Libya’s National Oil Corporation (NOC) and Russia’s Rosneft company have signed a cooperation framework agreement that lays the groundwork for investment by Rosneft in Libya’s oil sector, said the message on NOC’s website.

The agreement envisages the establishment of a Joint Working Committee of the two partners to evaluate opportunities in a variety of sectors, including exploration and production.

Reportedly, Rosneft and NOC also signed a crude oil offtake agreement (an agreement between a producer and a buyer to buy/sell a certain amount of the future production).

The accord represents a step forward in NOC’s plans, announced by chairman Mustafa Sanalla in London last month, to encourage investment by foreign oil companies in the expansion of Libya’s oil production to levels of 2.1 million barrels per day by 2020, said the message.

“We need the assistance and investment of major international oil companies to reach our production goals and stabilize our economy,” said Sanalla.

Alongside with Nigeria, Libya was exempted from the output cut deal during the meeting of OPEC countries held in Vienna Nov.30.

http://en.trend.az/business/energy/2723623.html

Oil, gas and petrochemicals projects to the tune of about $294 billion are in the pre-execution phase across the Mena region even while concerns about global oversupply continue to suppress oil prices, a report said.

Gas spending is also set to increase as countries such as Saudi Arabia and the UAE study higher-cost sour gas and shale gas plans to meet rapidly-growing domestic demand, reported the Times of Oman, citing Meed Insight’s Mena Oil and Gas Report 2017.

Last year saw average crude prices drop to a 13-year low as oil and gas producers in the Mena region continued to face the impact of global oversupply.

The drop in crude revenues coincided with an eight-year low in the value of engineering, procurement and construction (EPC) contracts awarded in the regional oil, gas and petrochemicals sectors.

Investment in the Mena hydrocarbons industries hit an eight-year low in 2016, dropping 34 per cent to $32.4 billion.

“The oil, gas and petrochemicals sectors will continue to be the backbone of economies across the Mena region,” Meed editorial director, Richard Thompson was quoted as saying in the report.

“With an estimated $294 billion-worth of projects in the pre-execution phase, the sector provides a wealth of opportunity for business from Saudi Arabia’s ambitious oil-to-chemicals complex to the re-emergence of the Iran oil industry following years of sanctions.”
Upstream investment has been driven by the need to meet rising demand, at both home and abroad, and the need to replace resources lost through natural depletion. In the GCC, Saudi Arabia, the UAE,

Kuwait and Qatar have all raised their sustainable crude oil production capacity, while Oman has managed to reverse a slump in output through its enhanced oil recovery (EOR) programme. Outside the GCC, production capacity and output has stagnated or fallen in Algeria, Egypt and Libya, mainly due to the political problems in those states. Iraq has been able to increase capacity through one of the world’s largest upstream investment programmes.

In terms of a subsector breakdown of future projects, the largest sector is petrochemicals with over a quarter of total projects planned. Many projects in this sector, however, are at an early stage and the current market environment for petrochemicals is not strong. The future of many of them also depends on the availability of feedstock, which has held back many GCC petrochemicals projects in the past. Oil refinery projects rank in second place with the announcement of several new refinery projects in Iraq boosting this sector. Spending is also anticipated on new refineries in Bahrain and Oman.

With capital spending on oil & gas projects of about $44.3 billion, Kuwait has been by far the biggest spender over the past two years after a slump in project spending at the start of the decade. That was driven by major projects such as the Clean Fuels Project, the Al-Zour refinery (also known as the New Refinery Project) and the Lower Fars heavy oil handling facilities.

Kuwait is only number five however in terms of pre-execution project value. This includes the estimated $7 billion Olefins 3 petrochemicals project and phases two and three of the Ratqa Lower Fars Heavy Oil project.

In the UAE, lower prices have been a driver of workforce reduction and consolidation. Abu Dhabi National Oil Company (ADNOC) is merging its two offshore oil producers as well as several logistics subsidiaries to low costs and streamline operations. Job cuts have also been administered at Qatar’s major gas companies.

Over the period in review the UAE has been the third most valuable market for hydrocarbons projects, spending $35.1 billion. Abu Dhabi in 2013 and 2014 awarded a string of contracts in the offshore oil sector. The UAE had quiet years in 2015 and 2016 as several major projects faced delays at the main contract bid phase. In 2016 the UAE was not in the top five countries in the region in terms of contract awards.

The UAE is also eyeing major gas capacity expansions in the coming years, largely by developing new sour gas reservoirs. These include major projects on the Bab and Hail fields as well as the expansion of the Shah gas field. The UAE ran into delays at the contract award phase on several projects in 2015/16, including the $3 billion Bab Integrated Facilities Expansion, a new refinery in Fujairah and the Fujairah LNG import terminal.

Meanwhile, Saudi Arabia plans to list the world’s largest oil and gas company, Saudi Aramco, on the stock market, in an initial public offering (IPO) that values the company at an estimated $2 trillion.

Saudi Arabia had the region’s largest oil, gas and petrochemicals market in the 2011-2016 period, with a total of $69.37 billion worth of contracts awarded, accounting for over a quarter of the regional total. The bulk of these awards however were in 2011 and 2012 with over $47 billion spent in these two years combined. Average spending has dropped considerably in the subsequent four years.

Saudi Arabia’s project pipeline is buoyed by the region’s two largest projects which are both at an early stage: Sabic’s oil-to-chemicals project and Aramco’s integrated refinery and petrochemicals development, both at Yanbu on the Red Sea coast. These projects aside, Aramco is likely to prioritise projects to expand its gas capacity which includes higher gas processing capacity, the development of non-associated gas fields in the Gulf and expanding shale gas production in the north.

Saudi Aramco plans to spend $334 billion across the oil and gas value chain by 2025, meanwhile, Kuwait is expected to spend $115 billion on energy projects over the next five years to help boost crude production capacity to 4 million barrels a day by 2020.

http://www.gdnonline.com/Details/180684/$294bn-oil,-gas-projects-underway-in-Mena

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Liquefied natural gas (LNG) imports into Japan increased 14.6 percent in January as demand for the chilled fuel for power generation rose on the back of low winter temperatures.

Japan imported 8.30 million mt of LNG in January, as compared to 7.24 million mt the year before, according to the provisional data released by Japan’s Ministry of Finance.

The country paid about $3.28 billion for LNG imports last month, a rise of 6.7 percent as compared to the same month in 2016, the data shows.

Japan’s average price of spot LNG hit its two-year high record during January. The average price of spot LNG bought last month was $8.40 per million British thermal units, up from $8 in the previous month and the highest since January 2015.

Worth mentioning, Japan imported 83.34 million mt of LNG in 2016, as compared to 85.05 million mt the year before.

This was the second drop in Japan’s annual LNG imports since the devastating earthquake and tsunami in March 2011 which caused Japan to shut down its nuclear industry.

http://www.lngworldnews.com/japans-lng-imports-rise-14-6-percent-in-january/

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Japan plans to conduct a second testing round for offshore production of methane hydrate from around late April, aiming to run the tests non-stop for up to a month, an official at the Ministry of Economy, Trade and Industry said Monday.

This will be the world's second offshore methane hydrate production test after Japan produced 120,000 cubic meters, or 20,000 cu m/day, of gas from methane hydrate in a first, six-day offshore production test in the Pacific Ocean in March 2013. That trial followed more than a decade of field research as well as testing of various technologies.

Like the last round, METI will conduct the trial using the decreasing pressure system at the Daini-Atsumi Knoll in the eastern Nankai Trough, 70-80 kilometers (43.4-49.6 miles) south of the Atsumi Peninsula in Aichi Prefecture, the official said.

The key objectives for the upcoming production test are to evaluate whether Japan can produce gas from methane hydrate using the decreasing pressure system stably for a given period, with a view to commercializing output in the future, the official said.

State-owned Japan Oil, Gas and Metals National Corporation, or Jogmec, is leading the methane hydrate output test for METI.

Starting from mid-April, operator Japan Methane Hydrate Operating Co. will extend its two production wells that have already been drilled by a further 50-60 meters to reach methane hydrate layers about 300 meters below the seabed at a water depth of around 1,000 meters, the official said.

JMH, which will charter the Chikyu drilling ship from early April, has to date drilled a total of five wells including the two production wells with monitoring wells.

JMH was formed in October 2014 as a joint venture of 11 Japanese companies, to take part in the planned next round of testing of pore-filling type methane hydrate.

JMH stakeholders are Japan Petroleum Exploration (33%), Japan Drilling Co. (18%), Inpex (13%), Idemitsu Kosan (5%), JX Nippon Oil & Gas Exploration Corporation (5%), Nippon Steel & Sumikin Engineering (5%), Chiyoda (5%), Toyo Engineering (5%), JGC (5%), Mitsui Oil Exploration Co. Ltd. (5%), and Mitsubishi Gas Chemical Company (1%).

http://www.platts.com/latest-news/natural-gas/tokyo/japan-plans-second-offshore-methane-hydrate-output-26666470

InterOil corporation said the Supreme Court of Yukon granted a final order approving the proposed $2.5 billion takeover by the US-based energy giant ExxonMobil.

The court decision follows a special meeting of InterOil shareholders at which 91 percent votes cast were in favor of the transaction.

With the court decision, the arrangement has received all necessary approvals, InterOil said, adding that together with ExxonMobil it expects the transaction to be completed this week.

The Supreme Court of Yukon initially approved the transaction in October last year, finding it “fair and reasonable”. However, the order was stayed by the Court of Appeal of the Yukon following an appeal lodged by InterOil’s former CEO Phil Mulacek.

When concluded, the transaction will give ExxonMobil access to InterOil’s resource base, which includes interests in six licenses in Papua New Guinea covering about four million acres, including PRL 15, which includes the Elk-Antelope which is the anchor field for the proposed Papua LNG project.

ExxonMobil earlier also said it aims to work with its co-venturers and the government to evaluate processing of gas from Elk-Antelope field by expanding the PNG LNG project.

http://www.lngworldnews.com/interoil-exxonmobil-deal-clears-final-hurdle/

China's Sinochem is exploring the sale of its 40 percent stake in Brazil's Peregrino offshore oilfield, four people familiar with the matter told Reuters, a deal that could see the state-owned conglomerate walk away from what was once touted as a key overseas asset because of historically low oil prices.

The oil and chemicals firm agreed to buy the stake from Norway's Statoil (STL.OL) for $3.07 billion in 2010 - beating out a raft of Chinese rivals chasing high-quality assets. The Norwegian giant owns the other 60 percent of Peregrino, the largest heavy oilfield it operates outside its home patch.

But two of the people with knowledge of the matter said Sinochem is moving to sell its largest overseas upstream stake - with capacity to pump 100,000 barrels a day - as it reshapes its assets to reflect oil prices having halved in the last two and a half years. With that in mind, one person said, Sinochem was pitching the sale at a big discount to its purchase price.

"Peregrino has been a success story for Statoil, not just technically but also financially. It provides a lot of value and has a good operator in Statoil," said Horacio Cuenca, Rio de Janeiro-based research director for upstream Latin America at energy consultancy Wood Mackenzie.

Long term expectations of oil prices, however, and capital expenditure required in the next two to three years to develop the second phase of production will determine the value of any potential stake sale, he said.

Earlier this month, Reuters reported Sinochem was in early talks to buy a stake in Singapore-listed commodity trader Noble Group (NOBG.SI), a move that would further its ambitions to become more active in global energy trade and also develop China's gas industry.

The process to sell the Brazilian stake is still at an early stage and a final decision would depend on how the negotiations progress, the people familiar with the matter said. They spoke on condition of anonymity because they were not authorized to discuss it publicly.

Statoil declined to comment.

In an e-mail reply, Sinochem's press office said: "The company has been monitoring a large amount of transaction opportunities in the market and is ready to re-adjust and optimize its asset structure at the right time." It added that company does not comment on specific projects.

Two sources said Sinochem's intent to sell the stake has been shared with India's Oil and Natural Gas Corporation (ONGC.NS). ONGC did not respond to requests for comments.

One person said the stake is also likely to be pitched to other international buyers, including some Japanese firms and Kuwait Foreign Petroleum Exploration Company, which snapped up Royal Dutch Shell's (RDSa.L) stake in Thailand's Bongkot gas field for $900 million last month.

SINOCHEM - ASSET MANAGER?

The potential sale of the stake in Peregrino - located 85 km off Brazil in the Campos basin below about 100 meters of water - comes as oil prices hover in a mid-$50s per barrel range, well below the highs of recent years. That trend has also prompted other industry players to consider selling once-prized assets.

Earlier this week, Reuters reported Malaysian state-owned oil and gas firm Petronas is aiming to sell a large minority stake in a local gas project for up to $1 billion as it seeks to raise cash and cut development costs.

For its part, Sinochem has seen growth in its key oil trading business stagnate, with increasing domestic competition from the likes of state oil traders Unipec and Chinaoil, while overseas oil and gas assets have struggled amid the prolonged low oil prices.

"Sinochem is readjusting its energy asset structure," said a Beijing-based industry veteran familiar with the company's strategy. "As a medium- to small-sized oil producer, exposure to higher cost assets like deep water has become over-challenging."

"The company sees itself more as an asset manager. This becomes a clearer direction under the new management," the industry executive said, referring to Sinochem chairman Ning Gaoning who took over the helm last year.

The potential sale of the Peregrino stake also comes ahead of the second phase of the project's development, expected to cost about $3.5 billion with production from the new phase set to start by the end of the decade.

The second phase is designed to add about 250 million barrels in recoverable reserves to Peregrino, which currently contains an estimated reserve of between 300 million and 600 million barrels of recoverable oil.

http://www.reuters.com/article/us-sinochem-m-a-idUSKBN1600MW

Galp Energia on Tuesday cut its spending plan for the next five years by a fifth and trimmed its oil production growth forecast, but raised its earnings outlook after producing stronger than expected earnings for 2016.

Galp, which is mainly an oil refiner, has stakes in various large oil fields off Brazil's coast and has been building up its oil and gas production.

The company said it expected production from sanctioned oil and gas projects to grow at a rate of 15-20 percent a year until 2021, down from 25-30 percent under its previous plan that ran up to 2020. "We remain focused on delivering the projects under construction, on time, within the budget ... and targeting high returns," Chief Executive Officer Carlos Gomes da Silva told investors at the company's capital markets day on Tuesday.

Galp shares were almost 2 percent lower in early trading, underperforming the broader market in Lisbon.

Galp estimated annual average capital expenditure up to 2021 at between 0.8 billion and 1 billion euros, 20 percent lower than under the previous plan announced a year ago.

But earnings before interest, taxes, depreciation and amortization (EBITDA) should grow at a rate of around 20 percent a year until 2021, up from the previous forecast of 15 percent.

This year, it expects an EBITDA of 1.5 billion to 1.6 billion euros. Earlier on Tuesday, Galp reported an 8 percent drop in 2016 EBITDA to 1.41 billion euros ($1.49 billion), which exceeded its forecast of 1.2 billion to 1.3 billion.

Galp also confirmed its previous projection that its free cash flow will break even next year. It put the cash breakeven price for oil production at around $65 per barrel in 2016-18 and below $35 per barrel 2019-21.

http://www.reuters.com/article/galp-energia-outlook-idUSL8N1G624O

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Woodside Petroleum Ltd said on Wednesday it sees its output rising by about 15 percent over the next three years, and flagged plans to expand near-term output in Western Australia as it seeks to defy views that it is short on growth.

Australia's top gas and oil producer has come through the oil market rout over the past two years in better shape than rivals, with $2.7 billion in cash and undrawn debt, and sees itself well positioned as prices rebound.

"We're a fundamentally different company to the one we were five years ago and the opportunity set in front of us is very much world class," Chief Executive Peter Coleman told reporters, pointing to prospects in Australia, Myanmar and Senegal.

Woodside reported a 23 percent drop in annual underlying profit to $868 million for 2016, in line with analysts' forecasts, as it was hit by weaker oil and gas prices that offset cost cuts and a rise in output.

The company cut its full year dividend to 83 cents a share from $1.09, slightly short of analysts' forecasts of 85 cents a share, according to Thomson Reuters I/B/E/S.

Woodside's forecast for production to grow by 15 percent over the next three years, implying output of around 100 million barrels of oil equivalent by 2020, was ahead of some analysts' forecasts for growth of around 5 percent.

All of its growth over the past five years has come from its Pluto liquefied natural gas project which began in 2012.

The increase will come from the Wheatstone liquefied natural gas project (LNG), where operator Chevron Corp expects production to start in mid-2017, and oil from Woodside's Greater Enfield project.

The company is also looking to boost output from Pluto by just under 1 million tonnes by running its facilities harder, and is considering a further expansion by adding a small new production unit of 1 million to 1.5 million tonnes.

"It's something that can be brought to market quickly," Coleman said, contrasting the expansion option with the huge LNG plants that have been built in the region over the past five to 10 years.

Woodside is also planning to build a truck terminal to supply LNG from Pluto to fuel the local mining industry and wants to supply LNG for the shipping sector, too, to build demand for its key product.

http://www.reuters.com/article/woodside-results-idUSL4N1G662V

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ASX-listed Senex Energy will invest some A$50-million to a 30-well drilling campaign in the Western Surat gas project, marking its first major investment in the project.

MD and CEO Ian Davies on Tuesday said the work programme would result in significant gas volumes from drill-ready acreage, with Senex already having a clear strategy for project acceleration.

“We have seen immediate gas to surface from the Glenora pilot wells, brought online for continuous production in early February. We have also seen evidence of strong gas flows from wells on the Eos block during rehabilitation work being undertaken on legacy wells. These results demonstrate that coal seams in the Glenora and Eos blocks have already been partially dewatered by neighbouring operations.”

Davies said the sanctioned well programme will further Senex’s understanding of the resource to support an accelerated project timeline, with potential to drill, complete and connect another 30 to 50 wells throughout 2018.

“Under this scenario and, subject to regulatory approvals, Senex can seamlessly transition to a development phase targeting gas production of over 16 TJ a day by 2019, equivalent to one-million barrels of oil equivalent a year.”

First wells are expected to come online in mid-2017 and are expected to produce some 10 TJ a day by mid-2018.

“Finally, the 2017 work programme will give us the opportunity to fully embed our design, contracting and execution methodologies in order to demonstrate best-in-class safety and cost performance,” Davies said.

With the Glenora and Eos blocks located directly north from the Gladstone liquefied natural gas (GLNG) project’s producing Roma field, Senex was planning to sell the raw gasto the GLNG project, subject to the agreement of commercial terms.

A pipeline from the Glenora pilot to the GLNG low-pressure gathering network was built in 2016.

http://www.miningweekly.com/article/senex-commits-a50m-to-western-surat-gas-project-2017-02-21

After a two-year downturn that pushed the Peace Region from having close to zero unemployment to the highest jobless rate in B.C. last year, jobs are suddenly flowing back into northeastern B.C.

Oil and gas companies have dramatically stepped up drilling this winter compared with the last two years.

“It’s been crazy,” said Dawson Creek Mayor Dale Bumstead. “It was like somebody turned a switch on about November, December. Before Christmas, all our hotels were almost 100% occupancy and rental accommodation was filling up.”

“There’s optimism out there right now,” said Mark Salkeld, CEO of the Petroleum Services Association of Canada (PSAC).

Between 2015 and 2016, new oil and gas rights sales dropped dramatically and drilling in northeastern B.C. slowed to a trickle, thanks to a sustained plunge in oil and gas prices and growing uncertainty over large liquefied natural gas (LNG) projects.

But on January 18, the auction for petroleum and gas rights generated more sales in a single day – $40 million – than the total reaped in all auctions held in 2015 and 2016. PSAC recently bumped up its estimate for the 2017 winter drilling season in B.C. to 367 wells from 280.

“We’re seeing it in company guidance,” said Mark Oberstoetter, lead oil and gas analyst with Wood Mackenzie. “A lot of companies are doubling or adding a lot of spend in 2017, versus the low scene in 2016. So we’re seeing a lot of optimism.”

Art Jarvis, owner of FloRite Environmental Systems and executive director for Energy Services BC, said companies in Fort St. John that parked equipment and laid off 40% to 60% of their staff during the downturn are now scrambling to find workers again.

While some might view the sudden activity as a sign of renewed optimism that an LNG industry will develop in B.C., Oberstoetter said it’s really just economics.

Even throughout the last two-year drilling drought, midstream companies have pumped billions into the Montney, building new gas processing plants and pipelines. Veresen Inc. (TSX:VSN) and Encana Corp. (TSX:ECA), for example, are spending $2.5 billion building three new gas processing plants in the Fort St. John and Dawson Creek area under the Cutbank Ridge Partnership.

But the more labour-intensive exploration side of the business, drilling and fracking, all but stopped between 2015 and 2016, thanks to a sustained plunge in oil and gas prices.

Gas well drilling is labour intensive. Each well takes a crew of about 135. That’s not including all the related jobs created for service businesses like Jarvis’ company, which provides truck-mounted pressure vessels that bleed off pressure to separate liquids from gases at wellheads.

In the Montney, companies will typically spend $3.5 million to $5 million per well, although some deeper and more complex wells may cost as much as $15 million.

The Montney has proved to be one of North America’s lowest-cost regions. The sheer volume of gas makes for good wellhead economics, and an abundance of liquids such as light oil, condensate and propane provides added value to producers.

“You get a lot of volumes for every well you drill,” Oberstoetter said. “They’re very big wells, and well costs have come down a lot.”

During the last drilling cycle, between 2012 and 2014, much of the drilling was being done by companies like Progress Energy (owned by Petronas) and Shell, which were proving out wells in anticipation of a liquefied natural gas industry developing.

The current boom involves companies that are after natural gas liquids, including some newcomers, like Crew Energy Inc. (TSX:CR) and Tourmaline Oil Corp. (TSX:TOU), which have been buying up assets in the Montney in both Alberta and B.C.

Last year, Tourmaline bought $1.4 billion worth of natural gas assets from Shell in Alberta’s Deep Basin and B.C.’s Montney.

Last year, when Terra Energy went bankrupt, Crew Energy snapped up some of its wells and processing assets.

https://www.biv.com/article/2017/2/oil-gas-exploration-explodes-provinces-peace-regio/

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ConocoPhillips has revised down over a billion barrels of oil sands reserves because of low global crude prices, a company filing showed on Tuesday, the latest sign that some of Canada's vast hydrocarbon potential may be left untapped.

The U.S. oil major said developed and undeveloped reserves of bitumen - the heavy viscous oil found in northern Alberta's remote oil sands - totaled 1.2 billion barrels at the end of 2016, down from 2.4 billion barrels at the end of 2015.

The oil sands have some of the highest full-cycle breakeven costs in the world, with new thermal projects needing U.S. crude prices around $60 a barrel. Crude futures settled at $54.33 a barrel on Tuesday.

The U.S. Securities Exchange Commission (SEC) document provides a detailed breakdown of the global reserves cut Conoco announced in quarterly results in early February, when it debooked 1.75 billion barrels of oil equivalent of reserves.

Al Hirshberg, Conoco's executive vice president for production, drilling and projects, told investors on the quarterly call the company expects to rebook the reserves if current prices hold.

Likewise Martin King, an analyst with GMP FirstEnergy in Calgary, said the debooking likely had more to do with SEC rules requiring companies to evaluate economic reserves at year-end.

But the fact that the oil sands make up 70 percent of the reduction underlines how much of Canada's resources are uneconomic in a weaker oil environment.

"They (the oil sands) are at the upper end of the cost curve," said Judith Dwarkin, chief economist at RS Energy Group in Calgary. "It may or may not speak to future similar events from other producers."

Calgary-based Imperial Oil Ltd , which is majority-owned by Exxon Mobil Corp , debooked 2.6 billion barrels of reserves in January.

ConocoPhillips made the reserve reductions at the Surmont, Foster Creek, Christina Lake and Narrow Lakes projects.

Surmont is operated by ConocoPhillips and a joint venture with Total E&P Canada, a unit of Total SA, and the other three are joint ventures run by Cenovus Energy Inc .

Total also debooked undeveloped reserves at Surmont, according to SEC filings. But Cenovus, which reports to Canadian securities authorities, said its total proved reserves including non-oil sands operations rose 5 percent in 2016 versus a year earlier.

Cenovus spokesman Reg Curren said the company assumed different rules relating to reserves reporting in Canada and the United States were behind the difference.

http://www.reuters.com/article/us-canada-conocophillips-oil-sands-idUSKBN1602OK

Whiting Petroleum Corp, North Dakota's largest oil producer, nearly doubled its 2017 budget for capital spending as crude prices stabilize following a two-year rout.

However, shares of the company were down 3.5 percent after the bell as the oil producer's revenue fell below analysts' expectations due to a steep drop in production.

Oil companies are betting big on a continued rise in crude prices by buying up acreage and raising capital spending.

Whiting boosted its 2017 spending to $1.1 billion from $554 million in 2016.

The company's production fell 23.4 percent to 118,890 barrels of oil equivalent per day in the fourth quarter ended Dec. 31.

Whiting's net loss available to common shareholders widened to $173.3 million, or 59 cents per share, in the quarter from $98.7 million, or 48 cents per share, a year earlier.

Excluding items, the company posted a loss of 28 cents per share, smaller than the analysts' average estimate of 32 cents.

Denver-based Whiting Petroleum's operating revenue fell 18 percent to about $342.7 million. Analysts had estimated revenue of $355.2 million, according to Thomson Reuters I/B/E/S.

http://www.reuters.com/article/us-whiting-petrol-results-idUSKBN1602L0

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