Security of gas supply is no longer an issue in European markets, and the balance of risk has moved to demand, participants said at the Platts European gas summit in Brussels Thursday.

"We're long on everything -- we're long gas, we're long storage, we're long flexibility, we have too much of everything," Christopher Delbruck, CEO of E.ON Global Commodities, said.

"Total storage capacity is above import requirements -- this has no precedent in Europe," GDF Suez's (now Engie) former vice president Jean-Francois Cirelli said. "The main economies are well supplied and will be well supplied."

But this robust near-term supply picture raises longer-term challenges, E.ON's Delbruck said.

"The economic sustainability of that solution is not there [given the extent to which prices could fall]."

Depressed prices would compromise future investment as well as the existence of current supply infrastructure, participants said.

"Not all storage sites are covering operational costs; storage operators could close facilities to deal with over capacity," Michael Kohl, commercial managing director at RWE Gas Storage, said.

Martin Bachmann, head of German firm Wintershall's European exploration and production division, said investment in the upstream gas sector was required to "safeguard" security of supply.

But despite the longer-term supply risks, demand is now the key immediate challenge facing Europe's gas industry, according to Cirelli.

"There is no security of demand in Europe -- no-one knows where we are going," he said, citing data from French bank Societe Generale showing a 22% fall in annual European gas demand from 2006-2014 driven mainly by lower power sector demand.

http://www.platts.com/latest-news/natural-gas/london/european-gas-supply-no-longer-a-risk-demand-is-26211997

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China will double its pipeline imports of Russian ESPO crude to 30 million mt/year as early as October 2017, after the second Mohe-Daqing pipeline comes on stream, PetroChina Vice President Sun Longde said Wednesday, according to local media.

He did not say when construction would start.

The existing 15 million mt/year Mohe-Daqing pipeline in northeastern Heilongjiang province receives Russian ESPO crude from the border Mohe station and sends it to Daqing, started operations in January 2011.

The pipeline was built to take 15 million mt/year of ESPO crude from Rosneft for 20 years.

The second ESPO crude pipeline will run parallel to the first.

Under earlier deals, Russia's state-owned Rosneft agreed to increase ESPO deliveries to China National Petroleum Corp. by 5 million mt/year in 2015 and another 5 million mt/year in 2016.

But the delivered volume has only increased slightly this year.

PetroChina has taken a total of around 11.02 million mt from the existing pipeline over January-August, or an average 33,105 b/d, with the yearly volume for 2015 expected to hit 16.48 million mt at the current transmission rate. While well below the 20 million mt/year target, this would be up 5.7% from 15.6 million mt shipped in 2014.

Rosneft redirected some of the ESPO exports to China via its Kozmino port, the destination of its only export pipeline to Asian markets.

PetroChina's 20.5 million mt/year Dalian refinery has been receiving seaborne cargoes shipped from Kozmino. The refinery this year will take around 5 million mt/year in seaborne cargoes.

Dalian refinery also takes ESPO crude shipped via pipeline from Daqing, with the 2015 volume estimated at 3.5 million mt.

Three other PetroChina refineries are major takers of pipelined ESPO from Daqing: 9 million mt/year Liaoyang Petrochemical in northeastern Liaoning province, the 10 million mt/year Jilin Petrochemical in northeastern Jilin province and the 5 million mt/year Harbin Petrochemical in Heilongjiang province.

ESPO crude makes up all of Liaoyang Petrochemicals' feedstock and 60%-65% of the Dalian refinery's feedstock.

Jilin and Harbin refineries process ESPO crudes and domestic onshore crudes such as Daqing.

http://en.chinamining.com.cn/News/2015-09-18/1442542052d73786.html

Chinese imports of fuel oil will drop further this year and next as reforms in the world's No.2 economy allow more independent refineries to ship in crude oil as an alternative feedstock, traders and analysts said.

China is opening its crude oil imports to buyers outside the state-owned sector, with independent refiners so far getting the go-ahead to use a total of nearly 700,000 barrels per day (bpd) in crude imports, or about 11 percent of total crude shipments into the country.

With seven refiners already receiving the final greenlight to use imported crude oil and two of them granted licenses to import directly themselves, analysts expect fuel oil to be displaced quickly. Consultancy Energy Aspects said fuel oil demand could fall by 9 percent next year.

"Straight run fuel oil imports have dropped a lot mainly as teapot refineries are getting import licenses for crude," said a trader with a Chinese state-owned company.

Small, independent refiners in China, often nicknamed 'teapots', prefer to process crude rather than fuel oil due to better refining economics and larger yields of high-value products such as gasoline and diesel.

China's appetite for fuel oil, which is also used in shipping, has already been hit hard by a shift to natural gas and the nation's economic slowdown, with the nation flipping into net fuel oil exports in July for the second month since 2006.

China imported nearly 1.1 million tonnes of fuel oil in July, it's lowest volumes in a year, while its exports nearly doubled from June, customs data showed.

Demand has also been curbed as the government has raised the fuel consumption tax several times, keen to reduce China's heavy use of energy and natural resources while addressing its severe pollution problems.

And appetite from shippers in China has also been fading, traders said.

"Fuel oil demand for shipping is also bad as trade has slowed down a lot," said a Singapore-based bunker fuel supplier.

"They are also using larger vessels now so this affects prices as well."

Cash premiums for straight run fuel oil have fallen by at least a third since the start of the year, a Singapore-based trader said.

Meanwhile, China's imports of bitumen mixture, another type of heavy oil that can easily be blended into fuel oil, have also dropped. Companies had in the last two years switched to importing fuel oil declared as bitumen mixture to avoid paying consumption tax, but slowing demand and a clampdown by the government has curbed those imports, traders said.

It is now importing about 500,000 to 700,000 tonnes a month of bitumen mixture, compared with 1.5 to 2 million tonnes a month late last year, said a Beijing-based trader.

http://www.reuters.com/article/2015/09/18/china-fueloil-idUSL4N11M2OR20150918

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It’s no secret that low commodity prices and the supply glut are pushing oil drillers to find cheaper ways to drill.

According to Oil and Gas Investor, producers are looking to old vertical wells for increased production from shallow play at a lower cost than horizontal drilling. Vertical wells also have a strong cash flow asset. In addition, vertical wells can be put into production within 10 days, compared to horizontal wells that take a month or longer to complete.

Baker Hughes data shows that the horizontal rig count fell by 2 percent while the vertical rig count rose 20 percent from early June to Sept. 4.

http://shalegasreporter.com/news/vertical-wells-making-comeback/57584.html

Small and medium-sized oil companies, squeezed by the oil price slump, may have to raise expensive new finance, sell assets or seek new investors to plug any funding gaps as banks tighten up on lending.

Many of these companies have already cut spending and axed thousands of jobs following a more than halving in the oil price to around $50 a barrel since June last year.

But they may need to do more as revenues fall and the oil price looks set to stay low. Oil's fall last month to its lowest since early 2009 at just above $40 a barrel has dashed hopes in the oil industry for a swift recovery.

In many cases, banks lend money based on a company's oil and gas reserves base, in what is known as reserve-based lending, so, in theory, the lower the oil price outlook, the smaller the loan or credit line.

"Banks will be broadly supportive but for some riskier clients and transactions, there may be a gap in financing that didn't exist before and they will have to find alternative financing," one banker, who heads a loan syndicate, said.

"There is concern that banks will redenominate and reduce existing financing for energy companies. Banks are looking at this now, it's a live issue."

The companies and their banks sit down twice a year to review finances, which used to be a fairly routine conversation when oil was riding high. Most companies emerged from the April round of talks, known as "redeterminations" relatively unscathed because of expectations of an oil price recovery.

The current round may be more difficult as banks will have cut their long-term oil price forecasts, according to several bankers and consultants.

"Managements and boards have had to come to terms in recent weeks with the 'lower for longer' oil price view," Rupert Newall, head of EMEA energy investment banking at BMO Capital Markets, said.

Exploration and production companies with large project financing needs include Africa-focused Tullow Oil, North Sea producers Lundin Petroleum and Ithaca Energy , according to bankers and analysts.

Nomura has estimated Tullow Oil's net debt will rise to $4.7 billion by the second half of 2016, when its TEN project off Ghana's coast is planned to start production.

Tullow's net debt at the end of the first half of 2015 was $3.6 billion.

Tullow and Ithaca declined to comment. Lundin did not immediately respond to requests for comment.

In the United States, where some oil companies borrowed heavily to invest in shale, several have run into trouble this year, including Oklahoma-based Samson Resources.

But Jo Clark, a transaction advisory consultant at EY, said the chances were low of similar problems in Europe.

There have been a few casualties. Oil producer Afren , for example, decided to go into administration in July when it failed to win support for a refinancing plan.

Credit rating agency Standard & Poor's on Thursday cut its long-term corporate credit rating on British oilfield services company Expro Holdings Ltd to CCC+ from B-, citing its high leverage and the challenging market conditions in oil and gas.

http://www.reuters.com/article/2015/09/17/oil-companies-debt-idUSL5N11A2HR20150917

While announcing a board shakeup, Australian energy company Santos said Thursday it was vetting interests from other entities eyeing its assets.

The board at Santos said Chief Executive Officer David Knox will step down once a successor is named after seven years at the helm. Knox will stay on in the interim, though Chairman Peter Coates will take on more responsibilities.

"We are undertaking a thorough strategic review of all options to restore and maximize shareholder value in the face of the continuing pressures on oil prices, globally," Coates said in a statement.

Santos in August said net profit for the first half of 2015 at $37 million was 82 percent lower year-on-year. Capital expenditure was down by more than half from the same period in 2014, reflecting the substantial slump in crude oil prices.

The company in July said it was maintaining its production guidance moving forward despite reductions in capital and operating expenditure. During the second quarter, the company produced 14.3 million barrels of oil equivalent, 12 percent higher year-on-year, and posted sales volumes of 15.7 million boe, 4 percent higher year-on-year. Sales revenue, however, fell 19 percent.

Coates said the company has a portfolio of high-quality assets and shareholder values needs to be protected. Though no short-cuts are on the table, the chairman said all options are on the table.

"We will be talking with the parties who have approached us to date with interest in various assets and other strategic initiatives and with this announcement there may well be new expressions of interest received," he said.

The company said it was taking the "appropriate steps" to cut operating costs. For full year 2015, Santos is targeting $180 million on supply chain savings.

Santos boasts strong operational performance from its liquefied natural gas portfolio, particularly from its LNG project in Papua New Guinea.

http://www.upi.com/Business_News/Energy-Industry/2015/09/17/Aussie-energy-company-Santos-starts-shakeup/4161442487441/

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OPEC expects the average price of its crude oil to rise to $80 a barrel by 2020 as supply from non-members grows more slowly than expected.

Production from nations outside the Organization of Petroleum Exporting Countries will be 58.2 million barrels a day in 2017, 1 million lower than previously forecast, according to an internal research report from the group seen by Bloomberg News. While OPEC expects little stimulus to demand in the medium term as a result of cheaper oil, it estimated that the average price of its crude will increase by about $5 annually to 2020 from $55 this year.

The impact of current low prices is “most apparent on tight oil, which is more price reactive than other liquids sources,” according to the report. “Supply reductions in U.S. and Canada from 2014-2016 are clearly revealed.”

The price of oil has tumbled more than 50 percent in the past year, triggering a cutback in drilling in the U.S. and other non-OPEC nations. Crude collapsed as OPEC followed Saudi Arabia’s strategy of defending its share of the global market against shale and other competitors.

http://www.bloomberg.com/news/articles/2015-09-17/opec-sees-crude-rising-to-80-by-2020-as-rival-suppliers-falter

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Kuwait's OPEC governor Nawal al-Fuzaia said on Thursday the oil market would balance itself but "we need to be patient", indicating support for the producer group's policy of defending market share despite falling prices.

Speaking at the Gulf Intelligence Energy Markets Forum in the UAE emirate of Fujairah, Fuzaia said the current imbalance in the market stemmed from several factors and not just an economic slowdown in China.

"The weakening demand in China, it is a short-term issue. I don't think that it will have an effect on OPEC market share," she said.

OPEC shifted policy in November 2014 by deciding not to support prices by cutting output, in order to defend market share against U.S. shale oil and other higher-cost supply sources.

The shift, led by Saudi Arabia and its Gulf allies, has proved controversial within OPEC as oil prices have more than halved from above $100 in June 2014, hurting the economies of less wealthy members such as Venezuela.

Still, Fuzaia said the Organization of the Petroleum Exporting Countries needed more transparency in data from China to gauge demand.

"I am not saying we can't trust Chinese numbers but our concern is that it is not the actual demand, it is the calculated demand. It could be the same as actual demand or not," she said.

Fuzaia said OPEC was looking for stable, sustainable growth in China's economy and demand but that should Chinese demand decline, Kuwaiti crude would go to other markets.

http://www.reuters.com/article/2015/09/17/kuwait-opec-idUSL5N11N20S20150917

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Glencore vies with Trafigura, Vitol in thawing LNG market

Mining and trading giant Glencore is mounting a challenge to Trafigura and Vitol to become the top merchant trader of liquefied natural gas, as a market in which sales are largely frozen into decades-long contracts looks set to thaw.

Trafigura recently adopted tactics developed from years of trading oil to become the world's top LNG merchant, investing in logistics and storage, while also providing credit and shouldering risk for buyers.

Glencore, on the other hand, plans to double its global LNG trading team and trade as many as 50 cargoes of the super-chilled fuel over the next year - almost twice what Trafigura traded in its fiscal year to Sept. 30, 2014.

LNG could soon surpass iron ore as the world's second-biggest traded commodity, with estimates of the market's worth ranging between $90 billion and $150 billion.

"The opportunity for growth in LNG trading is spectacular," said Glencore's global head of LNG, Gordon Waters, who joined in July after 18 years at BP.

Trading companies, which industry sources say have so far accounted for less than 10 percent of overall LNG trade, could help trigger a more liquid Asian LNG market, with exchanges from Singapore to Tokyo launching indices and futures contracts in preparation.

Waters was in a team at BP that took it from selling LNG via long-term contracts to being a key player in spot and short-term trade. "The idea is to do that all over again," he told Reuters.

Glencore - which has had a limited presence in LNG up to this point - plans to trade some 40 to 50 cargoes on spot or short-term deals over the next year and double the size of its three-trader team based in Singapore, London and Madrid.

"Come back in 12 months, and I think you'll notice a rapid growth," Waters said.

Glencore's planned volumes would be just under what some analysts say Trafigura could sell in the year to the end of this month, after the latter sold 1.7 million tonnes of spot LNG, or about 28 cargoes, the previous fiscal year.

Trafigura declined to provide further details in its volumes and market strategies.

Vitol says on its website it delivered over 1 million tonnes of LNG worldwide in 2014.

A Vitol spokeswoman declined to provide more details on its volumes, but said the trading house had been "at it years before anyone else, despite lots of noise in the last couple of years from Trafigura."

Sudden oversupply and the development of financial derivatives have allowed "new species to emerge in LNG," such as trading houses and banks, including his own, said Jogchum Brinksma, managing director at Citigroup Global Commodities, at this month's World LNG Series in Singapore.

Other merchants trading LNG include Noble Group and Gunvor.

http://www.reuters.com/article/2015/09/17/asia-lng-merchants-idUSL4N11N3WH20150917

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The Australian Competition and Consumer Commission voiced its concerns over issues on the proposed $70 billion acquisition by Royal Dutch Shell of BG Group.

ACCC’s Statement of Issues seeks industry views and more information on the competition issues that have arisen in the regulator’s review to date.

“The ACCC is concerned that, by aligning Shell’s interest in Arrow Energy with BG’s LNG facilities in Queensland, the proposed acquisition may change Shell’s incentives such that it will prioritise supply to BG’s LNG facilities over competing gas users. As a result, Shell could choose to direct more (and possibly all) of Arrow’s large gas reserves towards meeting BG’s contracts to supply LNG export markets. This would remove some or all of Arrow’s gas from the domestic market,” ACCC Chairman Rod Sims said.

He added that currently, Arrow has the largest quantity of uncommitted gas reserves in eastern Australia and there are a limited number of other potential suppliers to the domestic market. If the proposed acquisition resulted in less supply of gas to the domestic market, therefore, this could substantially lessen competition to supply domestic gas users and lead to higher domestic prices and more restrictive contractual terms.

The ACCC  said it has received a large number of submissions from market participants concerned about the competition effects of the proposed acquisition.

It called for further submissions from the market in response to the Statement of Issues by October 8. As a result, the ACCC’s final decision will be deferred until 12 November 2015.

http://www.lngworldnews.com/australian-regulator-deferring-decision-on-shell-bg-deal/

Saudi Aramco's Supreme Council has named Amin Nasser as chief executive officer of the state oil company of the world's largest exporter, Aramco said on Thursday.

Nasser has been acting president and chief executive officer of Saudi Aramco since April, when his predecessor Khalid al-Falih was appointed Aramco's chairman and also health minister of the world's top oil exporter.

The post of Saudi Aramco chairman had previously been held by Oil Minister Ali al-Naimi, himself a former chief executive of the company. Naimi remains in the ministerial position he has occupied for 20 years.

A statement by Saudi Aramco said the appointment was made after the company's Supreme Council, which was created in April this year, held its first meeting in Jeddah. The council is chaired by Deputy Crown Prince Mohammed bin Salman.

Nasser has been serving as senior vice-president for upstream operations at Aramco since 2008, according to his biography posted on Aramco's website. Nasser joined Aramco in 1982 after earning a degree in petroleum engineering.

The state giant's statement on Thursday did not say who will replace Nasser as senior vice president of upstream.

The council has endorsed a five-year business plan (2015-2019) for the company, Aramco said without providing details.

The 10-member Supreme Council of Aramco was formed after King Salman abolished the Supreme Petroleum Council earlier this year.

Members of the council include Deputy Oil minister, Prince Abdulaziz bin Salman, Oil Minister Ali al-Naimi, Finance Minister Ibrahim al-Assaf, Economy Minister Adel Fakieh, Aramco Chairmain Falih and Fahad al-Mubarak, governor of the Saudi Arabian Monetary Agency, the Saudi central bank.

A previous list of the council's members had not included Prince Abdulaziz, but it is not known if he has only recently been named to the group.

http://www.reuters.com/article/2015/09/17/energy-saudi-aramco-idUSL5N11N04L20150917

Oil and gas producer Samson Resources Corp filed for Chapter 11 bankruptcy protection on Wednesday to carry out a debt-cutting plan reached with key lenders, who will assume control of the company.

The company, owned by private-equity firm KKR & Co, listed assets and liabilities of more than $1 billion in its bankruptcy filing. (1.usa.gov/1P10Jca)

Samson's bankruptcy comes four years after the company agreed to be acquired in a leveraged buyout led by KKR, for $7.2 billion. KKR and its partners on the buyout made a big bet on the future of shale oil and gas, investing $4.15 billion in equity on the deal. The rest was funded with debt.

Lenders agreed to cut Samson's obligations by swapping the $1 billion they are owed for nearly all of the company's newly issued stock. They will also invest $450 million in Samson.

The investment by lenders may be further increased, under certain circumstances, by $35 million to improve liquidity, Samson said.

By filing with the support of the lenders, Samson could be able to implement its restructuring plan in the next few months. The plan must be approved by the U.S. Bankruptcy Court in Wilmington, Delaware.

The group of lenders includes affiliates of Cerberus Capital Management, Columbia Management, Credit Suisse, Eaton Vance Management, Invesco Ltd, New York Life Insurance Co and Silver Point Capital.

Samson follows many smaller commodity producers and related services firms into bankruptcy, including Sabine Oil & Gas, Alpha Natural Resources, Hercules Offshore, Quicksilver Resources and Dune Energy. Crude oil prices have fallen more than 50 percent since the middle of 2014, to less than $50 per barrel. Coal and natural gas prices have also dropped sharply.

As part of its bankruptcy plan, Samson is expected to continue to shed non-core assets that are mostly located in Oklahoma to focus on its best wells in East Texas and North Dakota, according to a plan disclosed prior to its bankruptcy.

http://www.reuters.com/article/2015/09/17/samsonresources-bankruptcy-idUSL1N11N0BD20150917

                                            Last Week   Week Before   Year Before

Domestic Production '000....... 9,117             9,135             8,838



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

U.S. crude oil refinery inputs averaged over 16.5 million barrels per day during the week ending September 11, 2015, 403,000 barrels per day more than the previous week’s average. Refineries operated at 93.1% of their operable capacity last week. Gasoline production decreased last week, averaging over 9.2 million barrels per day. Distillate fuel production increased last week, averaging about 5.1 million barrels per day.

U.S. crude oil imports averaged 7.2 million barrels per day last week, down by 270,000 barrels per day from the previous week. Over the last four weeks, crude oil imports averaged over 7.4 million barrels per day, 4.3% below the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 722,000 barrels per day. Distillate fuel imports averaged 66,000 barrels per day last week.

U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) decreased by 2.1 million barrels from the previous week. At 455.9 million barrels, U.S. crude oil inventories remain near levels not seen for this time of year in at least the last 80 years. Total motor gasoline inventories increased by 2.8 million barrels last week, and are in the upper half of the average range. Finished gasoline inventories decreased while blending components inventories increased last week. Distillate fuel inventories increased by 3.1 million barrels last week but are in the middle of the average range for this time of year. Propane/propylene inventories rose 1.1 million barrels last week and are well above the upper limit of the average range.

Total commercial petroleum inventories increased by 8.5 million barrels last week. Total products supplied over the last four-week period averaged 19.5 million barrels per day, up by 0.7% from the same period last year. Over the last four weeks, motor gasoline product supplied averaged about 9.2 million barrels per day, up by 2.0% from the same period last year. Distillate fuel product supplied averaged 3.6 million barrels per day over the last four weeks, down by 2.8% from the same period last year. Jet fuel product supplied is up 5.6% compared to the same four-week period last year.

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

EIA chart showing declining US NatGas production month by month

The retrenchment in drilling for US oil is threatening to leave a different market short: natural gas.

“The impacts of oil rig counts extend beyond oil: the outlook for US. natural gas is critically dependent on the outcome of this balancing act in US oil rigs,” said Anthony Yuen, a strategist at Citigroup in New York, in a report to clients Wednesday.

“If the oil market remains oversupplied and oil-rig counts fall, the decline in associated gas production would leave the market short of gas.”

Associated gas is the gas that comes out of oil wells along with the crude.

Supplies of this byproduct from fields including the Bakken formation in North Dakota and the Eagle Ford in Texas may fall by about 1 billion cubic feet a day next year as drillers idle rigs in response to the collapse in oil prices. That’s about 7% of US residential gas demand.

The US Energy Information Administration has already forecast that shale gas production will drop in October for the fourth straight month, a record streak of declines.

https://www.energyvoice.com/oilandgas/87945/shales-retreat-threatens-to-leave-us-short-of-natural-gas/

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Exxon Mobil Corporation announced today that its subsidiary, Esso Exploration and Production Nigeria Limited, has started oil production ahead of schedule at the Erha North Phase 2 project offshore Nigeria.

The Erha North Phase 2 project is a deepwater subsea development located 60 miles offshore Nigeria in 3,300 feet of water and four miles north of the Erha field, which has been producing since 2006. The Erha North Phase 2 project includes seven wells from three drill centers tied back to the existing Erha North floating production, storage and offloading vessel, reducing additional infrastructure requirements.

The project is estimated to develop an additional 165 million barrels from the currently producing Erha North field. Peak production from the expansion is currently estimated at 65,000 barrels of oil per day and will increase total Erha North field production to approximately 90,000 barrels per day.

"Executing successful projects such as Erha North Phase 2 ahead of schedule and under budget results from ExxonMobil's disciplined project management approach and expertise," said Neil W. Duffin, president of ExxonMobil Development Company. "We are able to create additional shareholder value by optimizing existing infrastructure, which reduces capital spending requirements and improves capital efficiency."

Duffin said the ahead-of-schedule startup was supported by strong performance from Nigerian contractors, which accounted for more than $2 billion of project investment for goods and services, including subsea equipment, facilities and offshore installation.

"These contracts are bringing direct and indirect benefits to the Nigerian economy through project spending and employment, consistent with project objectives," Duffin said.

ExxonMobil expects to increase its global production volumes this year by 2 percent to 4.1 million oil-equivalent barrels per day, driven by 7 percent liquids growth. The volume increase is supported by the ramp up of projects completed in 2014 and the expected startup of major developments in 2015.



Read more: http://www.benzinga.com/pressreleases/15/09/b5842770/exxonmobil-starts-oil-production-at-erha-north-phase-2-project-ahead-of#ixzz3luXEwFzc

At a time when commodity producers are writing down billions in asset values and cancelling projects around the world, one niche area of the gas market is booming.

Hybrid ships, called Floating Storage and Regasification Units, or FSRUs, offer emerging nations from Egypt to Pakistan a cheaper, quicker way to attack power shortages by importing liquefied natural gas. They cost about $300 million to build, or half as much as an onshore import terminal, and are up and running as much as six times faster, sometimes within as little as a year, according to owners Hoegh LNG Holding Ltd. and Excelerate Energy LLC.

As prices for the fuel slumped 64 percent from last year’s peak, the rout made importing the fuel more popular with new buyers seeking a quicker route to LNG amid soaring power demand. Built at shipyards in South Korea, Hoegh sees as many as 55 such vessels in use within 5 years, from about 20 now and just the one a decade ago.

“The main driver is speed,” Sveinung Stohle, Hoegh’s chief executive officer, said by telephone from the company’s Oslo office. “Demand for FSRUs follows a drastic reduction in the cost of LNG. We see that this has caused a very strong increase in requests.”

Hoegh gained 44 percent this year in Oslo trading. By comparison, the 79-member Bloomberg World Mining Index fell 26 percent, led by Glencore Plc’s 57 percent slump as raw materials from coal to copper plunged.

FSRUs are emerging as the fastest alternative for imports just as nations imposing limits on carbon dioxide emissions turn to gas, which is twice as clean as coal.

With prices down, “environmentally beneficial natural gas delivered as LNG is becoming competitive with coal” in power generation, said Graham Robjohns, the CEO of Golar LNG Partners LP, in a Aug. 27 earnings call. Hamilton, Bermuda-based Golar LNG has 6 operating FSRUs and two on order. Floating terminals account for 28 percent of the import capacity under construction, according to Bank of America Corp.

http://fuelfix.com/blog/2015/09/16/gas-markets-are-clamoring-for-more-lng-ships/

Did Chesapeake Energy take Williams to the cleaners? Chesapeake Energy has just cut a deal with Williams to shave 25 cents per Mcf off their natural gas gathering fees in the Utica Shale. In return for the price cut from Williams, Chesapeake agreed to bring more wells online and increase the volume of the gas they send through Williams’ pipes.

But what’s this? Credible rumours are swirling that Chesapeake, after winning concessions from Williams, is now looking to dump their dry gas (not wet gas) Utica Shale assets in an effort to raise $2 BILLION. Sure looks to us like Chessy just enhanced the value of their assets in the Utica as a way to turn around and sell it…

http://marcellusdrilling.com/2015/09/credible-rumor-chesapeake-shopping-utica-dry-gas-assets-for-2b/?utm_source=dlvr.it&utm_medium=twitter

Brazil's Petroleo Brasileiro SA said on Wednesday that output rose 4.5 percent in August to an all-time high of 2.88 million barrels of oil and equivalent natural gas a day from a year earlier.

Petrobras, as the state-run company is known, said production surpassed an earlier peak of 2.86 million barrels reached back in December.

The company, which is trying to overcome a massive corruption scandal, said the increase in production was mainly due to initial operation of the new Cidade de Itaguaí rig at Lula field in Brazil.

Considering only output in Brazil, Petrobras said it produced 2.69 million barrels of oil and equivalent natural gas a day in August, the highest volume ever for local output.

http://www.reuters.com/article/2015/09/16/brazil-petrobras-production-idUSL5N11M2GR20150916

Image Source: The GuardianThe Guardian reported that fracking for shale gas in the UK should be pursued as an alternative to the use of coal, a taskforce on the controversial technology has concluded, in order to provide a bridge to a low-carbon future.

According to the chairman of the taskforce, former Labour cabinet minister Mr Lord Smith, but shale gas should not receive public subsidy or tax breaks, and the tax revenues arising from its exploitation should be redeployed to develop renewable energy and other low-carbon innovations.

He said that “I can’t see any reason why the shale industry needs tax breaks. If the gas is there and is recoverable and that’s still a big ‘if’ the industry can derive revenue from extracting it.”

He said that “Shale gas is not the answer to climate change. That is a mixture of renewables, nuclear and energy efficiency and other low-carbon sources of energy. But we can’t simply wave a magic wand and say that will happen tomorrow. Shale gas provides a bridge.”

The Task Force on Shale Gas, which is funded by the UK’s shale gas industry but operates independently, found that climate change targets could still be met even with an increase in the use of gas, which is less carbon-intensive than coal. When technologies known as ‘green completion’ are used, which means stopping the leaks of methane from shale wells, the fuel is no more carbon-intensive than conventional gas, and less so than imports of liquefied natural gas from countries such as Qatar.

But the report also found that if gas is to be used for another four decades, as envisaged by the group, then much more effort must be put into carbon capture and storage technologies. These have been problematic, as repeated attempts to set up UK pilot projects over the past decade have yet to produce a result. “The government must get a move on,” said Lord Smith. “I don’t think the reason for the slowness lies in problems with the technology. It is a lack of political will.”

http://steelguru.com/gas-oil/shale-gas-fracking-should-go-ahead-in-uk-taskforce/434652#tag

Norway’s oil production hit 1.56 million barrels per day last month, exceeding an official forecast.

The output figure was up 4% on the tally a year ago and 4.5% above the prognosis for the month of the Norwegian Petroleum Directorate, even as oil prices have sunk to around $47 a barrel for Brent crude.

However, overall liquids production of 1.9 million bpd, including oil natural gas liquids and condensate, was down 37,000 bpd, or 2%, on the previous month while total gas sales of 9.7 billion cubic metres were unchanged.

Dominant state-owned operator is looking to maximise recovery from mature offshore fields such as Gullfaks to fully utilise existing infrastructure.

http://www.upstreamonline.com/live/1411364/norway-rolls-out-barrels?utm_source=twitterfeed&utm_medium=twitter

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Energy ministers, businesses gather in Tokyo to discuss LNG market

Ministers and business delegates from around 50 countries and regions gathered in Tokyo on Wednesday to discuss further development of the liquefied natural gas market and the latest market trends and challenges.

The LNG Producer-Consumer Conference has been hosted annually by the Japanese Ministry of Economy, Trade and Industry since 2012. It comes as the government seeks a manageable way to set LNG prices given the recent increase in imports for thermal plants in the absence of nuclear power following the 2011 Fukushima crisis.

“A market that is flexible and can function better will provide benefits for (both) producing and consuming countries,” Japanese industry minister Yoichi Miyazawa said in a speech.

Flexibility in deciding prices for LNG will help lower costs in Asia, where it mostly trades at higher prices than in Europe or the United States, under long-term contracts linked to crude oil prices, ministry officials said.

Miyazawa also underscored the importance of stable procurement of LNG in the event of emergencies such as natural disasters, adding the issue was expected to be one of the agenda items at a Group of Seven energy ministers’ meeting slated for next May in Japan.

Mohammed Saleh al-Sada, minister of energy and industry in Qatar, and International Energy Agency Executive Director Fatih Birol are among the participants at the fourth LNG conference.

http://www.japantimes.co.jp/news/2015/09/16/business/energy-ministers-businesses-gather-tokyo-discuss-lng-market/#.VflbltJVhBc

Iran to clients - Buy our oil and get joint ventures too

Iran has unveiled details for long-awaited foreign cooperation contracts which it hopes will attract oil buyers and investors to modernise its ageing infrastructure, including offers to take part in joint ventures to extract its huge reserves.

The United Nations endorsed a deal in July to end years of economic sanctions on the Islamic republic over its nuclear programme, although a removal of those sanctions still requires U.S.-Congressional approval.

Pre-sanctions agreements between Iran and foreign energy firms offered partners oil and gas revenue payments in return for cash investment in so-called buyback contracts. But foreigners were barred from joint ventures or from extracting themselves, making these contracts unpopular with investors.

"Iran is going to apply a new version of oil contract model in order to make it more attractive for foreign investors, with similar terms to a PSA (production sharing agreement)," said Shahrouz Abolhosseini, petroleum products pricing manager at National Iranian Oil Company (NIOC), during a business meeting in the South Korean capital on Wednesday.

"NIOC ... aims to embark on joint ventures with foreign investors and international companies in the oil and gas industry," he added.

Also in Seoul, Ali A. Arshi, adviser to the deputy minister for international affairs and commerce at Iran's Ministry of Petroleum, said the main advantage of the new contracts over the previous buybacks would be more contractual flexibility. He did not elaborate.

Tehran's move is a latest attempt to attract buyers beyond offering outright oil discounts, which have included offers of extended credit and free cost of shipping.

"What we can expect from Iran is being creative in the sense that when they approach potential clients they will tie the sale of Iranian crude or Iranian (refined) products to future collaboration," said Bijan Khajehpour, managing partner at Atieh International, which advises companies on investing in Iran.

Khajehpour said there were discussions to favour returning oil buyers with direct investment or joint venture opportunities in Iran.

http://uk.reuters.com/article/2015/09/16/uk-iran-oil-contracts-idUKKCN0RG15020150916

 
Prospects for the country's natural gas market remain strong in long term, despite the economic slowdown, according to the head of one of China's leading developers of unconventional gas resources.

Pierce Li is co-CEO and president of AAG Energy Holdings Ltd, an independent producer of coal bed methane, or CBM, which just raised $363 million in a Hong Kong flotation.

"While domestic demand for natural gas will be affected by the temporary economic slump to an extent, we are confident the Chinese economy will warm up in future," he said.

Through a series of production-sharing contracts, AAG holds majors shares in two gas concessions in the Qinshui Basin in Shanxi province: 80 percent of the Panzhuang concession (spanning 67.4 square kilometers) and 70 percent of the Mabi concession (898.2 sq km).

Panzhuang began production in 2007 and is considered the most commercially advanced Sino-foreign-owned CBM asset in China, and remains the only one to have received full development plan approval. At the end of last year its daily output hit a record 1.4 million cubic meters.

AAG started pilot production of Mabi in the first half of 2010, and in November 2013 received preliminary approval for its first phase of development from the National Development and Reform Commission, with production target of 1 billion cu m per year, starting in 2016.

An International Energy Agency report on coal mine methane in China, published in 2008, revealed China has seven geographic regions with different concentrations. Shanxi and Shaanxi provinces, and Inner Mongolia autonomous region contain the richest sources, with the Qinshui Basin considered the best single area.

China has prioritized the development of unconventional energy to reduce its reliance on coal.

http://en.chinamining.com.cn/News/2015-09-16/1442383135d73747.html

The White House said on Tuesday it does not support a bill in the U.S. House of Representatives to repeal the 40-year-old ban on exports of crude oil.

"This is a policy decision that is made over at the Commerce Department, and for that reason, we wouldn't support legislation like the one that's been put forward by Republicans," White House spokesman Josh Earnest told reporters at a briefing.

"The administration believes that the American people are better served by making sure that we pursue the kind of approach that also invests in renewable energy," he said.

The full House is expected to pass the bill to repeal the ban in coming weeks, after a vote on Thursday in the chamber's energy panel.

Energy interests say the domestic drilling boom could soon choke on a glut of crude if producers are not allowed to ship the oil to consumer countries in Asia and Europe.

A similar bill faces a tough battle in the Senate, however. Even if all 54 Republicans in the 100-member Senate voted for the bill, they would need support from six Democrats to overcome a procedural roadblock.

In July, the Senate energy panel passed a bill to lift the ban, but no Democrats voted for it.

The top Democrat on the panel, Senator Maria Cantwell of Washington state, has said she needs to know more about whether lifting the ban would be good for consumers. Cantwell has also voiced concerns that repealing the ban could increase the number of trains carrying oil through her state.

http://www.reuters.com/article/2015/09/15/usa-oil-exports-whitehouse-idUSL1N11L1SR20150915

Government analysts say shale oil fields in Texas, Colorado, North Dakota and Ohio are set to decline by 80,000 barrels a day this month, bringing their combined daily output to 5.2 million barrels in October.

That brings production declines in the U.S. shale plays to 350,000 barrels a day since the shale boom reached its peak in April, according to the Energy Information Administration’s monthly report on shale drilling productivity.

The oil wells drilled into shale formations have steep natural decline rates because the rock isn’t porous or permeable, making it difficult to squeeze out oil and gas. Shale wells typically give up most of their hydrocarbons in the first year after they’re brought into production.

These shale production losses have come from the Eagle Ford Shale in South Texas, the Bakken Shale in North Dakota, the Utica Shale in Ohio and the Niobrara in Colorado, Kansas, Nebraska and Wyoming. The only oil-focused shale play that didn’t give up production in October was the Permian Basin in West Texas, which is expected to bring up an additional 23,000 barrels a day by next month.

The biggest declines since April have come from the Eagle Ford, which has lost 300,000 barrels a day. The Permian has continued to bring production up, adding 88,000 barrels a day since shale production peaked,according to the EIA.

In the last few days, OPEC and the International Energy Agency put out dueling predictions of how far U.S. oil production will decline over the next year. The Saudi-led Organization of Petroleum Exporting Countries believes U.S. production will still grow next year but only by 50,000 barrels a day, down from its estimate of 400,000 barrels a day this year. And the Paris-based IEA said U.S. production is set to plunge by 400,000 barrels a day next year.

http://fuelfix.com/blog/2015/09/15/eia-shale-output-fell-by-350000-barrels-a-day-since-april/#30727101=0

 "The change of outlook to negative primarily reflects the uncertainties generated by the delay in the start-up of production and cost overruns at the company's Ichthys LNG Project in Australia," says Kailash Chhaya, a Moody's Vice President and lead analyst for INPEX CORPORATION.

"In addition, Moody's considers that the headroom within the company's current rating has been reduced by weak earnings in the current low oil price environment and the increasing level of liabilities related to Ichthys", adds Chhaya.

On 11 September 2015, INPEX announced that the start of production at Ichthys will be delayed to the third quarter of 2017, from the expected start date of end-2016. As of June 2015, the project's overall development was approximately 74% complete. But, a detailed review of its schedule prompted the company to revise the start date.

INPEX also announced that various factors -- including the delayed production start -- will increase by 10% the total project investment, estimated at the time of the final investment decision in January 2012.

INPEX will also likely increase its borrowings to cushion the impact of low oil prices and to fund the additional costs of the project, which will raise adjusted debt/EBITDA leverage. As of 31 March 2015, INPEX's adjusted debt/EBITDA leverage, calculated after treating its Ichthys-related completion guarantees as debt, stood at 2.6x.

Ichthys is critical to INPEX's goal of expanding its daily production capacity to an equivalent of 1.0 million barrels per day, 2.5x its current level, in the next 10 years. At its peak capacity, INPEX estimates that Ichthys will supply about 10% of Japan's annual LNG import volume.

Moody's recognizes INPEX as a government related issuer (GRI), based on direct (19%) and indirect (2%) ownership of approximately 21%, as well as on the government's ownership of a special-class share, or a golden share. When considering the rating of GRIs, Moody's applies a joint default analysis (JDA) composed of four factors: a baseline credit assessment (BCA), the related government's credit quality, its default dependence, and its support probability.

Moody's has assessed INPEX's BCA as baa1, based on the above mentioned fundamental characteristics. If leverage increases due to the planned investments in the Ichthys and Abadi projects, then the opportunity for a ratings upgrade is limited.

The credit quality of the Japanese government, as the potential support provider to the issuer, is A1 with a stable rating outlook.

https://www.moodys.com/research/Moodys-revises-INPEX-CORPs-outlook-to-negative--PR_334522

Canadian oil producer Penn West Petroleum Ltd said it would sell its assets in Mitsue in Central Alberta for $192.5-million in cash to reduce debt.

The company said it would have raised $605-million this year by divesting its non-core assets upon the closing of the Mitsue deal.

Penn West had long-term debt $2.21-billion as of June 30.

The company lowered its budget and cut jobs this month and said it would only spend cash it earned from operations.

The company had also cut its 2015 production forecast to 86,000 to 90,000 barrels of oil equivalent per day (boepd) from 90,000 to 100,000 boepd.

http://www.theglobeandmail.com/report-on-business/industry-news/energy-and-resources/penn-west-to-sell-properties-in-central-alberta-near-mitsue-for-1925-million/article26363857/

Braving all the political risks of the region, Italy's Eni aims to pull together its east Mediterranean gas empire headed by a giant Egypt find, into a major hub to supply Europe.

State-controlled Eni, the biggest foreign oil and gas major in Africa, wants to use its deep ties with Egypt and Libya to help create the export hub for liquefied natural gas.

It expects Libyan gas to flow into a hub when conflict abates, hopes to attract other producers seeking an export outlet from Israel and accelerate plans to send Cypriot gas owned by other companies into the facility, likely to be located in Egypt.

The project would help diversify gas supply to Europe, now dependent on Russia for about a third of its needs, but faces long odds given the region's mix of political disputes, conflict zones and state involvement in energy policy.

Its scope of tying together a multi-national gas supply network may be unprecedented. Pipelines would need to be built linking the various gas deposits scattered across the region to an LNG plant.

"The area (Egypt) could restart exporting LNG and, as it's very close to Italy and Spain where LNG import terminals are idle or underused, it's very likely it will come in there," Eni CEO Claudio Descalzi told Italy's parliament last week.

Descalzi, who has already flown to see heads of state in Egypt and Cyprus where the idea of a gas export hub was discussed, told senators the hub could be established to bring together the resources of Egypt, Cyprus, Israel and at some later point Libya.

"There's massive potential here for Europe and room for Italy to increase its clout in the area. It's clear there are huge amounts of gas, including off Libya," a person familiar with the matter said.

Fuel shortages have forced Egypt to idle its two liquefied natural gas (LNG) export plants, which chill gas into liquid form for transport on ships.

Pooling the region's rich energy resources could spur investment in previously stranded gas fields in Israel and Cyprus, while resuscitating once-bustling LNG export plants like BG's Idku as well as Eni's dormant Damietta in Egypt.

In Cyprus, Eni itself has not yet discovered any gas deposits but is focused on doing so, the company said last week.

Still, the firm's bumper gas find in Egyptian waters this month, the biggest ever in the Mediterranean, may help unlock aspects of the problem by providing large new supplies to feed the gas export hub.

While gas from the newfound Zohr field, holding 30 trillion cubic feet of reserves, will mainly feed domestic Egyptian demand only, a deeper reservoir below it could be a candidate for gas exports.

"Egypt had a plan to double its LNG export capacity and if the hub grows it could do it," Descalzi told Italy's parliament.

The CEO said Eni has made big gas discoveries in Libya that have lain dormant for years because they were unable to develop them as conflict raged, seeing Egypt as one export outlet.

Zohr is also close to Cyprus' offshore block 11 which is licensed to French major Total and the reservoir may extend across the maritime border, creating opportunities for explorers on the Cypriot side.

Israel and Cyprus already have plans to export gas to Egypt but progress has been slowed by regulatory interference and dragging negotiations.

Pulling off the hub project will not be easy given the region's tangle of political disputes.

Turkey opposes any export of Cypriot gas reserves until a long-standing dispute over territory is cleared up and a mechanism for sharing gas profits between the Turkish and Cypriot sides of the island are put in place.

http://www.reuters.com/article/2015/09/15/eni-mediterranean-gas-idUSL5N11H18O20150915

Sunoco Logistic Partners LP is holding a binding open season for a third Mariner East pipeline. The pipeline will deliver Appalachian natural gas liquids (NGL) to Sunoco's Marcus Hook Industrial Complex on the Delaware River south of Philadelphia, USA.

Sunoco said shippers have expressed interest in expanding Mariner East to provide more NGL takeaway capacity from points in eastern Ohio, western Pennsylvania and West Virginia for delivery to Marcus Hook – a former oil refinery that's being repurposed for NGL storage, processing and distribution to local, domestic and international markets.

Sunoco launched the current open season on 10 September.

Sunoco revealed in June that it was considering constructing a third Mariner East pipeline. It would likely follow the 300 mile path of the company's existing Mariner East 1, which runs from Western Pennsylvania to Marcus Hook.

Sunoco is also moving ahead on acquiring the more than 2500 parcels of land, some by eminent domain, needed to expand its Mariner East II pipeline to carry Marcellus shale gas to Marcus Hook.

http://www.energyglobal.com/pipelines/contracts-and-tenders/15092015/Sunoco-holds-binding-open-season-for-third-Mariner-East-pipe/

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Spain's Tecnicas Reunidas and Britain's Petrofac have been selected for contracts worth as much as $4.7 billion to build the Fadhili gas plant in Saudi Arabia for state oil giant Saudi Aramco, industry sources said on Tuesday.

"They received notification last week; a letter of intent," said one of the sources, who declined to be identified as the information isn't public.

Petrofac and Tecnicas declined to comment, while Saudi Aramco said it does not comment on its business plans.

- See more at: http://www.rigzone.com/news/oil_gas/a/140620/Sources_Tecnicas_and_Petrofac_Selected_to_Build_47B_Saudi_Gas_Project?rss=true#sthash.KrrMQxqU.dpuf

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ETPTI reported that global oil majors have slashed spending and cut jobs in response to plunging oil prices but state-owned Oil and Natural Gas Corporation is using the slump to build assets.

Oil majors including Shell, Total and BP have cut capital spending by at least USD 14 billion this year in response to the plummeting oil price.

Addressing company shareholders, Mr Dinesh K Sarraf, CMD of ONGC, said that energy industry, particularly the oil and gas sector, was facing challenging times due to the collapse of crude prices.

He said that oil prices have collapsed from USD 110 per barrel to sub-50 dollars a barrel due to lower growth in demand than expected from China, slow recovery in some of the developed economies and steady build-up of new supplies backed by strong North American output.

Mr Sarraf said that "While many of the global E&P companies have responded to this situation by cutting down their investments, ONGC takes this as an opportunity to build its assets in this environment of lower costs as well. ONGC remains steadfastly committed to the quest of energy security, a national priority endorsed by none other than our Prime Minister."

He said that ONGC has stepped up ongoing development efforts to bring new hydrocarbon volumes into the country's energy basket. Important projects have been given the go-ahead for development and more proposals to monetise our reserves are under various stages of finally being approved.

Having reversed the decline in crude oil production in 2014-15, ONGC is now fully focused on implementing programmes to raise output from ageing and old fields.

He said that "Every drop counts and ONGC's production track record from its predominantly mature portfolio and commercially prudent and holistic management of producing assets is really remarkable."

Improved Oil Recovery and Enhanced Oil Recovery projects to maximise production have yielded positive outcomes in 2014 to 2015 over 34% of ONGC's crude production was a result of investments in these projects.

http://steelguru.com/gas-oil/ongc-bucks-trend-to-build-assets-as-oil-prices-ease/434587#tag

CEFC China Energy has signed a preliminary agreement with an state energy company to provide oil storage for 12.6 million barrels of commercial state crude reserves, two senior sources at the privately held CEFC China said on Tuesday.

The deal, in which the un-identified state company will lease space enough for about two days of China's crude oil imports, lends some near-term support to global oil prices, which have been weighed down by a persistent supply glut.

China has been taking advantage of oil prices more than 50 percent lower than their 2014 peak above $115 a barrel to build up reserves, and in April this year imported more crude than the world's No.1 buyer, the United States.

CEFC China's new tanks, being built in Yangpu port on Hainan island off southern China, will have a total capacity of 17.6 million barrels and are to open at end-2015, several months behind an earlier plan and after a nearby oil terminal is ready for use, the sources said.

Under the heads of agreement signed for the deal, the state company will lease its portion of the tanks for up to six years, said the CEFC China sources, declining to name the state firm involved.

A final contract will be signed after the state company receives government approval to lease the storage, they said.

Just across a road from the CEFC facility is an 8.2-million-barrel crude storage site owned by Vopak - the world's largest independent tank terminal operator - and the State Development Investment Corporation (SDIC).

Commissioning at the Vopak site started early this month, and Vopak confirmed on Tuesday that one large crude oil cargo has been discharged.

The CEFC and Vopak facilities are next to a tank farm owned by state refiner Sinopec Corp, and the three have agreed to connect the depots with pipelines to optimise operations, said one CEFC executive.

The Sinopec farm is also linked with its 160,000 barrel-per-day Hainan refinery.

China's state reserves are split into two categories: strategic petroleum reserves for which the state builds tanks and pays the full cost of storage and oil, and commercial state reserves whereby the state leases tanks and shares the cost of buying oil with companies.

Most of the commercial storage tanks along China's coast are nearly full, and the CEFC and Vopak sites could be among the last available for stockbuilding before China's next strategic storage units are ready, storage and trading sources said.

http://www.reuters.com/article/2015/09/15/china-oil-storage-idUSL4N11L3FC20150915

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China's NDRC will cut natural gas prices for non-residential users by CNY0.5-0.6 per cubic meters, or nearly 20%: MNI...Zerohedge

@zerohedge

Mexico’s finance ministry has set the minimum fiscal terms companies will be required to meet in order to win development rights in an upcoming oil auction.

The country is gearing up for the second round of its auctions in its Round One tender after an historic energy overhaul last year.

The minimum amount of profits required to win development rights varies slightly by contract.

The minimum value of pre-tax profits for the five offshore extraction contract up for grabs range between 30.2 and 35.9%.

The National Hydrocarbons Commission, known by its Spanish-language acronym CNH, is the oil regulator that will run the September 30 auction.

The minimum amount of profits required to win development rights varies slightly by contract.

At the high end, the second contractual area, which covers the Hokchi field, is set at 35.9 percent. Bids for the fifth contractual area on offer, covering the Mision and Nak fields, will require at least 30.2 percent of pre-tax profits for the government.

The five production-sharing contracts covering nine oil and gas fields will be awarded by the CNH based on which company or consortium offers the biggest share of pre-tax profits to the government via a weighted formula that also includes an investment commitment.

The share of profits is 90 percent of the formula, while the investment commitment accounts for the remaining 10 percent.

However, the newly released terms do not require bidders to offer a additional minimum work program investment, although previously established taxes and royalties will also apply.

The contracts are for shallow water exploration and production of tracts located along the southern rim of the Gulf of Mexico near the country’s best-producing offshore fields, Ku-Maloob-Zaap and Cantarell.

https://www.energyvoice.com/oilandgas/87721/mexicos-finance-ministry-sets-minimum-fiscal-terms-for-september-auction/

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North Dakota's oil regulators said on Monday they may allow more wells to be temporarily abandoned, a step that would permit producers to delay fracking beyond the typical one-year window and prevent even more crude from flooding onto global markets.

The change would fuel massive savings for oil producers in the state who have amassed a backlog of almost 1,000 wells that have been drilled but not completed with processes needed to get the oil flowing. The delays are designed solely to ride out the roughly 50 percent drop in crude prices since last year.

Any regulatory change in North Dakota also would assuage market concerns about supply continuing to outstrip demand at a time when Iraq, Saudi Arabia and other OPEC members show little sign of curbing their own output.

While no decision has been reached, the North Dakota Department of Mineral Resources (DMR) is "leaning toward" sharply increasing the number of requests to temporarily abandon wells, director Lynn Helms told reporters on a conference call.

"It's just going to be a whole lot better for everyone if we store the oil in the shale formation instead of in Cushing, Oklahoma," Helms said, a reference to the popular crude storage hub near the geographic center of the United States.

Producers currently have one year to frack and start producing oil from a well. If that window passes, the DMR warns producers they have six months to plug the well or start producing oil. It then moves to confiscate the well if nothing has been done by the end of that six-month window.

The number of North Dakota wells waiting to be completed rose by 70 to 914 in July, and most of them have one-year windows that expire in December, Helms said.

Any decision to allow a well to be temporarily abandoned would be on a case-by-case basis, he said.

"It's a delicate balancing act because royalty owners expect to get royalties from those wells," Helms said.

The one-year window has loomed over corporate budget planning, with many producers hoping to wait as long as possible to bring new wells online.

For example, EOG Resources Inc, which has one of the largest number of North Dakota wells waiting to be fracked, told investors last week it would spend most of its capital budget in early 2016 on fracking new wells.

The rule change could abrogate the need for EOG and peers to start fracking come January.

"This sends a signal to the global markets that the state is not going to force even more oil out there," Helms said.

http://www.reuters.com/article/2015/09/14/north-dakota-oil-production-idUSL1N11K12220150914

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North Dakota's daily oil production fell less than 1 percent in July, state regulators said on Monday, a drop far less than many feared and one showing the state's Bakken shale formation could continue pumping high volumes of crude for the foreseeable future despite sliding prices.

The state, the No. 2 U.S. crude producer, had output of 1,201,920 barrels of oil per day (bpd) in July, down from 1,211,328 bpd in June, according to the Department of Mineral Resources, which reports on a two-month lag.

The slight dip in output came despite a more than 50 percent plunge in crude prices in the past year that has eroded the oil industry's profitability. Indeed, North Dakota's drilling rig count has dropped alongside the price of oil, and is 12 percent below June levels.

Yet advances in technology and efficiencies have helped the productivity of each drilling rig roughly double in the past year, helping the industry do more with less.

Highlighting that gain, the number of producing wells in North Dakota hit 12,940 in July, an all-time high.

Natural gas production rose slightly in the month to about 1,657,138 million cubic feet per day, also an all-time high.

http://www.reuters.com/article/2015/09/14/north-dakota-oil-production-idUSL1N11K12220150914

Murilo Ferreira will take a leave of absence as chairman of state-run oil firm Petrobras, turning his full attention to his job as chief executive of Vale SA as the mining giant grapples with a downturn in the sector.

Petroleo Brasileiro SA, as the company is formally known, did not give a reason for Ferreira's leave, which it said would last until Nov. 30. A company source told Reuters he had requested time off to focus on Vale as it navigates a slump in iron ore prices and a slowdown in China.

Ferreira, 62, who has been CEO of Vale since 2011, was appointed chairman of Petrobras in April as it looked to send a market-friendly signal after a giant corruption scandal resulted in billions of dollars in writedowns.

At the time some mining executives criticized the move, saying Vale was going through a difficult patch and needed the full focus of its CEO. Ferreira shrugged off concerns, saying the double job would only eat into his "leisure time."

But the world's largest producer of iron ore has continued to struggle. Shares in Vale have lost nearly 40 percent over the past 12 months and touched their lowest in a decade last month.

Analysts predict the price of iron ore .IO62-CNI=SI, the main ingredient in steel, will stay low for years after falling more than half since last year.

Despite being one of the world's lowest-cost producers of the mineral, Vale has found itself in a tight spot as its investments are well above those of Australian rivals BHP Billiton and Rio Tinto. Vale is in the process of building a giant iron ore mine in the Amazon known as S11D. The expansion is the world's largest iron ore project at the moment.

http://www.reuters.com/article/2015/09/14/petrobras-chairman-idUSL1N11K0Q620150914

Lukoil, Russia's No.2 oil producer, may sell its treasury shares to raise money or distribute them among shareholders, Chief Executive Vagit Alekperov was quoted as saying on Monday.

Earlier this month, Lukoil, where Alekperov and his deputy, Leonid Fedun, are the largest private shareholders, said its Cypriot unit had increased the percentage of shares held by the company in treasury to 16.2 percent from 11.25 percent.

Alekperov, who held a stake of around 23 percent in Lukoil as of the end of 2014, told the Rossiya-24 TV channel on Monday that the company could use treasury shares to raise money, among other options.

"The first way is to sell them on the stock market and to raise funds for large-scale projects. The second one -- to distribute among our shareholders," Alekperov was quoted as saying. He added the firm had yet to choose a preferred option.

http://www.reuters.com/article/2015/09/14/russia-lukoil-treasury-shares-idUSL5N11K34A20150914

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“There’s just no cash.” That’s the Coles Notes from a senior banker describing the book of oil service loans he manages for one of Alberta’s leading lenders. There’s simply not enough cash flow to support current levels of debt.

Bankers and borrowers have kicked the can down the road about as far as they can as more oilfield service (OFS) and exploration and production (E&P) companies default on their loans and seek more relief on lending covenants. While a significant oil price increase to lift all the sinking boats will surely come, it won’t happen soon enough. More of the same won’t work.

Oil industry debt is everyday news. But the discussion is about the symptoms, not the ailment.

Companies cannot borrow their way out of debt. Equity capital is only available at distressed valuations. Specialized OFS assets will fetch only a fraction of replacement cost—if somebody actually wants them. Although oil and gas reserve valuations are down by half, borrowers are being forced to sell them anyway to repair balance sheets. The last four months of 2015 will be very difficult for any company with meaningful amounts of debt. Same for their lenders, the other signatories to the loan agreement.

As the banker said, “There’s just no cash.” Here’s what it means.

The foundation of global credit markets is based upon the borrower’s capability, obligation and commitment to pay the money back. The amount of money anybody can or should borrow is dependent upon free cash. Not forecast cash flow, not earnings before interest, taxes, depreciation, and amortization (EBITDA), not good intentions. Free cash. How much money is available to service debt after all the other bills are paid. This is the key factor behind every credit application, from a car loan or home mortgage to an operating line of credit or senior secured term debt. The more free cash you generate, the more you can borrow. When free cash drops, the opposite is true.

But what happens when an entire industry can no longer service previous levels of debt?

ARC Financial produces a weekly chart calculating revenue, spending and upstream cash flow for the entire Canadian E&P sector for the current and preceding 14 years. Selected data has been reproduced below. MNP added 1998, 1999 and 2000 from prior reports. ARC calculates total revenue from all oil and gas produced, then deducts direct lifting and operating costs, taxes and royalties and the administrative cost of running the business. The result is “after-tax cash flow,” which is the free cash available for exploration, development, dividends and, of course, debt servicing.



Gross revenue from production sales is in blue and after-tax cash flow in red. The green line is 2015’s estimated cash flow compared to prior years. The figures are not corrected for inflation.

http://www.zerohedge.com/news/2015-09-14/theres-just-no-cash-oil-price-increase-will-not-come-fast-enough-save-alberta

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Iraq aims to export a record volume of Basra crude from its southern terminals in October as it ramps up production, adding to a global oil supply glut.

The oil surplus combined with weakening demand has depressed global crude prices and pitted members of the Organization of the Petroleum Exporting Countries (OPEC) against each other in a battle for market share.

Iraq, the largest OPEC producer after Saudi Arabia, plans to export 3.68 million barrels per day (bpd) of Basra crude, traders said on Monday, citing a preliminary loading programme.

The volume, if realised, would beat a previous monthly record of 3.064 million bpd set in July.

Iraq's decision to split its output into two grades, Basra Heavy and Basra Light, resolved quality issues, enabling the producer to ramp up output, industry sources said.

However, the country tends to allocate more volumes than it can supply each month to avoid disrupting production as it has limited storage capacity to keep excess oil, one industry source familiar with the matter said.

Iraq is unlikely to export more than 2.35 million bpd of Basra Light in October while the volume of Basra Heavy would not exceed 850,000 bpd, he said.

Some of the October cargoes are also expected to be lifted in November instead, according to the source.

Iraq cut official October selling prices (OSPs) for Basra Light and Heavy by 50 cents and $1.10 a barrel, respectively, from the previous month, but these reductions were unlikely to lift spot differentials given the glut, traders said.

In October, Basra Light exports could jump by 800,000 bpd to about 2.8 million bpd, traders said, citing a preliminary loading programme.

The grade has been performing well in the spot market, fetching premiums to its OSP for September-loading cargoes, but the potential jump in supply could depress differentials for cargoes loading in October, traders said.

For Basra Heavy, exports could drop to about 900,000 bpd in October, according to the loading programme.

That would be down from a planned 1.017 million bpd for this month, but remain elevated compared with 600,000-650,000 bpd in July and August, traders said.

Basra Heavy crude sellers are struggling to find buyers for the high export volumes as refiners in Asia want to purchase and process the grade while similar quality Latin American grades can be had at cheaper prices.

Basra Heavy's discount has dropped to as low as $2 a barrel for cargoes loading in September.

Basra Heavy's OSP in the months ahead "will have to drop another dollar to compete with Latin American crude" like Colombia's Castilla and Mexico's Maya, a seller said.

http://www.reuters.com/article/2015/09/14/iraq-crude-exports-idUSL4N11K2UR20150914

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Azeri state energy company SOCAR said on Monday it would transfer less money to the state next year as its revenues had halved due lower oil price.

The former Soviet republic has had to devalue its currency following a sharp decline in the Russian rouble.

"The decline in the oil price has affected our financial condition. Our revenues fell two times," Rovnag Abdullayev, the company's president, said.

Abdullayev did not say to what level the company's revenue fell. Oil and gas account for 95 percent of Azeri exports and 75 percent of government revenues.

The SOCAR president also suggested that next year's state budget should be calculated based on an estimated oil price of $50-$55 per barrel, down from $90 this year.

The 2015 budget anticipates revenues of 19.4 billion manats ($18.5 billion) based on an estimated oil price of $90 per barrel, down from $100 last year. Brent crude is now trading around $50.

SOCAR's Vice-President Suleiman Gasymov told Reuters in February that an average oil price of $60 per barrel would reduce the company's revenues by $510 million this year. In March, SOCAR placed $750 million worth of Eurobonds.

According to SOCAR officials and independent analysts, the production cost of oil for SOCAR is estimated at $15 per barrel, while the oil production cost for BP, which operates some big energy projects in Azerbaijan, is $12 per barrel.

SOCAR will also ask the central bank for a 1.8 billion manats ($1.7 billion) loan, mainly for building its $16.5 billion oil, gas and petrochemicals processing plant, Abdullayev said.

Last year, it had delayed the completion of the complex, outside the capital Baku, by four years until 2030 due to a lack of funds.

"We intend to get 1.8 billion manat worth of credit in the central bank," Abdullayev told reporters.

He said 1.2 billion manats would be used for modernisation of the oil, gas and petrochemical plant, while the rest was expected to be used for current drilling projects.

The first stage of the project, intended to replace SOCAR's ageing oil refinery as well as the Garadagh gas processing plant and facilities of chemicals firm Azerikimya, is estimated to be worth $2.1 billion.

http://www.reuters.com/article/2015/09/14/azerbaijan-oil-idUSL5N11K1HQ20150914

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OPEC on Monday predicted higher demand for its crude oil next year, sticking to its view that a strategy of letting prices fall will curb supply from the United States and other rival producers.

The monthly report from the Organization of the Petroleum Exporting Countries, however, trimmed its estimate for 2016 global oil demand growth and predicted a less dramatic slowdown in non-OPEC supply than the International Energy Agency.

OPEC said it expected demand for its crude next year to average 30.31 million barrels per day (bpd), up 190,000 bpd from last month, despite slower demand growth overall due to a weaker outlook for Latin America and China.

Oil is trading below $50 a barrel, less than half its level of June 2014. But OPEC has refused to cut output, seeking to recover market share by slowing higher-cost production in the United States and elsewhere that had been encouraged by OPEC's former policy of keeping prices near $100.

"Despite moderate economic growth, recent data shows better-than-expected oil-demand in the main consuming countries," OPEC said in the report.

"At the same time, U.S. oil production has shown signs of slowing. This could contribute to a reduction in the imbalance of oil market fundamentals, however, it remains to be seen to what extent this can be achieved in the months to come."

OPEC expects supply from non-member countries to increase by 160,000 bpd next year, a downward revision of 110,000 bpd from last month and marking a sizeable slowdown from growth of 880,000 bpd in 2015.

The 2016 forecast for U.S. tight oil production, also known as shale, was reduced by 100,000 bpd.

But OPEC did not go as far as the IEA, which in its report on Friday said lower oil prices would force non-OPEC to cut output by the steepest rate in more than two decades next year.

The producer group also expects the recent strength in oil demand growth to moderate. OPEC trimmed its estimate of 2016 world oil demand growth by 50,000 bpd to 1.29 million bpd.

http://www.reuters.com/article/2015/09/14/opec-oil-idUSL5N11K1Z320150914

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Oil Search Ltd on Monday rebuffed an $8 billion takeover proposal from Australia's biggest energy company Woodside Petroleum Ltd as far too cheap, although it left the door open to higher offers.

Woodside last week sought exclusive talks with the Papua New Guinea-focused oil and gas producer on a one-for-four share offer, conditional on support from key stakeholders, including the PNG government.

The rejection is a blow to Woodside, which is chasing low cost liquefied natural gas assets in PNG at a time when the company has little new output due to start this decade and its undeveloped projects face challenges in a world of cheap oil.

"The proposal from Woodside from every which way we looked at it grossly undervalued Oil Search," Oil Search Chairman Rick Lee told Reuters.

Oil Search said it was in a strong financial position and highlighted its low-cost operations in PNG, where its output could double in the early 2020s working with giants ExxonMobil Corp and France's Total SA on two liquefied natural gas projects.

Lee said there were unlikely to be any benefits in putting the two companies together, and the board saw Woodside's plan to create a regional LNG champion conflicting with Oil Search's long history as PNG's national energy champion.

The company and its partners did not need Woodside's operational or liquefied natural gas marketing expertise, Lee told analysts on a conference call.

Shareholders found Woodside's proposal unattractive, he added. Oil Search is nearly one-fourth owned by the PNG government and Abu Dhabi's International Petroleum Investment Corp.

"If any proposals are tabled in the future that reflect compelling value for Oil Search shareholders, we will engage on them," Lee said.

Woodside declined to comment on whether it was considering another approach.

"Woodside is surprised and disappointed that the board of Oil Search has rejected the proposal without meeting with Woodside to understand the benefits of the opportunity or to negotiate the terms of a possible merger," it said in a statement to the stock exchange.

Credit Suisse estimated Woodside would have to pay between A$9 and A$10 a share, or at least A$13 billion ($9.2 billion), to snare Oil Search, well above its A$11.4 billion value on Monday.

The PNG government last year bought its 9.8 percent stake in Oil Search for A$8.20 a share, so it's unlikely it would sell for less than that.

"The door's been closed pretty firmly in their face," Credit Suisse analyst Mark Samter said.

Investors said Woodside shareholders had little to gain from paying a bigger premium and said they doubted Woodside would sweeten its offer.

"They're seen not to have been frivolous in the past with their bid prices. For that reason, I think they're most likely to walk away from a tie-up with Oil Search," said Simon Mawhinney, chief investment officer at Allan Gray, which owns Woodside shares.

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LNG Limited informed that it has agreed a schedule to conclude pricing negotiations and subsequent signing of the turnkey EPC contract for the Magnolia LNG project with the KBR‐SK joint venture in the fourth quarter 2015.

KSJV will provide LNGL a fixed‐price on the full 8 mtpa project, as well as a 6 mtpa project, providing certainty of pricing for a six‐month period from the EPC contract’s effective date, the company said in a project update.

The two firm KSJV prices allow LNGL flexibility in its FID decision to match a firm EPC contract price with the outcome of ongoing liquefaction capacity marketing efforts, without further KSJV negotiations during the six‐month period.

As part of the EPC contract, the KSJV will fully guarantee the LNG production and fuel gas efficiency of each train at the guaranteed production rate of 206 metric tons/hour (1.7 mtpa equivalent) and fuel gas efficiency of 8%, incorporating the OSMR process design provided by LNGL.

LNG Limited also revealed in the update that FERC’s draft environmental impact statement comment period for Magnolia LNG project has expired on 8 September.

One substantive comment was received from the National Marine Fisheries Service recommending the resolution of certain dredging issues in advance of the final EIS. Magnolia LNG is working with FERC, NMFS and the Army Corps of Engineers on this matter and expects to have it resolved promptly, the company said.

LNG Limited also added that marketing of binding offtake agreements for the remaining 6 mtpa of Magnolia LNG capacity continues with a number of investment‐grade, as well as some non‐investment grade counterparties.

Certain negotiations (with investment‐grade counterparties) are advanced and progressing through the internal investment decision authorisation processes attendant to each counterparty.

Each of the offtake negotiations are for initial 20‐year terms, with some taking the form of a liquefaction tolling agreement and some being LNG sale and purchase agreements, LNGL said

http://www.lngworldnews.com/lngl-advancing-talks-over-magnolia-lng-remaining-capacity/

Repsol has received approval from Canadian regulators to begin exporting liquefied natural gas (LNG) from its Canaport import facility.

The National Energy Board of Canada granted a 25-year permit to import as much as 312 billion cubic feet of natural gas per year by pipeline from the US and western Canada.

It will then be converted to six million metric tons of LNG at a new on-site facility.

The project is one of four LNG export terminals proposed in Canada aimed at shipping North American natural gas to markets overseas.

Canada’s energy regulator has acknowledged the deluge of recent applications but also indicated it was unlikely all would survive.

In its proposal, Repsol downplayed concerns about supply, saying it was “evaluating the prospects of sourcing feed gas supply from Western Canada and/or the United States.”

But only one pipeline, Spectra’s Maritimes & Northeast (M&NP), currently connects the region with the vast Marcellus shale gas deposit beneath Pennsylvania, Ohio and West Virginia.

Recent proposals to build pipelines through the US Northeast have met resistance from local environmentalists.

Canaport was built in 2009 to supply the Canadian and US markets, but the shale boom in the United States has since left it underused.

https://www.energyvoice.com/oilandgas/87587/repsol-wins-approval-from-canadian-regulators-to-export-lng/

Chinese state-owned energy giant Sinopec Group will sell off most of its hotels by the end of 2017 and get rid of more than 4,000 company cars as part of efforts to root out corruption and waste, it said on Monday.

Since President Xi Jinping's appointment in 2013, the government has cracked down on official corruption and extravagance in China, where the flaunting of personal and often illicit wealth and wasteful public spending have led to widespread criticism of the party.

The big state-owned conglomerates have been a particular focus, and several high-ranking executives or former executives at Sinopec have been investigated or jailed. Sinopec Group is the parent of Sinopec Corp, Asia's largest oil refiner.

In a statement released by the Communist Party's graft-busting Central Commission for Discipline Inspection, Sinopec said that the latest inspection by anti-corruption teams had been very effective at rooting out problems.

"It has hit the nail on the head, grasping the essence and crux (of the issue), helping us to find the root of the disease," it said.

As part of company efforts to rein in spending, all the hotels it runs will be sold off by late 2017, apart from a "small number" that are competitive or are in exploration areas with no other hotels, it said.

State-owned firms in China tend to be very diversified and often own assets that have nothing to do with their core business.

The number of cars the company operates will also be slashed by 4,300, it added, a move in line with other government-run organisations and departments.

The probe found a series of other problems of waste, including a holiday two executives took to Taiwan in 2013 on the company dime, and four people who did not return to China immediately after a board meeting in gambling hub Macau.

Sinopec is not the only state-owned energy company to have been probed by the graft watchdog.

In a statement released late on Sunday, China National Offshore Oil Corp, better known as CNOOC, listed the steps it was taking to address the problems inspectors had found there, including promising not to use company money to buy high-end cigarettes and liquor.

http://www.reuters.com/article/2015/09/14/china-corruption-sinopec-idUSL4N11K1DF20150914

In the week ended September 11, the number of rigs drilling for oil in the United States totaled 652, compared with 662 in the prior week and 1,592 a year ago. Including 196 other rigs drilling for natural gas, there are a total of 848 working rigs in the country, down by 16 week over week and down 1,083 year over year. The data come from the latest Baker Hughes Inc. (NYSE: BHI) North American Rotary Rig Count.

Last week marks the second consecutive week with a substantial drop in the rig count.

The number of rigs drilling for oil in the U.S. is down by 940 year over year and down by 10 week over week. The natural gas rig count fell by six, from 202 to 196. The count for natural gas rigs is down by 142 year over year.



Read more: Oil Rig Count Down by 10 Last Week; US Production Declining - 24/7 Wall St. http://247wallst.com/energy-economy/2015/09/12/oil-rig-count-down-by-10-last-week-us-production-declining/#ixzz3lgo7UagF
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INPEX Corp. has announced it has increased the expected production capacity of the Ichthys LNG Project to 8.9 million tpy, an increase of approximately 6% compared to the initial 8.4 million tpy. Initially, the product was expected to start towards the end of December 2016, but is now expected to begin in 3Q17. It is expected that these two updates will increase the project’s investment by approximately 10%.

This increase in production capacity is based on the company’s recent evaluation of the latest technological information pertaining to the entire LNG production system.

“The Ichthys LNG Project is a world-class project with an expected operational life of at least 40 years. All the LNG initially planned to be produced from the project has been sold. Of this, about 70% of the LNG is set to be supplied to Japan, and this is expected to further contribute to the long-term, stable supply of energy to the country and improve Japan’s energy procurement risk management,” said INPEX Corp. President & CEO, Toshiaki Kitamura. “The project is also expected to make a significant contribution to the social and economic development of Australia, one of the world’s foremost producers of energy.”

http://www.lngindustry.com/liquid-natural-gas/11092015/INPEX-Corp-raises-LNG-production-1272/

Some U.S. oil producers are trying to sell parts of their lucrative saltwater disposal businesses in a sign that cheap crude is already forcing cash-starved companies to sell assets so oil can keep flowing.

Many oil companies rely on outside contractors, which tend to be small, privately-held companies, to inject the briny byproduct of crude production hundreds or thousands feet deep into the earth, well below the water table.

But for producers which own such facilities, the high-margin business has served as a source of cost savings and steady revenue, factors that also make them appealing to yield-seeking investors in master limited partnerships (MLPs) and private equity funds.

SandRidge Energy Inc and Oasis Petroleum Inc are two publicly traded oil producers openly marketing their saltwater divisions. SandRidge is planning to raise cash by listing it as an MLP and Oasis is seeking at least a partial sale.

"The psychology of the market is pretty bad right now," said Andrew Coleman, an energy analyst at Raymond James. "Any sale of these assets gives financial visibility without having to carry the cost of the asset on their books in what could be a rocky next few months."

Putting even a part of such businesses on the block suggests some energy executives are coming under increasing pressure to part ways with good, albeit non-core, assets to ride out the crude market slump and finance core oil operations.

The SandRidge and Oasis transactions could bring each company $100 million or more at a time when capital market funding is drying up and cash is tight as crude oil trades at less than half mid-2014 levels, analysts say.

Other publicly held energy companies with notable saltwater units include Devon Energy Corp, MidStates Petroleum Co and Ferrellgas Partners LP. So far only SandRidge and Oasis have publicly discussed their spin-off plans.

The U.S. Environmental Protection Agency figures show more than 9.5 million barrels of brine and other liquid byproducts gets pumped into some 28,000 saltwater disposal wells around the country.

With disposal fees ranging from 25 cents to $1 per barrel, large wastewater operations can generate hundreds of millions of dollars in annual revenues for investors.

And given that the volumes of water extracted alongside oil tends to increase as wells age, in some cases reaching as much as five barrels for every barrel of crude produced, rates have held steady even as crude prices tumbled and production tapered off

http://www.reuters.com/article/2015/09/11/usa-oil-water-idUSL1N11G32P20150911

U.S. commercial crude stocks are still close to their highest levels in over 80 years, but operational requirements prevent refineries filling on-site storage facilities to their maximum capacity.

An increasing proportion of U.S. crude oil stocks is held in off-site tank farms, some owned or leased by refiners themselves, but many owned or leased by marketers and traders.

According to the Energy Information Administration (EIA), which surveys storage capacity every six months, total crude in storage at the end of March was 475 million barrels, and the country had capacity to store up to 660 million.

Only 182 million barrels of storage capacity, around 28 percent, was on site at oil refineries. The rest was off site at tank farms or in pipelines, railroad tank cars, barges and oilfield tanks.

Most of the crude at refineries and tank farms is stored in giant cylindrical tanks with a roof that floats directly on the surface of the oil.

Storage tanks need to be kept filled to a minimum of around 20 percent to support the roof and operate the pipes and other equipment.

Adjusted for these tank bottoms, the effective or "working" capacity of refinery storage tanks was 150 million barrels, according to the EIA ("Working and net available shell storage capacity", May 2015).

But at the end of March, U.S. refineries were storing only 104 million barrels, equivalent to just 69 percent of their maximum working capacity and 57 percent of the total storage volume.

Refinery storage is subject to various operational constraints that make it hard for refiners to fill tanks to the top.

Refinery tanks are commonly divided into storage tanks, which receive the crude oil, and charging tanks, which feed crude into the atmospheric distillation units 

With so many constraints on charging and discharging, minimum residence, unintended mixing of crudes, and continuously feeding distillation units, refineries cannot operate with their storage and charging tanks anywhere near full.

Refineries are prevented from filling all their tanks to the brim by the need to preserve some flexibility for scheduling changes ("Crude oil scheduling in refinery operations", 2003).

It is easy to see why U.S. refineries were storing only 104 million barrels at the end of March even though they had working capacity to store 150 million and total capacity of 182 million.

The amount of crude stored in the United States has been rising since around 2005. But the working storage capacity at U.S. refineries has remained roughly unchanged. Most of the extra capacity has been added at tank farms.

Tank farm capacity has grown rapidly to meet both the refineries' need for more operational flexibility and heightened demand for medium-term storage from crude marketers and traders.

Some of the tank farms are owned or leased by refiners themselves to give them access to more off-site storage options.

Others are owned or leased by traders who use them for speculative storage, especially when the futures market is trading in contango.

At the end of March, tank farms held almost 240 million barrels of crude, more than twice as much as the refineries.

Tank farm storage is subject to many of the same constraints that affect operations at refineries. Tanks cannot normally receive and send crude at the same time, need to minimise the amount of unintentional mixing, and must generally be kept at least 20 percent full.

But because one tank farm can hold crude that can be used at a number of refineries, the space can be effectively shared, providing important flexibility at lower cost than on site at a single refinery.

As U.S. refineries increasingly process a mix of very light domestic shale crudes and heavy imported oils, tank farms are being used to meet the requirement for more blending capacity.

Refineries tend to hold crude for immediate use because space within the tank farm is at a premium: filling a tank with crude and leaving it idle for weeks or months at a time significantly reduces the refinery's scheduling flexibility.

Tank farms are more suitable for medium-term storage of crude because they can hold oil for months at a time with no operational penalty.

http://www.reuters.com/article/2015/09/11/usa-refineries-oilstorage-kemp-idUSL5N11H1PO20150911

A slump in oil prices is forcing the oil and gas services industry for the first time in 15 years to trim costs in a way that executives say will create a lasting change away from their usual lavish way of doing business.

Navigating a new environment in which oil prices have halved in a year and their customers are slashing investments, oil service firms face a rough ride.

"The industry has been quite lazy in changing because oil prices have been helping us a lot," Samir Brikho, chief executive of oil service engineering company Amec Foster Wheeler , told Reuters.

"At a time like this, you need to take a look at how you can take out the fat. Once we have done this we will never go back, this will become the new norm."

The previous oil price plunge in 2008-2009, driven by the global financial crisis, ended too soon to force oil service firms seriously to reassess their cost structures.

Now, as oil prices have failed to rebound in over a year, oil service companies are depending on running their businesses more efficiently to survive.

This week's biennial gathering of the offshore oil services sector in Britain's oil capital, Aberdeen, highlighted the extent of cost savings being made.

British oil service heavyweights including Wood Group and Petrofac, as well as London-headquartered Seadrill , had no presence among the 1,500 exhibitors at the conference.

"It shows how seriously they take the cost-cutting," said one conference attendee who works in the industry but declined to be identified.

Britain's oil and gas industry lobby group estimates the sector will reduce costs by 2.1 billion pounds ($3.2 billion) by the end of next year.

A large part of these savings is related to job cuts. Oil & Gas UK estimates the industry has already shed 65,000 jobs since peak employment at the start of last year. The group expects employment in the sector to drop further in coming months.

Companies say they are making changes in working practices that mean the sector is less wasteful, such as cooperating better on projects and standardising equipment.

"It's this transformation that needs to be sustained," said Andy Samuel, chief executive of Britain's newly created oil and gas regulator.

http://uk.reuters.com/article/2015/09/11/britain-oil-services-idUKL5N11F3X920150911