PetroChina Co., the country’s biggest listed oil and gas producer, said full-year net income in 2016 fell by as much as 80 percent, putting it on pace to report a record-low profit.

The slump is due to lower international oil prices and domestic natural gas prices dropping “drastically” compared with the previous year, it said in a filing with the Hong Kong stock exchange on Wednesday. The company reported net income of 35.5 billion yuan ($5.16 billion) in 2015, which means profit last year may have fallen to as low as about 7.1 billion yuan, down for a third year to the least in data going back to 1996.

“It’s slightly better than what we were expecting, but overall it’s largely in line with guidance,” said Neil Beveridge, a Hong Kong-based analyst Sanford C. Bernstein & Co. “As oil prices recover, we’ll see a strong recovery in earnings in 2017.”

The warning comes after the company in October said third-quarter profit dropped 77 percent and it barely eked out a half-year profit. The company will continue to improve cost cutting in 2017 and it expects oil prices to rise as the global market rebalances, it said in its statement. The company may report full-year results on March 30, according to Bloomberg estimates.

Brent crude averaged about $45 a barrel last year, down from almost $54 in 2015. The government cut gas prices in November 2015 in order to spur consumption. The slump in oil prices has punished China’s state-run producers, who were forced to cut production at fields that were too expensive to operate.

https://www.bloomberg.com/news/articles/2017-01-25/petrochina-warns-net-income-dropped-as-much-as-80-in-2016

The chairman of Libya’s National Oil Corporation, Mustafa Sanalla, today announced plans to allow foreign oil companies to invest again in Libyan oil production:

 “We intend in the coming months to lift our self-imposed moratorium since 2011 on foreign investment in new projects to achieve the best national interest for the Libyan oil sector and for Libya as a state.”

 In a keynote address at Chatham House’s Middle East and North African Energy conference,    Mr. Sanalla said NOC-driven projects to expand oil production could create a virtuous circle of domestic economic stimulus and security, while raising Libyan oil production to a forecast 1.25 million bpd by the end of 2017 and 1.6 mln bpd by 2022.

 Sanalla said after three years of blockades by the Petroleum Facilities Guards, all major oil export routes were now open. Investment in oil production capacity was needed to build on the opportunity created after the central Petroleum Facilities Guards under Ibrahim Jadhran were removed from the ports of the Oil Crescent by the Libyan National Army in September, and flows from the Shahara field were unblocked.

 “The LNA has its hands on the taps. And the Government of National Accord (GNA) has [UN Security Council resolutions] 2259 and 2278. Each side has one key to the treasure room, but both keys are needed to open the door. And for the moment the oil is flowing. This can be an important foundation of stability in Libya if we build on it.”

 Saying the oil sector had suffered from chronic under-investment, Sanalla continued:

 “We cannot rely on the international community to save us. We don't know when the transitional period will end. We cannot stand back and do nothing while the state disintegrates. The integrity of NOC is the best guarantee we have that Libya will be preserved as a unitary state.”

http://noc.ly/index.php/en/new-4/2018-national-oil-corporation-ends-foreign-investment-moratorium

Germany’s major oil and petrochemical companies, including BASF, have expressed their willingness to invest a total of $12 billion in the Iranian oil sector.

The Chemical company BASF, whose managing director paid an official visit to Iran last year as a member of a delegation accompanying German Economy Minister Sigmar Gabriel, has offered to invest in a six-billion-dollar project to establish petrochemical sites in southern parts of Iran.

Over the past year, numerous meetings have been held between Iranian oil ministry officials and German companies and if they are finalized and lead to contracts between the two sides, $12bln of investment will be made in Iran by the Western European country.

Wintershall Holding GmbH, Germany’s largest crude oil and natural gas producer and a wholly owned subsidiary of BASF, is another company that has signed a memorandum of understanding (MoU) with the National Iranian Oil Company (NIOC) to make studies on four oil fields west of Iran.

There has been a new wave of interest in ties with Iran since Tehran and the Group 5+1 (Russia, China, the US, Britain, France and Germany) on July 14, 2015 reached a conclusion over the text of a comprehensive 159-page deal on Tehran’s nuclear program and started implementing it in January 2016.

The comprehensive nuclear deal, known as the Joint Comprehensive Plan of Action (JCPOA), terminated all nuclear-related sanctions imposed on Iran.

The promising prospect of trade with Iran has prompted major European countries to explore the market potential in the populous Middle East nation.

http://ifpnews.com/news/business/energies/2017/01/germany-interested-in-making-12-billion-investment-in-irans-oil-industry/#.WIdb5AYe3h0.twitter

Russia is the gas supplier of choice for European markets and will remain the most cost-effective and reliable source of gas in Europe, Alexander Medvedev, Gazprom's deputy CEO, said Tuesday.

Speaking at the European Gas Conference in Vienna, Medvedev said US LNG had been a "big hope" for Europe, but that the record flows of Russian gas to Europe in 2016 -- almost 180 Bcm -- were evidence of Russia's position as the leading gas supplier to its European partners.

"Russia is the only gas supplier that can reliably and flexibly supply gas in any amount. We can supply whatever Europe wants -- we have the capacity to supply an additional 150 Bcm/year," he said.

In an apparent reference to US LNG exports starting up in February last year, Medvedev said Europe had chosen Russian gas despite there being newer supply options.

"Our clients have a variety of diversification options, but they still buy Gazprom gas," he said. "This is a good indicator that -- in the face of new alternative gas resources -- our gas is and will be the most competitive in Europe."

He added that LNG supplies were dependent on "volatile" prices, whereas pipeline supplies under long-term contracts were more reliable.

Gazprom chairman Viktor Zubkov, also speaking at the Vienna conference, said the company was "not afraid of commercial competitors or other energy resources."

European demand for Russian gas was buoyed last year by relatively low prices.

Russian flows last year to Europe and Turkey -- but not including the countries of the former Soviet Union -- were up by 20 Bcm compared with 2015.

Asked if Gazprom also looked to boost supplies to European hubs in a bid to raise market share, Medvedev said its supplies to its trading subsidiaries in Europe -- Gazprom Marketing & Trading in the UK and Wingas in Germany -- under their long-term contracts were reflected in the sales figures, as were the volumes sold in its 2016 gas auction for delivery into Germany.

This suggests Gazprom could have sent maximum possible volumes to its own subsidiary companies in Europe last year, which would have boosted its market share.

'FLEXIBLE CONTRACTS'

Medvedev again highlighted Gazprom's ability to react to customer demands for more gas.

"We have very flexible contracts and very good prices, and this means we can react on a daily basis to requests from our European partners," he said.

Asked if the long-term gas supply contract model was under any threat, Medvedev replied that the system still worked.

"We feel comfortable -- we are delivering as much gas as needed under our long-term contracts," he said.

He added that Gazprom had 4 Tcm of gas contracted under long-term agreements out to 2035, giving it security of demand for the next two decades and certainty for investing in new infrastructure -- especially its planned pipeline projects to Europe.

"There is no better way to finance projects than long-term contracts -- we are ready to sign new long-term contracts to finance new infrastructure," he said.

There has been some shift in Gazprom behavior in the past few years, including auctions and agreeing shorter term contracts.

For 2017, Gazprom signed a one-year supply deal with Lithuania, but Medvedev said talks were ongoing about returning to a longer-term export deal.

"Now we see a strong desire from Lithuania to sign a five- or 10-year contract. We have a one-year deal now, but we are in talks with them to go back to long-term contract," he said.

POLITICAL ANGLE

Medvedev also urged European policymakers to encourage more gas consumption against the background of climate change policy and to allow Gazprom to build new pipeline routes to Europe.

"Europe needs a consistent energy policy that is compliant with COP21," he said.

He also said that reliable gas supply was a "huge political question" that needs a political answer "now".

"Despite price volatility, Gazprom is still moving forward with its capital investments in Europe," he said.

Medvedev's views were echoed Tuesday by Zubkov, who said Gazprom's policy was directed toward long-term reliability of supply to Europe.

But, he said, the company could only supply gas via pipelines European politicians would allow.

This is a reference to political opposition to Gazprom's planned Nord Stream 2 and TurkStream pipelines.

"This is a very challenging situation for our company," Zubkov said. "It would be a pity if we would be politically forced to use routes that are not so favorable to us," he said.

Manfred Leitner, head of downstream at Austria's OMV, also said Europe needed to shift its political attitude toward Russia.

"Political Europe needs to urgently reconsider its neighborhood approach to Russia," he said.

http://www.platts.com/latest-news/natural-gas/vienna/gazproms-medvedev-dismisses-role-of-us-lng-in-26646341

Gas usage in Japan, the world's biggest importer of the fuel in liquid form, this week hit daily records in the cities of Tokyo and Osaka, with residents cranking up heating as a cold snap grips the country.

Japan's biggest city gas supplier, Tokyo Gas, on Wednesday said gas usage in the capital reached just over 60 million cubic metres (2.1 billion cubic feet) the day before as average temperatures there fell as low as 2.5 degrees Celsius (36.5 degrees Fahrenheit). That eclipsed Friday's record of 59.5 million cubic metres.

Osaka Gas, which serves Japan's second-biggest metropolitan area, said gas usage marked a record 36.8 million cubic metres on Monday in the face of similar temperatures.

Gas, along with electricity, is typically used for heating in Japan's main cities as they have pipe networks.

In more rural and other urban areas, kerosene is often used to warm buildings, with sales also climbing as temperatures drop and heavy snow falls in many places.

Kerosene sales rose nearly 6 percent to 550,000 barrels per day in the week to Jan 21 from a week earlier, Japan's petroleum association said on Wednesday.

Temperatures fell to below -30 degrees Celsius on the northern island of Hokkaido, national broadcaster NHK said on Tuesday.

Japan's liquefied natural gas (LNG) imports dropped for a second year in a row to 83.34 million tonnes, the government said on Wednesday.

Prices for LNG spot cargoes for Japan rose for a third month to a 16-month high in December, gains that are attracting increasing supplies to Asia from as far away as the U.S. Gulf Coast.

http://www.reuters.com/article/japan-gas-demand-idUSL4N1FF1UJ

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The PNG LNG terminal project in Papua New Guinea has ample supply options to facilitate a capacity upgrade and has operated well above its nameplate capacity over October-December 2016, Australia-listed project participant Oil Search said in its quarterly report released Tuesday.

"A likely upgrade in the PNG LNG project reserves, together with resources in Elk-Antelope, P'nyang and the new Muruk discovery, support Oil Search's view that there is more-than-sufficient discovered gas resources in PNG to supply not only to the proven expanded capacity of PNG LNG trains 1 and 2, but also to at least two, and possibly three, expansion trains," the company said in the report.

The PNG LNG project is a two-train 6.9 million mt/year nameplate capacity integrated LNG project operated by ExxonMobil PNG Ltd., which has a 33.2% interest in the project. Oil Search has 29% stake.

The discovery of gas by the Muruk 1 exploration well was a key hightlight during the December quarter, Oil Search's quarterly report said.

"Given that Muruk is only 21 kilometres northwest of the nearest Hides well, it is a prime candidate to be tied into the PNG LNG project infrastructure, to support potential LNG expansion, if appraisal activities are successful," it said.

Formal talks on an expansion are expected early this year, RBC Capital Markets analyst Ben Wilson said Tuesday.

"One of the key upcoming catalysts we are looking for is forming commercial arrangements with ExxonMobil, Total, and Santos around expansion plans for two trains at the PNG LNG site," he said.

"Formal talks are now expected in early-2017, contingent on ExxonMobil's acquisition of Interoil. This would put the JV partners in a good position to begin negotiations with the PNG government, following the mid-year elections," Ben said.

PNG LNG produced at an annualised rate of approximately 8.3 million mt/year during October-December 2016, up from 8.1 million mt/year in July-September and 20% higher than the nameplate capacity of 6.9 million mt/year, Oil Search's quarterly report said.

LNG production from PNG LNG net to Oil Search during the October-December 2016 quarter was 26,560 mmscf, compared with 24,805 mmscf a year earlier and 25,864 mmscf in the July-September 2016 quarter, the report said.

The full-year net production from the terminal for Oil Search was 101,827 mmscf, up from 96,646 mmscf in 2015, it said. For 2017, it is expecting 101 bcf-104 bcf, Oil Search said in its guidance Tuesday.

Other stakeholders in the PNG LNG project are: Santos (13.5%), National Petroleum Co. of PNG (16.8%), JX Nippon Oil and Gas Exporation Co. (4.7%) and Mineral Resources Development Co. (2.8%).

http://www.platts.com/latest-news/natural-gas/sydney/papua-new-guineas-png-lng-well-positioned-for-26646315

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Add Southern Green Canyon and Mars Blend to the growing list of American crude that’s challenging OPEC’s dominance in the world’s biggest oil market.

Cargoes of the two varieties produced in the Gulf of Mexico, which are heavier and more sulfurous than supply from U.S. shale fields, are poised to flow into Asia as they turn cheaper relative to similar-quality crudes from nations such as Saudi Arabia and Oman.

The deal between producers worldwide to cut output and ease a glut is boosting the cost of Middle East supplies, priced against the Dubai benchmark, because most of the reductions are coming from the region. Meanwhile, U.S. marker West Texas Intermediate is turning relatively weaker as a rebound in global crude prices from the worst crash in a generation is spurring more American rigs into action. Shale oil that was already cheap enough to sail to Asia is now being joined by cargoes from more traditional fields.

“Flows of Mars and Southern Green Canyon to Asia are extremely rare,” said Nevyn Nah, a Singapore-based analyst at industry consultant Energy Aspects Ltd. But “the move is currently viable as Dubai has strengthened against other benchmarks such as WTI, following the Saudi-led output cut,” he said.

Asia is buying oil from as far away as the U.S. because of a shortage of supplies of medium-heavy crudes, according to Nah. Refinery shutdowns for maintenance work on the U.S. Gulf Coast mean that grades such as Southern Green Canyon are available and cheap enough to be shipped to other regions, he said.

WTI’s cost fell below Dubai in December for the first time in at least three months. The U.S. benchmark was at a discount of $1.08 a barrel to Dubai on Tuesday. Mars and Southern Green Canyon are even cheaper than WTI because they are more difficult to refine.

Oil explorers last week put the most rigs back to work in U.S. oil fields in almost four years, according to data from Baker Hughes Inc. Oil output in the nation rose to the highest level since April in the week ended Jan. 6, while crude stockpiles surged by the most since November during the same week.

Japanese refiner TonenGeneral Sekiyu K.K. bought Southern Green Canyon from BP, while Mars Blend is being offered to Asian customers. The tanker Manifa is sailing to Singapore after loading Southern Green Canyon, Eagle Ford shale crude and fuel oil via a series of ship-to-ship transfers, according to Matthew Smith, director of commodity research at ClipperData LLC, a firm that analyzes and tracks oil flows globally.

Such arbitrage trades became viable as cargoes turned relatively cheaper compared with similar-quality Oman crude, a Bloomberg survey showed last week. Additionally, the premium for Brent crude, the benchmark for more than half the world’s oil, against Dubai narrowed to a 16-month low of $1.46 a barrel this month, providing an incentive for Brent-linked grades to flow from the Atlantic Basin to the Asian market.

Market Competition

Such shipments from the Americas as well as Europe and Africa are making oil sales to Asia more competitive. It’s also influencing the strategy of traditional dominant suppliers such as Saudi Arabia. In January, the largest oil exporter was focusing its output curbs on its Arab Medium and Arab Heavy grades while continuing to pump lighter crudes to compete better with U.S. shale and African supply.

But that’s in turn boosted the cost of more sulfurous heavy crudes in Asia, creating an opportunity for relatively cheaper and similar quality U.S. supply to flow east.

“Newer and complex refineries in Asia have no problem refining heavier crudes from the U.S. Gulf Coast, as long as the economics make sense after factoring freight and market structure,” said Tushar Tarun Bansal, director at industry consultant Ivy Global Energy in Singapore. “Arbitrage flows of heavier crudes from U.S. Gulf Coast to Asia will remain an opportunistic trade.”

https://www.bloomberg.com/news/articles/2017-01-23/opec-helps-cheap-u-s-oil-find-its-way-to-group-s-top-customers

Good news for natural gas drillers in general, and Marcellus/Utica drillers in particular:

Our favourite government agency, the U.S. Energy Information Administration (EIA) predicts the average price for natural gas in the U.S. will rise in both 2017 and 2018.

EIA expects the Henry Hub natural gas spot price to average $3.55 per million British thermal units (MMBtu) in 2017 and $3.73/MMBtu in 2018, both higher than the 2016 average of $2.51/MMBtu.

Higher prices in 2017 and 2018 reflect natural gas consumption and exports exceeding supply and imports, leading to lower average inventory levels…

http://marcellusdrilling.com/2017/01/eia-says-natgas-prices-heading-higher-this-year-next/

Update: it's official, Trump has signed an executive order which will renegotiate the terms of the Keystone XL and Dakota Access pipelines:

TRUMP SAYS GOING TO RENEGOTIATE TERMS ON KEYSTONE
TRUMP SIGNS EXECUTIVE ORDER ON KEYSTONE PIPELINE
TRUMP SIGNS ORDER ON DAKOTA ACCESS PIPELINE
TRUMP SAYS `WE'RE GOING TO MAKE THE PIPE' IN U.S.
TRUMP SIGNS THIRD EXECUTIVE ORDER ON PIPELINES
TRUMP SIGNS FOURTH EXECUTIVE ORDER ON REGULATIONS

Earlier:

It is just day two of his presidency, and already Trump is taking a sledgehammer to the Obama legacy: in his latest move reported moments ago by Bloomberg, president Trump intends to sign two executive actions today that would advance construction of the controversial Keystone XL and Dakota Access pipelines, putting a spoke, so to say, in the train wheels of Warren Buffett's train-based oil transportation quasi-monopoly.

http://www.zerohedge.com/news/2017-01-24/trump-sign-executive-orders-advancing-keystone-dakota-pipelines

Requiring Keystone XL (and Others) To Use Domestic Steel

President Trump today signed executive actions to accelerate the Keystone XL and Dakota Access pipeline projects and to decree that American steel should be used for pipelines built in the United States.

I want to see the precise language of the requirement (should be available later today), but this looks like a probable violation of international trade agreements. I wrote about this issue a while back, when Congress considered a similar requirement

http://worldtradelaw.typepad.com/ielpblog/2017/01/requiring-keystone-xl-and-others-to-use-domestic-steel.html

Fifteen years ago the first shale, the Barnett was discovered, closely followed by the Fayetteville. They were big enough to be interesting, but not large enough to impact gas price.

Then came the Marcellus. On the map above I've replaced the Marcellus with the Barnett and Fayetteville.  You can put both inside the Marcellus, worse, the Marcellus rock was simply better. 

Natural Gas production soared, prices crashed, E&P execs and analysts were shocked, surprised and mostly went bankrupt.

Eight years ago Oilmen made the Bakken flow, then the Eagle Ford. US production started rising. Saudi was annoyed, and crashed prices. E&P execs and analysts were shocked, surprised and mostly went bankrupt. 

This last year, Oilmen have been transferring their skillset into the Permian. On the map I've replaced the Permian with the Bakken and Eagle Ford. You can put both inside the Permian, worse the Permian rock is simply better. 

Now the Oil market is much bigger than the Natural Gas market, but you can see where this story ends. 

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In the snowy prairies of Western Canada, not even temperatures below -40 degrees have stopped Stampede Drilling Ltd.’s 60 recently rehired workers from manning the oil-service provider’s rigs after a nine-month dry spell for the business.

“Once oil hit $50, everybody started phoning again,” Bill Devins, the drilling company’s 57-year-old owner, said in a phone interview from his office in Estevan, Saskatchewan, a town bordering North Dakota right at the heart of the Bakken shale formation. “We started to have some activity come our way.”

From the tight-oil plays of Saskatchewan to the oil sands of northern Alberta, Canada’s energy producers are returning to growth mode after more than two years enduring the worst market rout in decades. They are leaner and more efficient after cutting staff, shelving projects and reducing costs since the downturn. Cheaper crude doesn’t feel so painful any longer.

Companies such as MEG Energy Corp., Canadian Natural Resource Ltd., Cenovus Energy Inc., Encana Corp. and Seven Generations Energy Ltd. have all announced plans to expand production. Calgary-based Precision Drilling Corp.hired and recalled about 1,000 field workers to reactivate rigs in Canada and the U.S.

The renewed focus on expansion happens as the Organization of Petroleum Exporting Countries cuts output and after the Canadian government in November approved construction of two expanded oil pipelines that will add almost a million barrels a day of export capacity to Western Canada.

‘More Comfortable’

“A lot of companies have started increasing capital budgets,” Amir Arif, a Calgary-based analyst at Cormark Securities Inc., said by phone. “They are getting more comfortable in the $45 to $60 oil world. The stability in the oil price is a key factor.”

Crude has rallied on the back of the OPEC-led supply cuts, trading mostly above $50 a barrel in New York since a Nov. 30 agreement. While that’s nothing like the industry’s heyday years of about $100 before the crash, it’s a big improvement from the near-$25 doldrums of a year ago.

MEG plans to spend C$590 million ($446 million) in operations this year, almost five times more than in 2016, as it expands production at the Christina Lakes oil-sands site by about 25 percent. Cenovus will proceed with a 50,000-barrel-a-day expansion of its own Christina Lake project and Canadian Natural is moving ahead with its 40,000-barrel-a-day Kirby North project. The three ventures represent the first oil-sands expansions to be announced since the downturn began.

Economic Rebound

The rosier outlook is filtering into Western Canada. Alberta’s economy will grow 2.1 percent this year, tying with British Columbia for second-fastest among Canadian provinces behind Ontario’s 2.3 percent, according to the median of forecasts compiled by Bloomberg. The growth follows two straight years of economic contraction in the oil-rich province and will be largely due to the rebuilding of Fort McMurray, the gateway to the oil sands that was devastated by wildfires last year. Saskatchewan, the country’s second-largest oil producing province, will also emerge from a two-year recession to grow 1.7 percent.

Oil companies that form the backbone of the Western Canadian economy cut capital spending 50 percent in the past two years to C$17 billion in 2016, according to the Canadian Association of Petroleum Producers projections. About 110,000 jobs were lost between late 2014 and April of last year, CAPP said. The number of rigs drilling for oil and natural gas in Canada has jumped almost 40 percent from a year ago, after falling to the lowest since the early 1990s last year, according to data from Baker Hughes Inc.

To be sure, the economy is only beginning to recover. In Alberta, holder of the world’s third-largest crude reserves, the unemployment rate dropped to 8.5 percent last month from 9 percent in November, the highest in more than 20 years.

Empty Offices

In Calgary, the province’s biggest city and the headquarters for most Canadian energy companies, almost 25 percent of office space was vacant in the third quarter, according to New York-based Cushman & Wakefield, a real estate service company. Vacancies are going to rise to as high as 30 percent by 2018 as downtown office buildings such as Brookfield Place and Teles Sky open their doors, Stuart Barron, the company’s Toronto-based national director of research, said by phone.

“There is more optimism but the market is not going to turn around on a dime,” he said. “Its going to take another year or two to see strengthening.”

For oil companies, a return to the days when 200,000-barrel-a-day new oil-sands projects were routine is unlikely, Stephen Kallir, Canada upstream research analyst at Wood Mackenzie Ltd., said by phone. Most oil-sands expansions announced in recent months were projects that had already had capital invested in them, he said. Energy companies in Canada may also focus more on shale plays, where investment returns are realized more quickly than in the oil sands.

‘Prudent Approach’

“The aftershock and, for lack of a better word, hangover of the past two years is going to linger for quite a while in terms of how capital spending decisions are made,” he said. “There is going to be a lot more prudent approach.”

Much of the growth will be concentrated in Saskatchewan, where a less challenging geology means more wells will be tapped this year than in Alberta, according to the Canadian Association of Oilwell Drilling Contractors and Petroleum Services Association of Canada. That’s good news for Stampede’s Devins, who’s watched people move away and local businesses close up including a Staples and a motel. The new year has started out good.

“It’s probably as active as we’ve seen in two years for sure,” he said.

https://www.bloomberg.com/news/articles/2017-01-24/canadian-drillers-brave-deep-freeze-as-oil-patch-revives-growth

Oil companies Shell and Phillips 66 together bought 6.4 million barrels of oil last week from the Strategic Petroleum Reserve (SPR), according to a Department of Energy document released on Tuesday.

Shell bought 6.2 million barrels of oil and Phillips 66 bought 200,000 barrels on Jan. 18, according to the department document, seen by Reuters.

The federal government held the sale to fund a revamp of the emergency oil stash, which is stored in salt caverns in Louisiana and Texas along the Gulf Coast. The Department of Energy had said it would sell up to 8 million barrels as part of its modernization program.

Shell will take delivery of 1.7 million barrels of oil to a vessel, the documents said, while the remainder of the barrels are slated for pipeline delivery.

The U.S. lifted its decades-long ban on exporting U.S. crude in December 2015, giving buyers of the oil the opportunity to export oil purchased from the reserves.

A spokesman for Shell declined to comment on whether the company planned to export the crude.

Phillips offered a price of $53.8985 a barrel for the oil, and Shell offered between $53.668 and $54.338 a barrel, the documents said.

On Jan. 18, benchmark West Texas Intermediate crude futures settled at $51.08 a barrel.

Shell and Phillips 66 both operate oil refineries along the U.S. Gulf Coast near sites of the strategic reserves.

http://www.reuters.com/article/us-usa-spr-oil-idUSKBN15905U