, where saboteurs have damaged production facilities and heightened concerns for future security, to last for months.

The KRG's pipeline to Turkey, which is the only pipeline currently exporting crude from northern Iraq, has been down for about 80 hours so far this month, an international oil company official familiar with pipeline operations said.

The outages have been caused by an electricity transmission malfunction at the PS-3 pumping station in Silopi, just over the border in Turkey, said the IOC official, an industry official in Erbil, and an industry official at Turkey's Ceyhan port.

In July, the export pipeline sent 511,000 b/d of crude to market, the KRG Ministry of Natural Resources reported in early August.

The pipeline first went down on the afternoon of August 5, the Ceyhan official said. He and the IOC official said exports resumed briefly on the morning of August 7, but only for a few hours.

Exports came back online early August 9, initially flowing at 458,000 b/d, the Ceyhan official said.

Temporarily bolstered by crude from storage built up at producing fields during the pipeline outages, exports had risen to 573,000 b/d by Thursday but were unlikely to stay at that rate, the official said.

Assuming the pipeline stays online, KRG exports for the rest of this month are expected to be significantly lower than the July average following a July 31 attack on the 170,000-180,000 b/d Bai Hassan oil field northwest of Kirkuk.

REPEATED SABOTAGE ATTACKS

The field lies outside the semi-autonomous Kurdistan region's official border with the rest of Iraq, but for the past two years has been contributing to export flows through the KRG pipeline, after repeated sabotage attacks by insurgents closed the Iraqi federal government's northern export pipeline. Bai Hassan has been operated by the KRG since late 2014, following the Islamic State group insurgency in much of northern and western Iraq that peaked in summer of that year

The July 31 attack, which authorities have also attributed to IS, caused the 70,000 b/d southern section of the field to be shut down, several officials familiar with operations said. Bai Hassan South remains offline, industry officials said.

A subsequent attack August 10 struck a different section of Bai Hassan but had a negligible effect on production. Saboteurs also planted improvised explosive devices along the pipeline connecting Bai Hassan and the Avana Dome of the Kirkuk field to the KRG export system, Kirkuk security officials said.

In response to the loss of Bai Hassan crude exports, the KRG ministry of natural resources has redirected some crude production previously earmarked for domestic consumption to the export pipeline.

The 100,000 b/d Kalak refinery near Erbil, the Kurdistan regional capital located less than 100 km north of Kirkuk, has been offline since August 4 due to lack of feedstock, government and industry officials in Erbil said. The refinery had been taking between 30,000 and 40,000 b/d from the KRG-operated Khurmala Dome of the Kirkuk field, but that production has been diverted to the export pipeline.

The KRG's other major refinery, Bazian, located in the east of the Kurdistan region, is also operating at reduced capacity due to the crude diversions. An industry official briefed on operations at Bazian said the refinery had recently been taking between 20,000 and 25,000 b/d of crude for processing and would likely be operating at that level until Bai Hassan's production recovers.

Bazian's current capacity is at least 40,000 b/d. In 2014, Qaiwan Group, the local company that owns and operates the refinery, announced plans to increase that to 125,000 b/d by 2018.

In another setback for the KRG, which depends almost exclusively on crude export revenues to finance government operations, the quality of KRG export crude has suffered following the attacks on Bai Hassan. The IOC official said recent loadings at Ceyhan, the current delivery point for all KRG crude exports, have had a higher API gravity, higher sulfur content and more water than usual.

http://www.platts.com/latest-news/oil/erbil/northern-iraq-crude-oil-exports-dive-on-pipeline-26522012

Cheniere files for permit to begin commissioning of Sabine Pass LNG Train 3

The Houston-based Cheniere Energy filed a request with the United States Federal Energy Regulatory Commission to introduce fuel gas and begin commissioning activities for Train 3 at the Sabine Pass LNG terminal.

According to the filing, the company requested the approval to introduce gas to Train 3 to be granted no later than August 19.

http://www.lngworldnews.com/cheniere-files-for-permit-to-begin-commissioning-of-sabine-pass-lng-train-3/

Futures slid as much as 0.7 percent in New York after rising 9.7 percent the previous three sessions following comments by Saudi Arabia’s energy minister that it’s prepared to discuss stabilizing the market. Nigerian Petroleum Minister of State Emmanuel Kachikwu signaled that production cuts are unlikely from OPEC, according to a Twitter post. U.S. crude stockpiles probably rose for a fourth week, a Bloomberg survey shows before government data Wednesday.

Oil has gained about 15 percent since closing below $40 a barrel and tumbling into a bear market earlier this month. Russia is open to talks to jointly freeze output “if necessary,” according to a newspaper report. A possible deal on capping production between members of the Organization of Petroleum Exporting Countries and non-member producing countries was first flagged in February but deal discussions in April ended with no final accord.

“The OPEC comments have caught the market’s attention, but history would suggest that nothing will happen,” said David Lennox, a resources analyst at Fat Prophets in Sydney. “While falling U.S. supply has helped to narrow the surplus, OPEC hasn’t helped. The group has continued to pump. It’s really only disruptions that have reduced supply.”

West Texas Intermediate for September delivery lost as much as 32 cents to $45.42 a barrel on the New York Mercantile Exchange and was at $45.51 at 12:18 p.m. in Hong Kong. The contract climbed $1.25 to $45.74 on Monday, capping the biggest three-day gain since April 12. Total volume traded was about 32 percent below the 100-day average.

Output Freeze

Brent for October settlement slid as much as 37 cents, or 0.8 percent, to $47.98 a barrel on the London-based ICE Futures Europe exchange. Prices added 2.9 percent to close at $48.35 on Monday, the highest settlement since July 12. The global benchmark crude traded at a $1.93 premium to WTI for October delivery.

Russia sees no signals that Iran will change its position on a production cap and agree to an output freeze, Interfax reported, citing a diplomatic source close to the talks whom the news service didn’t identify. Russian Energy Minister Alexander Novak told Arabic-language newspaper Asharq Al-Awsat that the nation was open to cooperating to stabilize markets after Saudi Arabian Energy Minister Khalid Al-Falih said that talks in Algiers may result in action.

OPEC members will discuss the market when they gather for the International Energy Forum in Algeria next month, according to Mohammed bin Saleh Al-Sada, Qatar’s energy and industry minister and the group’s current president.

http://www.bloomberg.com/news/articles/2016-08-15/oil-trades-above-45-amid-opec-production-freeze-speculation

Libyan forces loyal to eastern-based military commander Khalifa Haftar have entered Zueitina and established a presence about 10 kilometers (6 miles) from the city’s oil terminal.

Photos on local media websites showed a small number of Haftar’s Libyan National Army troops arriving to cheers. The port is under force majeure and is controlled by the Petroleum Forces Guards linked to the United Nations-backed unity government, or GNA, in Tripoli.

Haftar spokesman Ahmed Mismari said in a news conference on Aug. 11 that his force wasn’t planning to capture the port and only wanted to protect Libya’s wealth. He couldn’t be reached on Monday to explain why LNA troops had moved from positions they held over the weekend, something Mismari had earlier ruled out.

Nearly nine months after the unity government was formed in Tunis and four months since Prime Minister Fayez al Serraj arrived in Tripoli, Libya remains divided. In June, UN envoy Martin Kobler told the Security Council that a buildup of armed forces in the so-called oil crescent raised the possibility of conflict between groups that had gathered there to confront Islamic State.

Six Western countries -- Germany, Spain, the U.S., France, Italy and the U.K. -- on Aug. 8 called for all parties to avoid any damage to oil infrastructure at Zueitina.

Oil Slump

Libya’s oil output has dropped 85 percent as factions fought for control of natural resources during the five years since the ouster of Muammar Qaddafi. As a result foreign-currency reserves have plunged, deficits widened and now worsening living conditions are causing unrest.

Zeid Ragas, an independent analyst based in Benghazi, said any attempt by Haftar to take Zueitina port would be self-destructive.

“The move was made by Haftar to widen his control on the ground and overcome achievements made by the GNA across the country," he said. “But with warnings by the international community and tribes in the area, any action is going to be suicidal."

http://www.bloomberg.com/news/articles/2016-08-15/libyan-forces-under-haftar-move-closer-to-zueitina-oil-terminal

More good news for Dominion’s $5 billion, 594-mile Atlantic Coast Pipeline–a natural gas pipeline that will stretch from West Virginia through Virginia and into North Carolina.

In March MDN reported Dominion has agreements for 96% of the capacity along the 1.5 billion cubic feet per day pipeline. Not only that, but 90% of the landowners along the pipeline’s proposed route have granted Dominion survey access and many of them have signed easements allowing Dominion to build the pipeline across their land.

The new news is that the Federal Energy Regulatory Commission (FERC) has set June 30, 2017 as the date by which the agency will issue their final environmental impact statement for the project.

http://marcellusdrilling.com/2016/08/atlantic-coast-pipeline-makes-progress-ferc-timing-announced/

Did Putin just spoil the Oil party?  

RUSSIA DOESN'T SEE OIL OUTPUT FREEZE AT OPEC TALKS IN SEPT: IFX

This whole ramp was driven by chatter of Russia and Saudis talking which has now been denied...

http://www.zerohedge.com/news/2016-08-15/oil-surges-16-lows-despite-russian-denial-output-freeze-opec-talks

Rosneft PJSC’s second-quarter profit decreased about 34 percent, coming in better than analysts estimated, even as a recovery in oil prices sputtered out at below last year’s price levels.

Net income fell to 89 billion rubles ($1.4 billion) in the second quarter from 134 billion rubles a year earlier, according to the Moscow-based company. That was higher than the 83 billion-ruble average estimate of nine analysts surveyed by Bloomberg News. Revenue dropped 7.9 percent to 1.23 trillion rubles.

A rout in commodities prices has Russia facing its second year of recession. The government is considering selling nearly 20 percent of Rosneft, the nation’s biggest company, as early as this year to help fill a gap in its budget. State finances have borne the brunt of oil’s crash. The companies themselves have been sheltered by a progressive tax system.

Earnings before interest, taxes, depreciation and amortization were 348 billion rubles, according to the statement. That compared with an analyst estimate of 307 billion rubles.

Free cash flow came in at $1.3 billion, while Sberbank CIB estimated just below $1 billion in an Aug. 9 note. Net debt fell to $23.4 billion from $23.9 billion at the end of the first quarter.

http://www.bloomberg.com/news/articles/2016-08-15/rosneft-second-quarter-profit-falls-34-as-oil-recovery-stalls

Rosneft is targeting higher spending this year as higher oil prices boosted the bottom line of the Russian state-owned oil company in the second quarter.

http://www.upstreamonline.com/live/1441408/profits-boost-for-rosneft?utm_source=twitterfeed&utm_medium=twitter

Jabbar al-Luaibi, the former head of Iraq’s biggest crude producer who was appointed oil minister on Monday, said that he sees ways to resolve the energy dispute with the self-governed Kurds in the north of OPEC’s No. 2 producer.

Al-Luaibi’s appointment was approved by parliament on Monday as part of a government reshuffle, according to a statement by deputy parliament speaker Humam Hamoudi. Al-Luaibi is former head of the state-owned South Oil Co. which produces most of the country’s crude. He replaces Adel Abdul Mahdi who had suspended his participation in the cabinet in March, citing disarray in government ministries.

The new minister told local news service Alsumaria soon after his appointment that there are “various ways to resolve” the conflict with the Kurdish region of Iraq which has split control of the country’s crude exports. He also said that Iraq will seek local investment to develop its natural gas industry.

Iraq, the second-biggest producer in the Organization of Petroleum Exporting Countries, holds the world’s fifth-largest oil reserves. The drop in crude prices over the past two years has squeezed state revenue as the government waged a costly campaign against Islamic State militants who have seized parts of northern Iraq. Iraq produced 4.36 million barrels a day in July compared with 4.44 million at the end of last year, according to data compiled by Bloomberg.

Crippled Exports

Prime Minister Haidar al-Abadi said the cabinet reshuffle was part of reforms, according to a statement on his website. Al-Abadi’s efforts to shuffle the cabinet have been repeatedly blocked by lawmakers.

More than 13 years after the U.S.-led invasion that ousted former President Saddam Hussein, Iraq’s finances are being drained by the oil-price plunge and the political bickering that has delayed efforts to tackle graft and sectarian divisions. The country has lost sales and revenue from its northern region as a payments dispute with the Kurds and interruptions to the flow of oil for export through a pipeline to Turkey have crippled shipments.

Al-Luaibi, who has a bachelor of science in chemical engineering, has worked in Iraq’s oil business since 1973, according to a copy of his resume provided by his office.

http://www.bloomberg.com/news/articles/2016-08-15/iraq-appoints-oil-minister-as-costly-war-limits-growth-in-output

Hedge funds increased their bullish long positions in crude oil by the most for over two months in the week ending on Aug.9.

Hedge funds and other money managers boosted net long positions in the three major Brent and WTI futures and options contracts by the equivalent of 48 million barrels.

The increase in net long positions was the largest since the middle of May and comes after hedge funds cut net long positions by a total of 309 million barrels between May 17 and Aug. 2.

Hedge fund managers seem to have reacted to the prospect of a short-covering rally after short positions reached exceptionally high levels ("Oil short-selling cycle may be at or near a turning point", Reuters, Aug 10).

Hedge funds had previously amassed short positions in Brent and WTI totalling 374 million barrels, the third-largest short position on record and only 19 million barrels below the maximum short position ever recorded.

The scale of short positions made a rally highly likely once prices stopped falling and funds started close some positions to lock in previous profits.

In the week between Aug. 2 and Aug. 9, hedge funds continued to add an extra 1.5 million barrels of short positions in NYMEX WTI.

But that was a much smaller increase in short positioning than during the previous weeks, when hedge funds added an average of 35 million barrels of short positions per week.

And in Brent, hedge funds cut short positions by 19 million barrels, the largest one-week reduction since January.

TURNING BULLISH

With short covering creating a strong bid in the market, other fund managers raced to add fresh long positions to profit from the expected rally in prices.

Hedge funds added an extra 19 million barrels of long positions in WTI and 11 million barrels of long positions in Brent, according to data published by regulators and exchanges.

The rise in combined Brent and WTI long positions was the largest one-week increase since the middle of May.

The short-selling cycle that lasted from May 31 until Aug 2 now appears to have turned.

Both Brent and WTI prices have increased by more than $5 per barrel, around 13 percent, since Aug. 2, as hedge funds have scaled back short positions and started to turn more bullish.

VERBAL INTERVENTION

The short-covering rally has been accelerated by carefully timed comments from Saudi Arabia and other oil exporters seemingly talking up the possibility of an output agreement at informal talks next month.

In official comments published on Saturday, after leaking on Thursday, Saudi Energy Minister Khalid al-Falih noted "the large short positioning in the market" which has "caused the oil price to undershoot".

Al-Falih described current prices as "unsustainable" and said oil prices would have to rise from current levels to reverse the decline in investment.

He reiterated that Saudi Arabia was watching the market closely and was ready to take action to help rebalance the market in cooperation with OPEC and major non-OPEC producers.

Al-Falih specifically noted the ministerial meeting in Algeria next month would provide an informal opportunity to discuss the market situation "including any possible action that may be required to stabilise the market".

While the comments were no different to previous statements made by Saudi officials over the last 12 months, their timing and carefully scripted nature have been interpreted as a deliberate attempt to influence prices.

By hinting at the possibility of an output agreement, the minister's verbal intervention has added to the short-term risk of holding short positions and fuelled the rally.

http://www.reuters.com/article/oil-global-kemp-idUSL8N1AW2R2

Despite challenging market conditions, global capital expenditure (Capex) on FLNG facilities is forecast to increase significantly over the 2016-2022 period. The protracted oil price downturn has impacted the sanctioning of capital intensive liquefaction units over the last 24 months. However, the need to move towards cleaner sources of energy and diversify gas supply has stimulated the floating regasification market - over 14 countries are expected to commission their first floating import unit over the forecast period.

These are some of the findings from Douglas Westwood's (DW) latest World FLNG Market Forecast with global FLNG Capex expected to total $41.6 billion (bn) during 2016-2022, compared with $11.4bn 2011-2015 - an increase of 264%. Report author, Mark Adeosun, commented, 'Liquefaction vessels will account for approximately 59% of forecast expenditure, with the remaining 41% allocated to import and regasification terminals. Near-term growth in expenditure will be predominantly driven by a number of flagship liquefaction projects sanctioned prior to the oil price downturn.

'Global expenditure is expected to peak in 2017 as the first wave of sanctioned projects come onstream. Reduced project sanctioning will likely impact the market towards the end of the decade - with expenditure forecast to decline significantly in 2019 - before stagnating over the 2019-2021 period. Long term prospects are positive; a marginal uptick in spending is expected in 2022 driven by the sanctioning of a second wave of capital intensive liquefaction projects. Over the forecast period, Africa and Asia will be key areas for liquefaction and regasification units - with both regions accounting for 54% of total global expenditure. Spend in Australasia is set to decline post 2018 after the installation of the Prelude FLNG.

'Despite near-term concerns, the long-term viability of FLNG technology is clear. In the decades ahead, natural gas will continue to play an increasingly important role in meeting global energy demand. Furthermore, the rising cost of onshore development terminals and the shorter lead times of floating units make the technology a viable option in the current market environment.'

http://www.oilvoice.com/n/Forecast-FLNG-spend-of-over-41-billion-following-wave-of-landmark-projects/d5aefdcd73e9.aspx

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Attached Files

Russia's Economy Ministry has advised Prime Minister Dmitry Medvedev he would have to issue an unprecedented special decree if he wants to bar state-controlled oil major Rosneft (ROSN.MM) from the privatization of a mid-sized energy group, according to a letter seen by Reuters.

The planned auction of a 50 percent stake in state-owned oil producer Bashneft (BANE.MM) later this year will pit some of Russia's most powerful businessmen, executives and officials against each other if Rosneft and other state-controlled groups are allowed to participate.

The sale is designed to plug holes in the government budget caused by a slump in oil prices and Western sanctions imposed over Russia's actions in Ukraine.

However, the interest shown by Rosneft, whose head Igor Sechin is a close ally of President Vladimir Putin, has drawn criticism from some government officials who have said this would essentially involve the state transferring assets from one firm to another.

Rosneft argues its involvement would boost competition and the price the government can fetch for Bashneft.

Deputy Prime Minister Arkady Dvorkovich and some other officials have opposed the idea of allowing Rosneft to take part but Putin - who holds the ultimate say-so over such major decisions in Russia - has so far stayed silent on the subject.

Rosneft has said it is considering a bid for Bashneft, which produces around 20 million tonnes of oil a year. If it goes head, Sechin is likely to be up against Vagit Alekperov, one of Russia's richest men whose private group Lukoil (LKOH.MM) is interested in buying all of the company.

In its letter to Medvedev, dated Aug. 10, the Economy Ministry said the government has no legal grounds for stopping state-controlled groups such as Rosneft from bidding.

"It is possible to set additional criteria to limit the participation in the transaction of entities directly or indirectly controlled by the state ... based only on a separate decree by the government," it said.

The economy ministry was not immediately available for comment.

HOTLY-C0NTESTED AUCTION

The letter gave no indication of Medvedev's views on the issue. But if such a decree were issued, it would be a setback for Sechin and would leave Lukoil, Rosneft's main rival, as the main contender to buy Bashneft.

Lukoil has said it would not overpay for the company, whose market capitalization is around $10 billion. Lukoil says it values the firm at no more than $4.0-$4.5 billion.

If the government decided against issuing such an order, it would turn the Bashneft privatization into one of Russia's most hotly contested auctions of the past decade and could allow Sechin to expand his giant firm further.

Russia also plans to sell a minority stake of 19.5 percent in Rosneft to reduce its budget deficit.

Sechin argues that Rosneft's participation would increase competition at the Bashneft auction. Rosneft became the world's largest listed oil producer by output in 2013 when it acquired Anglo-Russian oil company TNK-BP for $55 billion.

The economy ministry's letter to Medvedev cites a letter from Sechin to the ministry from Aug. 5 as saying that if Rosneft were banned from the privatization it could see its shares fall and possibly draw law suits from its minority shareholders.

Sechin also argues that if Rosneft were allowed to purchase Bashneft, it would create synergies of around 160 billion rubles ($2.5 billion) and result in higher revenues for the government when the Rosneft stake is sold.

Rosneft declined to comment.

Russia appointed state-controlled bank VTB Capital (VTBR.MM) as its agent to sell Bashneft. VTB has invited around 10 potential bidders including state-controlled Gazprom, Tatneft and the Russian Direct Investment Fund.

If the government banned all state firms from bidding, this would leave Lukoil as well as mid-sized firms Russneft, Independent Petroleum Company, Tatneftegas, Energia and the Antipinsky refinery among remaining bidders.

http://www.reuters.com/article/us-russia-bashneft-rosneft-idUSKCN10Q0WU

Chesapeake Energy Corp, the second-largest U.S. natural gas producer, said on Monday that it had arranged a $1 billion 5-year term loan that it would use to buy back senior notes due between 2017 and 2038.

The company, whose total debt stood at about $8.68 billion as of June 30, said it had commenced tender offers to buy back $500 million of convertible senior notes due 2037 and 2038.

The company said it also commenced tender offers to buy back another $500 million of senior notes due between 2017 and 2023.

Chesapeake said Goldman Sachs Bank USA, Citigroup Global Markets Inc and MUFG helped arrange the term loan.

The company last week announced the sale of its Barnett shale acreage in Texas and said it renegotiated an expensive pipeline contract, steps estimated to save it more than $1.9 billion in future liabilities.

http://www.reuters.com/article/chesapeake-enrgy-debt-idUSL3N1AW37N

Santos flags $1.05 billion GLNG impairment

Australian LNG operator Santos on Monday said it is writing down the value of its GLNG project in Queensland due to low oil and gas prices.

Santos expects to recognise an impairment charge against the carrying value for its GLNG project of about US$1.05 billion after tax ($1.5 billion before tax) in its 2016 half-year accounts.

The impairment outcome is subject to finalisation of the half-year accounts, which will be released on August 19, Santos said, adding it will be a non-cash charge and will “not affect the company’s debt facilities.”

According to Santos, during the course of this year there has been a slower ramp up of GLNG equity gas production and an increase in the price of third party gas. This has caused the Australian LNG operator to adjust its upstream gas supply and third party gas pricing assumptions for GLNG, Santos said.

“The expected impairment charge for GLNG is clearly disappointing but it is a consequence of the challenging environment which we now face. We have decided to adjust our long-term operating assumptions for GLNG to reflect the reality of the current oil price environment,” said Santos chairman Peter Coates.

“However, we firmly believe in the strong long-term growth of LNG consumption and demand globally. GLNG will continue to be an important part of our LNG portfolio and a key supplier of LNG to the Asian market,” Coates said.

Santos started producing the chilled fuel from the first GLNG train on Curtis Island in September 2015. The second train at the $18.5 billion GLNG project started producing liquefied natural gas in May this year.

The company has a 30% interest in Australia’s GLNG. Other co-venturers include Petronas (27.5%), Total (27.5%) and Kogas (15%).

Santos reported earlier this year a net loss of A$2.7 billion ($1.93 billion) for 2015, after booking A$2.8 billion in impairment charges also blaming low oil and gas prices.

The impairment charges related to the company’s Cooper Basin gas producing assets, GLNG assets and Gunnedah Basin assets,

“Low oil and gas prices continue to challenge our upstream business and the entire oil and gas industry,” Santos chief executive Kevin Gallagher said in the statement on Monday.

“We will continue to maintain a disciplined approach to capital allocation, reducing costs and seek opportunities to optimise our asset portfolio in a manner that delivers value to shareholders.”

http://www.lngworldnews.com/santos-flags-1-05-billion-glng-impairment/

China's July refinery throughput retreats from record highs

China's refinery throughput in July retreated from the previous month's record highs as refiners lowered runs because of weak domestic demand, a trend that could extend into August when many state-owned and independent refiners are likely to undergo maintenance.

After surging to a historical high of 11.02 million b/d in June, China's refinery throughput in July took a breather, easing 2.7% month on month to 10.72 million b/d, although it was 2.5% higher from July 2015, S&P Global Platts calculations based on preliminary data released Friday by the National Bureau of Statistics showed.

The country processed 45.32 million mt of crude in July, NBS data showed.

On a b/d basis, throughput in July was slightly lower than the average 10.73 million b/d over the first seven months. China refined 311.86 million mt of crude oil over January-July, up 2.5% from the same period last year, NBS data showed.

NBS does not release its methodology for the statistics, but market observers said that the data covered throughput from all state-owned refineries as they are required to submit all their operational data to the the bureau, and covers some data from independent refiners which may or may not submit the full data.

THE PRICE IMPACT

A monthly survey by Platts in July had shown that 26 of China's largest state-owned refineries, operated by Sinopec, PetroChina and China National Offshore Oil Corporation, planned to run their plants at an average 81% of nameplate capacity, up one percentage point from 80% in June, because Sinopec had planned to lift throughput ahead of maintenance at its Tianjin, Qilu and Shanghai refineries.

But it likely did not happen.

"The plants have flexibility to adjust their refining plans according to the market situation, which remained weak last month," said a source with a Sinopec refinery.

The cut in oil product prices also discouraged refining.

A Shanghai-based analyst said: "The cut in oil product prices in second-half July also discouraged refining."

China on July 21 announced a cut in guidance retail prices for gasoline and gasoil by Yuan 155/mt ($23.33/mt) and Yuan 150/mt, respectively. It was the first price cut since January 13.

The country's independent refineries in Shandong also reduced their throughput in July by 7% month on month because of maintenance and poor domestic sales, Platts has reported.

Domestic sale of gasoline and gasoil from Shandong-based independent refineries registered month-on-month declines of 8.87% and 9%, respectively, in July, Platts calculations based on data from Beijing information provider JYD showed.

Looking forward, throughput in August is expected to fall further because of additional maintenance plans both at state-owned and independent refineries, analysts said.

http://www.platts.com/latest-news/oil/singapore/chinas-july-refinery-throughput-retreats-from-26520699

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Attached Files

Brazil’s Petrobras cuts LNG imports by 56 pct

Brazil’s state-controlled oil and gas company Petrobras said its liquefied natural gas imports dropped by 56% in the first half of this year.

Petrobras attributed this decline to higher domestic gas supply and lower thermoelectric demand in Brazil.

LNG imports into Brazil stood at 54 Mbbl/d (thousand barrels per day), as compared to 122 Mbbl/d in the same period a year before, Petrobras said in its second-quarter report.

Petrobras is aiming to reduce its role in the Brazilian natural gas and LNG industry. The company recently announced it will sell its LNG terminals in Rio de Janeiro and Ceará, along with the thermoelectric power plants associated with these terminals.

The Brazilian company also said it is selling its LPG distribution unit, Liquigás Distribuidora.

Petrobras’ net income fell 30 percent to 370 million reais ($118 million) in the second-quarter compared with a profit of 531 million reais a year earlier, according to the report.

http://www.lngworldnews.com/brazils-petrobras-cuts-lng-imports-by-56-pct/

All it took was a few words from OPEC to encourage oil bulls.

Money managers increased wagers on rising crude prices by the most since January as futures rebounded from a three-month low. Prices jumped after OPEC’s president said Aug. 8 the group will hold informal talks in Algiers next month and Saudi Arabia signaled Aug. 11 it’s prepared to discuss taking action to stabilize markets.

"The statement certainly achieved its purpose," said Daniel Yergin, vice chairman of IHS Markit. "The Saudis saw bearish bets had really driven down the prices."

Talks between OPEC members and other producers may result in action to stabilize the market, Saudi Arabia’s Energy Minister Khalid Al-Falih said. Members of the Organization of Petroleum Exporting Countries are in “constant deliberations,” according to a statement on OPEC’s website attributed to Mohammed bin Saleh Al-Sada, Qatar’s energy and industry minister and the group’s current president.

Hedge funds bolstered their long position in West Texas Intermediate crude by 17,154 futures and options combined during the week ended Aug. 9, according to the Commodity Futures Trading Commission. WTI rose 8.3 percent to $42.77 a barrel in the report week. Prices gained 0.8 percent to $44.85 a barrel as of 1 p.m. Hong Kong time on Monday after posting the biggest weekly gain since April.

"The Saudis are very conscious of the financial markets and how they exaggerate price moves," Yergin said.

Differences between Saudi Arabia and Iran caused the demise of a proposal to freeze production at an April summit in Doha. The kingdom insisted it wouldn’t restrain output without commitments from all OPEC members, including Iran, which has boosted crude production and exports after years of sanctions were lifted in January.

"A freeze may be on the table, maybe more," said Mike Wittner, head of oil market research at Societe Generale SA in New York. "The Saudi comments leave the door open to anything, as opposed to Doha where they killed the deal. The fact that the Saudis are open to any action is an important signal. The Iranians have pretty much done what they wanted to do, which will make them more open, and the Saudis seem open as well."

Refinery Demand

Refiners around the world will process a record 80.6 million barrels a day of crude this quarter to absorb all-time high production from several Persian Gulf producers, the International Energy Agency said Aug. 11.

"The market is moving towards balance with a huge overhang," Yergin said. "We see supply and demand roughly in balance, and if there are no additional disruptions prices should be in the mid $50s next year."

Rising U.S. crude stockpiles and weakening demand from the nation’s refineries may weigh on prices. Crude supplies rose 1.06 million barrels million as of Aug. 5, Energy Information Administration data show. Over the past five years, refiners’ thirst for oil has fallen an average of 1.2 million barrels a day from July to October.

Money managers’ long position in WTI rose to 322,594 futures and options, the highest since May 2015, CFTC data show. Shorts, or bets on falling prices, increased 0.7 percent and were at a record for a second week. Net longs advanced 18 percent, the biggest jump since March.

"The Saudi statement could mean anything," said Tim Evans, an energy analyst at Citi Futures Perspective in New York. "They said that there will be informal meeting of OPEC members on the sidelines. That could be anything from coffee and cake on a terrace to a closed-door meeting to decide on specific production proposals."

http://www.bloomberg.com/news/articles/2016-08-14/oil-bulls-take-heart-as-opec-rekindles-hopes-of-output-freeze

U.S. drillers this week added oil rigs for a seventh consecutive week, the longest recovery streak in the rig count in over two years, even as analysts revise down rig count growth forecasts and energy firms become more cautious the longer crude holds below $50 a barrel.

Drillers also added the most oil rigs since December with 15 rigs activated in the week to Aug. 12, bringing the total rig count up to 396, compared with 672 a year ago, energy services firm Baker Hughes Inc said.

That is the longest streak of rig additions since April 2014 when U.S. oil futures averaged over $100 a barrel. Since July 1, drillers have added 66 oil rigs.

U.S. crude futures were up almost 2 percent to over $44 a barrel, putting the contract on track for a weekly gain near 6 percent, its biggest weekly increase since April, after it fell below $40 last week. [O/R]

Prices, however, are still far from the key $50 level hit in June that analysts and drillers said would prompt a return to the well pad after nearly two years of severe cuts in the rig count amid the worst price rout in a generation.

"Consensus among exploration and production companies, service companies, and land drillers is for a 'lower-slope' recovery, with concerns of the direction of oil prices still lingering, especially with the recent dip below $40 after averaging $48 in the middle of summer," analysts at Barclays said in a report this week.

The bank said it still expects a modest increase in rig additions heading into the end of the year and through the first quarter of 2017, but revised down its total oil and natural gas rig forecast to an average of 480 from the 495 it projected in March.

That, however, is not much higher than the average 477 oil and gas rigs that Baker Hughes said were active since the start of the year. In 2015, the total rig count averaged 978.

Analysts at Simmons & Co, energy specialists at U.S. investment bank Piper Jaffray, forecast total rigs would average 489 in 2016, 680 in 2017 and 957 in 2018. That is a slight reduction from last week when Simmons forecast rigs would average 491 in 2016, 683 in 2017 and 961 in 2018.

Since total rigs fell to 404 in May, the lowest since 1940, Baker Hughes said more than two-thirds of the additions have been in the Permian basin in west Texas and eastern New Mexico, the nation's largest shale oil play.

Of the 481 total rigs active in the United States, 189 are in the Permian, the most in that basin since January.

http://www.reuters.com/article/us-usa-rigs-baker-hughes-idUSKCN10N20N

Saudi Energy Minister Kahlid al-Falih made remarks suggesting Saudi Arabia might be willing to revisit talks with members of the Organization of Petroleum Exporting Countries and other producers on limiting production.

“If there is a need to take any action to help the market rebalance, then we would, of course in cooperation with OPEC and major non-OPEC exporters,” al-Falih said.

Some analysts remain skeptical that Saudi Arabia would support a collective production cap. An April meeting between OPEC and non-OPEC producers failed to reach any such agreement.

But future talks on the same topic are being discussed. Qatar’s Energy Minister and OPEC Pres. Mohammed bin Saleh al Sada has said cartel members will participate in such talks Sept. 26-28 on the sidelines of the International Energy Forum in Algeria.

http://www.ogj.com/articles/2016/08/market-watch-nymex-brent-oil-prices-rebound-on-saudi-comments.html

It may seem odd that the opening of one pipeline crossing through four U.S. Midwest states could upend the movement of oil throughout the country, but the Dakota Access line may do just that.

At the moment, crude oil moving out of North Dakota's prolific Bakken shale to "refinery row" in the U.S. Gulf must travel a circuitous route through the Rocky Mountains or the Midwest and into Oklahoma, before heading south to the Gulf of Mexico.

The 450,000 barrel-per-day Dakota Access line, when it opens in the fourth quarter, will change that by providing U.S. Gulf refiners another option for crude supply.

Gulf Coast refiners and North Dakota oil producers will reap the benefits. Losers will include the struggling oil-by-rail industry which now brings crude to the coasts.

The pipeline also will create headaches for East and West Coast refiners, which serve the most heavily populated parts of the United States and consume a combined 4.1 million barrels of crude daily. They will have to rely more on foreign imports.

The pipeline, currently under construction, will connect western North Dakota to the Energy Transfer Crude Oil Pipeline Project (ETCOP) in Patoka, Illinois. From there, it will connect to the Nederland and Port Arthur, Texas, area, where refiners including Valero Energy, Total and Motiva Enterprises operate some of the largest U.S. refining facilities.

"That's a better and cheaper path than going out West and down through the Rockies," said Bernadette Johnson, managing partner at Ponderosa Advisors LLC, an energy advisory based in Denver.

CHEAPER THAN RAIL

Moving crude by pipeline is generally cheaper than using railcars. The flagging U.S. crude-by-rail industry already is moving only half as much oil as it did two years ago: volumes peaked at 944,000 bpd in October 2014, but were around just 400,000 bpd in May, according to the U.S. Energy Department.

Rail transport has become less economical for East and West Coast refiners when compared with importing Brent crude, the foreign benchmark, because declining supply out of North Dakota made that grade of oil less affordable.

"If you look at the Brent to Bakken arb, it's tight," said Afolabi Ogunnaike, a senior refining analyst at Wood Mackenzie in Houston. "If you look at the spot rate, it's uneconomical to move crude by rail right now."

Ponderosa Advisors estimated that the start-up of the pipeline could reroute an additional 150,000 to 200,000 bpd currently carried by rail to the U.S. East Coast and Gulf Coast.

Crude imports into the East Coast are now on the rise, averaging 788,000 bpd this year, with nearly 960,000 bpd in July, the highest level in three years, according to Thomson Reuters data.

On the West Coast, refiners like Shell, Tesoro and BP may have to commit to some railed volumes for longer because of shipping constraints, although it will largely depend on rail economics. They also face declining output from California and Alaska.

Tesoro's top executive Gregory Goff told analysts and investors last week he expects rail costs to drop as much as 40 percent from the current $9-to-$10 barrel cost to compete with pipelines, in order to move Bakken to its Anacortes, Washington, refinery.

CHANGING TIDES

Rail companies have been trying to adapt. CSX Corp, which runs a network of lines in the eastern part of the country, said it was evaluating potential impacts of the pipeline. BNSF Railway declined to discuss future freight movements, but said that at its peak, it transported as many as 12 trains daily filled with crude, primarily from the Bakken. Today, it is moving less than half of that.

In a recent earnings call, midstream player Crestwood Equity Partners said it was working to capitalize on the pipeline and not be dependent on loading crude barrels onto trains. That includes building an interconnection to its 160,000 barrel-per-day COLT crude rail facility in North Dakota.

As refiners bring in more barrels from overseas, Brent's premium over U.S. crude will eventually widen. On Thursday, December Brent futures settled at a 97-cent premium to U.S. crude, one of its widest premiums this year.

Separately, Bakken crude, a light barrel, could rise further due to the additional competition, especially as production is still falling. Bakken differentials hit a six-month low earlier this week of $2.65 a barrel below WTI, according to Reuters data, but rose to a $1.80 a barrel discount by Thursday.

http://www.reuters.com/article/us-usa-oil-pipeline-idUSKCN10N0HP

Some of the oil reserves in the United States may be more resilient to weak oil prices and show slow, but steady, production gains, a federal report finds.

A review from the U.S. Energy Information Administration finds global tight oil, a lighter grade of crude oil found typically in shale deposits, is expected to double by 2040 to about 10.4 million barrels per day. Most of that, the report found, will come from the United States.

"United States tight oil production, which reached 4.6 million bpd in March 2015, but fell to 4.1 million bpd in June 2016, has proven more resilient to low oil prices than many analysts had anticipated," the report read.

In its reference case, EIA estimates total U.S. tight oil production reaches 7.1 million bpd by 2040.

EIA made a similar conclusion in June regarding shale natural gas. About half of all of the natural gas produced in the United States comes from shale gas reserves or is associated with so-called tight oil basins. Much of that comes from lucrative shale beds like the Eagle Ford basin in Texas and the Bakken play in North Dakota.

The EIA's analysis found that, through 2040, total U.S. production from shale gas and tight oil more than doubles to 29 trillion cubic feet, accounting for about 69 percent of total output of natural gas in the country.

Lower energy prices, off about 4.7 percent from this time last year even after recovering 68 percent from this year's lows, have robbed energy companies of the revenue needed for robust exploration and production programs. Nevertheless, most have said they expect to produce more as their operations become more efficient.

Continental Resources, one of the largest stakeholders in the Bakken shale oil basin in North Dakota and Montana, said its production expenses were lower than it previously estimated by 11 percent. Based on that, the company said it expects to produce an average full-year production of around 215,000 barrels of oil equivalent per day, an increase of 5,000 boe per day from its previous estimate.

North Dakota's government said oil production could stay above 1 million bpd through next year if oil prices stay around $45 per barrel. It set a record in December 2014, when oil traded in the $60 range, at 1.23 million bpd.

Higher production volumes and sluggish global economic growth is keeping oil prices relatively lower. By 2040, EIA in its reference case estimates a price for Brent crude oil at $136 per barrel, a price last reached less than a decade ago.

http://www.upi.com/US-oil-more-resilient-than-thought/8741471005587/

Saudi Arabia plans to increase production of Arab Extra Light crude in coming weeks, which could translate to weaker spot differentials for similar grades in the Middle East, market participants said Friday.

Industry sources had said earlier this month that the production of Arab Extra Light crude was expected to rise by about 200,000 b/d from September, though Saudi Aramco could not immediately be reached for comment.

"[Saudi Aramco's] October supply volumes [of Arab Extra Light] to term lifters would be increased... or perhaps some term customers may want to lift additional volumes if the incremental cost is lower than what they would have to pay to grab additional [light sour crude] barrels in the spot market," said a North Asian sour crude trader with knowledge of allocations in Saudi Arabian term crude liftings.

The talk of higher Saudi output emerged soon after Saudi Aramco slashed the September official selling price differentials for its crudes bound for Asian buyers early in the month.

At the start of the month, Aramco cut the OSP of its Arab Light crude loading in September and bound for Asia by $1.30/b, making it the lowest price since January. The September OSP of Asia-bound Arab Super Light crude was cut by 80 cents/b from August and Extra Light by $1.60/b.

Market participants said Aramco's bigger-than-expected OSP cuts and the planned fourth quarter output increase suggested that the major Middle Eastern producer was stepping up efforts to remain price competitive in order to appeal to Asian end-users and fend off competition from Europe's North Sea crude suppliers amid a narrowing Brent-Dubai spread.

The second-month Brent/Dubai EFS -- which enables holders of ICE Brent futures to exchange their Brent futures position for a forward-month Dubai crude swap -- was assessed at $2.58/b Thursday, close to the eight-month low of $2.27/b reached on July 29.

Regional sour crude traders said Saudi Arabia could also be aiming to sell additional barrels in order to make up for any losses in oil revenue incurred due to the recent sharp pullback in international flat prices, with front-month ICE Brent futures tumbling to three-month lows late last month.

"Crude prices around and below $40/b would worry many producers, not just the Saudis," said a crude trader based in South Asia.

Regional traders said Saudi Arabia's plan to increase the production of Arab Extra Light crude later this month, on top of dismal light distillate margins and the narrow Brent-Dubai spread, would likely deter many Asian buyers from Abu Dhabi and Qatari supplies.

Trading has remained thin in Abu Dhabi's light sour crude market to date, while very little has been heard on pre-tender deals for Qatar's deodorized field condensate and low sulfur condensate for loading in October, a week before Tasweeq's tender closes on August 16.

"There are more Arab Extra Light crude [available for Q4]," said a Singapore-based crude and condensate trader, adding: "I think a lot of end-users are rushing to secure incremental Saudi barrels first. After that, focus might just turn to light sour Murban and Qatari condensates, maybe." "Buyers are quiet... it might be a very slow trading month [for Qatari condensates]," said a Tokyo-based crude trader. The gap between offers and buying indications for Qatar's DFC was very wide, with several North Asian end-users looking to buy October-loading DFC at a premium of around $1/b to Platts front-month Dubai crude oil assessments, while some suppliers were aiming to sell above Dubai plus $1.70/b, he added.

In comparison, most DFC cargoes for loading in September received premiums in the range of $1.70-$1.90/b to Dubai crude last month. The expected increase in the production of Saudi Arab Extra Light crude continued to affect sentiment in the broader light sour crude complex in the Middle East, with end-users across Asia adjusting their buying ideas for Murban and Das Blend lower.

Asked about the near-term price differential outlook for October-loading Murban crude, several traders said the grade could change hands at a discount to Murban's OSP, indicating that sentiment was deteriorating despite ADNOC's recent cuts in OSPs.

Four regional traders surveyed by S&P Global Platts last week had tipped Murban to trade at a small premium to the grade's OSP this month. "Arab Extra Light supply will be the key [factor for Murban's price outlook] ... the narrow [Brent-Dubai] EFS will certainly do some damage, too," said a Southeast Asian trader.

http://www.platts.com/latest-news/oil/singapore/hike-in-saudi-arab-extra-light-crude-oil-supply-26520792

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Attached Files

We’d never heard this before, but apparently the Marcellus/Utica has been known for some time as the “Beast of the East.” Fitting! However, our region has gone from “Beast of the East” to “Beast on a Leash.”

Very true. Low prices have suppressed new drilling projects. But according to experts on a recent webinar held by S&P Global Platts, new Marcellus/Utica drilling “is imminent.” Now that’s REALLY good news!

http://marcellusdrilling.com/2016/08/experts-say-new-marcellusutica-drilling-imminent/

Sabine Oil & Gas Corporation has confirmed that its Chapter 11 Plan of Reorganization, which was confirmed by the United States Bankruptcy Court for the Southern District of New York July 27, is now effective and revealed that it has emerged from bankruptcy as a private company.

In conjunction with its emergence from Chapter 11, the company closed on its new senior secured credit facility, which has commitments of $200 million and an initial borrowing base of $150 million, and on its new $150 million second lien term loan.

The company completed an effective balance sheet restructuring that involved a debt-for-debt exchange, a debt-to-equity conversion, and the issuance of warrants to purchase stock in the newly-formed parent holding company of the reorganized company. Sabine emerged from bankruptcy with a “significantly stronger” balance sheet and “renewed ability to focus on creating value from its compelling asset base,” according to a company statement.

“Sabine has successfully restructured its balance sheet, addressing its leverage and liquidity needs,” said Sabine Chief Executive Officer David Sambrooks.

“Throughout this process we have valued and appreciated the support and guidance of our outgoing board of directors as well as our professional advisors. Above all, I am humbled by the dedication and outstanding effort of our employees, and have great optimism for the next chapter of our organization. We look forward to working under the guidance of our new, remarkably experienced board to create value for our new ownership group.”

http://world.einnews.com/article/339663224/8ZfzpBGdbhupwcta

Turkey wants to buy more gas from Iran, resolve price dispute: foreign minister

Turkey wants to buy more natural gas from Iran and has discussed pricing issues, Foreign Minister Mevlut Cavusoglu said on Friday, adding that Ankara and Tehran should resolve a dispute on gas prices without arbitration.

Cavusoglu made the comment at a joint news conference with his Iranian counterpart, Mohammad Javad Zarif in Ankara. Zarif is on an official visit to Turkey.

http://www.reuters.com/article/us-turkey-security-iran-gas-idUSKCN10N12O

China crude output falls to five-year low in July

China's crude oil production in July fell 8.1 percent from a year ago to the lowest since October 2011 on a daily basis, as low prices limit the incentive to keep some wells operating in the world's fourth-largest oil producer.

Crude output last month was 16.72 million tonnes in July, data from the National Bureau of Statistics showed on Friday. On a daily basis July's production is about 3.94 million barrels per day (bpd), down from June's 4.03 million bpd and the fifth straight month of declines in terms of daily output.

For the first seven months of 2016, production was down 5.1 percent versus the same period last year to 118.35 million tonnes, or about 4.06 million bpd.

Dominant domestic producers PetroChina and Sinopec have both projected output declines this year as many of their fields began to operate at a loss, especially during the first quarter when oil prices sank below $40 a barrel.

Sinopec said in July that their domestic production in the first half of 2016 was down 12.95 percent to 128.38 million barrels, or about 705,000 bpd.

In addition to production that is not viable economically, China is also grappling with aging oil fields that are increasingly running out of oil and gas.

Daqing, China's largest field, which produced first oil in 1960, will decline at a rate of 7.2 percent this year, its fastest pace in the last 20 years, according to consultants Energy Aspects.

Natural gas output last month fell 3.3 percent compared with the year ago period to 10.3 billion cubic meters, though for the first seven months of the year production rose 3.1 percent to 79.4 billion cubic meters, the stats bureau said.

Throughput at China's oil refineries rose 2.5 percent in July from a year earlier to 45.32 million tonnes, or 10.67 million bpd, according to the bureau. That was down from June's runs of 10.97 million bpd.

Crude runs in the January to July period rose 2.5 percent year on year to about 10.69 million bpd, according to the data.

http://www.reuters.com/article/china-economy-output-crude-idUSL3N1AT1FK