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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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

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/

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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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

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

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/

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/