The oil and gas industry will cut $1 trillion from planned spending on exploration and development because of the slump in prices, leading to slower growth in production, according to consultant Wood Mackenzie.

Malcolm Dickson, Principal Analyst at Wood Mackenzie said: “The impact of falling oil prices on global upstream development spend has been enormous.

“Companies have responded to the fall by deferring or cancelling projects and costs have also fallen.

“Our 2015-2020 forecast for capital investment has been reduced by 22% or US$740 billion since Q4 2014. In the nearer term the impact is even more severe: compared to pre-oil price fall expectations, capex will be down by around US$370 billion or 30% in 2016 and 2017.”

Wood Mackenzie expects to see further cuts throughout the year and investment levels continue to shrink as more projects are dropped and companies struggle to breakeven.

“Virtually every oil producing country has seen some form of capex cuts. The deepest are in the US Lower 48, where forecast capital investment has halved in 2016-17, falling by US$125 billion. This is mainly down to a big drop-off in drilling, with the onshore rig count dropping by 53% from 2015 to 2016,” says Dickson.

A global supply glut caused by the increase in shale oil production in the US, coupled with OPEC’s decision to keep pumping to preserve market share, triggered the collapse in oil prices in 2014.

While Brent crude, the international benchmark, has rebounded more than 75 percent from a 12-year low in January, the current price of about $49 a barrel is still less than half the level two years ago and has led to loss of hundreds of thousands of jobs around the world, with an estimated 120,000 lost in the UK North Sea alone.

The U.S. has experienced the steepest cuts in spending. Forecast capital investment there is down by half for this year and next, a drop of around $125 billion, mainly due to a decline in drilling, Dickson said in the report.

The Middle East is the region least affected, with no drop in investment expected in Saudi Arabia — the world’s largest crude exporter — for this year and next. That’s because several countries in the region are spending to maintain their market share, the report said.

The investment cuts are taking a toll on production. Compared with expectations before the slide in oil prices, output this year will be 5 million barrels of oil equivalent a day lower, with the deficit widening to 6 million next year, Wood Mackenzie estimates.

Part of the reduction in spending stems from a drop in the cost of doing business. Costs in the U.S. unconventional oil and gas industry were a quarter lower on average compared with their peak in 2014, Wood Mackenzie said. In Russia, the 40 percent reduction in investment in dollar terms anticipated over the next two years is due in large part to the depreciation of the ruble, it said.

Dr Andrew Latham, Vice President of exploration research at Wood Mackenzie said: “Although exploration investment has more than halved since 2014, and the figure is expected to be around US$42 billion per annum for 2016 and the same in 2017, costs have not been cut as much and as quickly as we expected. Some deepwater exploration spend has been protected by long rig contracts, but as these unwind we expect sharper cuts than in non-deepwater.”

On a more positive note for operators, cost deflation has played a major role in driving down spend. For example, costs in the US unconventional sector in 2015 fell by 25% on average from peak in 2014. Wood Mackenzie’s models show 2016 is likely to yield another 10%.

“For now, the select few projects that are progressed will do so because costs have been cut substantially to hit economic hurdle rates. But kick-starting the next investment cycle will require more cost deflation and project scope optimisation along with confidence in higher prices and arguably fiscal incentives.” says Dickson.

https://www.energyvoice.com/oilandgas/112310/global-upstream-investment-slashed-1trillion-since-oil-price-fall-says-wood-mac/

Iran's Oil Comeback May Already Be Over

Iran easily beat expectations with its speed in boosting oil exports after the lifting of sanctions. Without an injection of cash and the easing of remaining trade barriers, the recovery may have run its course.

When restrictions on Iran’s oil exports were relieved in January following a nuclear pact with world powers, analysts from Goldman Sachs Group Inc. to Barclays Plc doubted it could return to previous levels this year. The Persian Gulf state defied the skeptics with a 25 percent surge in production and aims to reach an eight-year high of 4 million barrels a day by year-end.

“They have surprised most market participants with the speed they’ve been able to resume production,” said Antoine Halff, a senior fellow at the Center on Global Energy Policy at Columbia University in New York. “But to exceed pre-sanctions levels would require investment and technology and that’s a much longer-term proposition.”

Returning to world markets after more than three years of isolation, Iran is seeking more than $100 billion of investment from international partners to rehabilitate its oil industry and ultimately reclaim its position as OPEC’s second-biggest producer. Still, companies are still waiting for Iran to approve the contract model to be used in deals and for clarity on remaining U.S. sanctions before re-entering the country.

Iranian Wins

Since limits on crude sales were lifted, exports have doubled to about 2 million barrels a day, flowing again to previously prohibited markets in Europe, where Royal Dutch Shell Plc and Total SA resumed purchases. Production reached pre-sanctions levels of 3.6 million barrels a day in April and maintained that level in May, the Paris-based International Energy Agency estimates.

Iran’s own figures have output climbing to 3.8 million barrels a day in May, with plans to hit 4 million by the end of the year and ultimately reaching 4.8 million within five years, Oil Minister Bijan Namdar Zanganeh said June 3 in Vienna. With Total, Eni SpA and BP Plc having expressed interest in developing Iran’s resources, Zanganeh predicts the first deals with foreign companies will be signed within three months.

While oil analysts concede that Iran surpassed their initial forecasts, they aren’t convinced its greater ambitions will be realized soon. Qamaar Energy Chief Executive Officer Robin Mills and independent consultant Peter Wells, who both have experience working in Iran, say that sustaining a level of 3.6 million to 3.8 million a day is more realistic.

New Investment

Iran will need billions of dollars of investment and foreign technology to boost reservoir pressure to expand capacity at its aging, cash-starved wells, which were already suffering output declines before sanctions hit, the Paris-based agency estimates. Even with an influx of investment, returning to 4 million barrels a day won’t happen before 2021, the IEA predicts.

“They are doing everything they possibly can on their own while waiting to bring in foreign partners,” said Bjornar Tonhaugen, an analyst with Rystad Energy AS in Oslo, an oil consultant that advises more than 600 clients. “The risk now is that it’s not sustainable.”

Iran can boost capacity by 300,000 barrels a day in the next several years from deposits in the West Karoun area near the Iraqi border, said Tushar Tarun Bansal, an energy analyst at consultants FGE in Singapore. Zanganeh, in an interview with Iranian magazine Seda Weekly published June 11, said the country can add 700,000 barrels a day from these fields over five years.

Model Contract

However, attracting foreign capital will be a struggle when a model contract for oilfield investment isn’t ready and as a range of U.S. sanctions remain in place, said FGE’s Bansal.

Even after dropping sanctions on Iran’s oil sales, the U.S. still prohibits transactions related to the Islamic Republic from being conducted in dollars, restrictions imposed because it accuses Iran of human rights abuses and sponsoring terrorism. Zanganeh acknowledged last week that the oil contract models need further revisions.

“The big question for the Iranians is: ‘Are they going to get all the investment they want?’” Daniel Yergin, vice chairman of consulting firm IHS Inc., said in a Bloomberg television interview. “Companies are going to be very cautious about making new commitments to Iran. No one wants to run afoul of U.S. sanction law. ”
A series of output disruptions from Nigeria to Canada and Venezuela has meant that the extra Iranian oil has been easily absorbed by the market rather than depressing prices, said Mike Wittner, head of oil market research at Societe Generale SA in New York. Crude futures recovered to more than $50 a barrel last week, nearly double the 12-year low reached in January. With Iran’s comeback almost complete and global demand rising, traders are starting to wonder how much world markets will tighten in 2017, he said.

“By the end of this year Iran will be maxed out,” said Wittner. “Is it bullish? Yeah. When I look around the world and I need a bit more OPEC crude, I ask myself where it’s going to come from.”

http://www.bloomberg.com/news/articles/2016-06-15/iran-oil-comeback-that-startled-doubters-approaches-roadblock

At 4:00am @NDAvengers blow up NNPC Pipeline in Oruk Anam Local Government Area in Akwa Ibom.

@NDAvengers

Exxon Mobil Corp and BHP Billiton Ltd said on Wednesday that they are considering selling depleting energy assets in Australia, including Kingfish, the country's largest ever discovered oil field.

The resource giants are looking to market 13 fields, licenses and associated infrastructure held in the Gippsland Basin Joint Venture. The venture in Australia's Victoria state began operations in 1969, according to BHP's website.

"We are seeking to identify interested parties with proven experience and strength to operate and capture the remaining potential in these licenses," a spokesman for Esso Australia, which operates the venture, told Reuters.

BHP and Esso Australia each hold a 50 percent share of the joint venture.

http://world.einnews.com/article/331029759/avapmI6jh78vgd0O

Italy's Snam, one of Europe's biggest gas pipeline operators, is looking to lift about 4 billion euros ($4.5 billion) off its balance sheet as part of plans to spin off its domestic gas business, sources familiar with the matter said.

In a refinancing to be carried out by a dozen or so banks, the debt would end up with Snam's Italgas unit, which will be spun off by distributing Italgas shares to Snam investors and listing them, six sources familiar with the refinancing said.

That would leave Snam more focused on its goal of becoming a prime mover in integrating Europe's patchwork of grids and making Italy a European gas hub, in line with the European Union's desire to wean itself off Russian gas imports.

Snam, which has 13.5 billion euros of debt, is investing more than half its 3.6 billion euro revenues in transmission and would benefit from cutting domestic distribution commitments.

While Snam will raise no money from the listing, the deal will cut leverage, making it easier to tap funds on the market.

"Snam could go for acquisitions in Europe in order to get more control over the South European gas corridor," Macquarie analysts said.

Three of the sources said around 12 banks, including Mediobanca (MDBI.MI), UniCredit (CRDI.MI) and Banca Imi (ISP.MI), were being lined up for a 3.5-4.0 billion euro refinancing package that would see as much as 2 billion euros of group debt being transferred to Italgas on top of its own 1.9 billion euro debt pile. The refinancing is expected to be wrapped up by the summer with a listing of Italgas likely towards the end of the year, the sources said.

Snam is controlled by state lender Cassa Depositi e Prestiti (CDP) through a vehicle that also includes State Grid Corporation of China STGRD.UL.

Four sources said Snam would keep a minority stake in Italgas of up to 15 percent with one source saying it could be as low as 10 percent.

A banker with knowledge of the matter said the idea of a shareholder pact between Snam and CDP to allow the state lender to keep a firm grip on Italgas when it is on the market was being discussed.

Goldman Sachs (GS.N) is advising Snam on its options, the sources said, adding the structure of the demerger was still under discussion and some of the details could change.

The company, which has a strategic alliance with Belgium's Fluxys, already controls French grid TIGF and Austrian pipeline TAG and recently bought a 20 percent stake in the Trans Adriatic Pipeline that will bring Azeri gas into Europe.

It is interested in German gas grid Thyssengas and Austria's Gas Connect Austria as well as a stake in Greece's DESFA.

In March Snam launched a feasibility study on demerging all or part of Italgas but gave no further details.

Earlier this year the group, under new CEO Marco Alvera, delayed its strategy plan which will now be unveiled on June 29.

New rules in Italy's fragmented gas distribution sector cutting concession areas to just 177 from almost 7,000 are expected to trigger consolidation, favoring companies with strong balance sheets. In January sources told Reuters CDP was mulling the idea of merging Italgas with No 2 distributor 2i Rete gas in which CDP is also a shareholder.

http://www.reuters.com/article/us-italgas-m-a-snam-it-idUSKCN0Z11N7

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Malaysia’s state-owned oil corporation and Saudi Arabian Oil Co. are asking banks for proposals to finance about $7 billion for a planned refinery and a petrochemical complex in the Southeast Asian nation, according to people familiar with the matter.

The lenders would provide financing for the two projects worth a total of $12 billion to be constructed by Petroliam Nasional Bhd. and Saudi Aramco under a memorandum of understanding that the two firms have signed, according to the people, who asked not to be identified as the process is private. The banks are expected to submit proposals by later this month, the people said.

A Petronas’s spokesman couldn’t immediately be reached for comments by phone. Saudi Aramco’s media officials at its headquarter in Dhahran, Saudi Arabia, declined to comment.

Long-Term Projects

While Petronas announced in January that it would cut its capital and operating expenditures by 50 billion ringgit ($12.2 billion) over four years, it also gave commitment to invest in long-term projects. The planned projects with Saudi Aramco are part of the $27 billion Refinery And Petrochemicals Integrated Development that it is building for future growth and will come onstream in 2019.

Petronas reported a 71 percent decline in net income of 2.7 billion ringgit in the first quarter from 9.3 billion ringgit a year earlier due to lower product prices and reduced sales volume, according to May 18 statement. Its total assets decreased to 567.6 billion ringgit as at end March compared to RM591.9 billion as at Dec. 31. The company raised $5 billion by selling dollar bonds and Islamic debt in March last year.

Saudi Aramco, the world’s biggest oil exporter, already has refining and petrochemical partnerships in the U.S., China, South Korea and Japan, as well as in Saudi Arabia, giving it a share in plants capable of processing 5.4 million barrels a day. It is also looking to develop more joint ventures in countries including the U.S., China, Indonesia, India, Vietnam and South Africa, Chief Executive Officer Amin Nasser told reporters on May 10.

Saudi Arabia is seeking to reduce its reliance on oil sales amid lower prices for its most lucrative export. As part of that effort, the Middle Eastern nation wants to sell stock in Saudi Aramco for the first time, creating what could be the world’s largest listed company.

http://www.bloomberg.com/news/articles/2016-06-15/petronas-saudi-aramco-said-seeking-pitches-for-7-billion-loan

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Brazil’s troubled state-run oil company Petrobras is close to selling a 81 percent stake in a natural gas pipeline network in Brazil for nearly $6 billion to a consortium led by Brookfield Asset Management Inc, said three people with direct knowledge of the matter.

The Singapore sovereign-wealth fund GIC Pte, the Chinese sovereign-wealth fund China Investment Corp. and the Greenwich, Connecticut-based private equity firm First Reserve Corp are also part of the group of buyers, said two of the people, asking not to be identified because the discussions are private. The deal is expected to be signed as soon as next month, one of the people said.

Petrobras is trying to sell the network of gas pipelines, called Nova Transportadora do Sudeste SA, as it struggles to reduce the largest debt load in the oil industry amid crude prices that stand at half the levels seen just three years ago. The transaction, if closed, could be the only divestment in Brazil for the Rio de Janeiro-based firm this year, one of the people said, given the current pace of other deals.

BR Distribuidora and Transpetro, two subsidiaries the company is considering selling, are complex deals and are currently not moving fast enough to be concluded this year, one of the sources said.

Brookfield and First Reserve declined to comment on the deal. Petrobras, CIC and GIC didn’t immediately reply to requests for comment.

Petroleo Brasileiro SA, as the oil giant is formally known, said May 12 it had entered a 60 day period of exclusive talks with Brookfield, the largest alternative asset manager in Canada, for the sale of the gas pipelines, a period which could be extended by 30 more days.

Pedro Parente, who took over as the company’s chief executive officer this month, has vowed to reduce leverage at the world’s biggest deep-water oil producer and said he would focus on divesting assets outside of its core activities to focus investments on mega-projects in deep waters of the South Atlantic. The company has already sold about $2.1 billion in assets since last year, mainly from unloading its operations in Chile and Argentina -- part of a two-year, $15.1 billion asset sale program.

Petrobras wouldn’t cash in immediately the money as it would still need approval from regulatory bodies such as the oil regulator known as ANP, and the antitrust body Cade.

http://www.bloomberg.com/news/articles/2016-06-15/petrobras-said-close-to-6-billion-sale-of-brazil-gas-pipelines

U.S. crude oil refinery inputs averaged over 16.3 million barrels per day during the week ending June 10, 2016, 100,000 barrels per day less than the previous week’s average. Refineries operated at 90.2% of their operable capacity last week. Gasoline production decreased last week, averaging 9.7 million barrels per day. Distillate fuel production increased last week, averaging 5.0 million barrels per day.

U.S. crude oil imports averaged over 7.6 million barrels per day last week, down by 83,000 barrels per day from the previous week. Over the last four weeks, crude oil imports averaged over 7.6 million barrels per day, 9.8% above the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 747,000 barrels per day. Distillate fuel imports averaged 123,000 barrels per day last week.

U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) decreased by 0.9 million barrels from the previous week. At 531.5 million barrels, U.S. crude oil inventories are at historically high levels for this time of year. Total motor gasoline inventories decreased by 2.6 million barrels last week, but are well above the upper limit of the average range. Both finished gasoline inventories and blending components inventories decreased last week. Distillate fuel inventories increased by 0.8 million barrels last week and are well above the upper limit of the average range for this time of year. Propane/propylene inventories rose 1.1 million barrels last week and are near the upper limit of the average range. Total commercial petroleum inventories decreased by 0.7 million barrels last week.

Total products supplied over the last four-week period averaged about 20.4 million barrels per day, up by 3.6% from the same period last year. Over the last four weeks, motor gasoline product supplied averaged over 9.6 million barrels per day, up by 2.9% from the same period last year. Distillate fuel product supplied averaged over 3.8 million barrels per day over the last four weeks, down by 2.6% from the same period last year. Jet fuel product supplied is up 5.3% compared to the same four-week period last year.

Cushing oil storage up 900,000 bbl

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

                                                       Last Week       Week Before    Last Year

Domestic Production '000....... 8,716               8,745              9,589

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

A rare tour of the Strategic Petroleum Reserve

The world’s largest emergency stockpile of crude oil is quickly falling apart.

The stockpile’s infrastructure, which currently stores 695.1 million barrels at four sites along the US Gulf Coast, is nearing the end of its design life and in need of a roughly $2 billion makeover, US Department of Energy officials claim.

“We’ve had several significant equipment failures over the last couple years that have affected our operational capability,” said Bob Corbin, the DOE deputy assistant secretary who oversees the stockpile, formally known as the US Strategic Petroleum Reserve.

In April, a water pipe at the DOE’s Big Hill site in Winnie, Texas failed, less than a year after a crude oil storage tank failed at the Bryan Mound SPR site near Freeport, Texas.

Throughout the system, pipes are corroding, tank floors need to be replaced, wells are failing mechanical integrity tests and pump motors, after decades of dealing with harsh weather and salty air off the Gulf of Mexico, are breaking down beyond repair, DOE officials claim.

Corbin said these issues complicate the ability of DOE to both drawdown and distribute crude oil at times of severe supply distributions, which is the primary reason the SPR was created more than four decades ago. They also complicate US’ ability to meet obligations under international agreements and could endanger energy security.

http://blogs.platts.com/2016/06/15/rare-tour-strategic-petroleum-reserve/

Ultra Petroleum Corp. was a shale success story. A former penny stock that made the big leagues, it was worth almost $15 billion at its 2012 peak.

Then came the bust. Almost half of Ultra’s reserves were erased from its books this year. The company filed for bankruptcy on April 29 owing $3.9 billion.

Ultra’s rise and fall isn’t unique. Proven reserves -- gas and oil resources that are among the best measures of a company’s ability to reward its shareholders and repay its debts -- are disappearing across the shale patch. This year, 59 U.S. oil and gas companies deleted the equivalent of 9.2 billion barrels, more than 20 percent of their inventories, according to data compiled by Bloomberg. It’s by far the largest amount since 2009, when the Securities and Exchange Commission tweaked a rule to make it easier for producers to claim wells that wouldn’t be drilled for years.

Wider Effort

The SEC routinely questions companies about their reserves. Now, agency investigators are also on the hunt for inflated reserves estimates, according to a person familiar with the matter.

“Reserves make up a large share of the value of these companies, so it really matters,” said David Woodcock, a partner at Jones Day in Dallas who served as the SEC regional director in Fort Worth, Texas, from 2011 to 2015. “They’re looking even more closely at how companies are booking reserves, how they’re evaluating the quality of those reserves and what their intentions really are. They’re not accepting pat answers.”

Drillers face pressure to keep reserves growing. For many, the size of their credit line is tied to the measure. Investors want to see that a company can replace the oil and gas that’s been pumped from the ground and sold.

There are two ways to increase reserves: buy more or find more. Fracking made it easier to do the latter, and the industry lobbied the SEC to count more undeveloped acreage as proved reserves, arguing that shale prospects are predictable across wide expanses.

The SEC agreed, with two key limits. First, the wells must be profitable to drill at a price set by an SEC formula. The companies got a temporary reprieve for 2014 because the SEC number was about $95 a barrel even though crude had plummeted to less than $50 by the time results were reported in early 2015.

That advantage has disappeared. When companies reported their 2015 reserves this year, the SEC price was about $50. Wells that vanished this year may return if prices rise.

The SEC also requires that undeveloped wells be drilled within five years of being added to a company’s books. The five-year plan can’t just be wishful thinking. “The mere intent to develop, without more, does not constitute ‘adoption’ of a development plan,” the SEC explained in 2009.

Despite those limitations, reserves surged 67 percent in the five years after the 2009 rule change, according to 53 companies that have records going back that far. Almost half the gains came from wells that existed only on paper.

Fix Estimates

By the end of 2014, undeveloped properties accounted for 39 percent of proved oil and gas reserves, up from 33 percent at the end of 2009, an increase of nearly 8 billion barrels.

In its first letter to Ultra, in July 2014, the SEC said it would take about 13 years for the company to drill its backlog. About two months later, Ultra raised $850 million in debt. The SEC letters weren’t yet public. Over the next 19 months, the regulator twice told the company to revise its estimates.

Falling Prices

Ultra responded that its drilling plans changed due to falling prices and the shrinking availability of financing. The company sometimes delayed or canceled certain wells in favor of more profitable locations, the company wrote.

Ultra ultimately agreed to a small revision to its 2011 reserves booking. It was disclosed in a footnote to its 2015 annual report, after the SEC completed its review in February. In the same report, Ultra deleted all of its undeveloped reserves because of uncertainty about financing.

The letters were made public in mid-March. By then, Ultra’s shares had plummeted to 58 cents, and the bonds issued less than two years before were selling for about 8 cents on the dollar. Prices have since rebounded.

Sandi Kraemer, Ultra’s director of investor relations, declined to comment. So did Judith Burns, an SEC spokeswoman.

Other companies have also drawn SEC scrutiny. The agency said in correspondence with Goodrich Petroleum Corp. that the company drilled only 4 percent of its undeveloped reserves each year, a slower pace than necessary to comply with the five-year rule. Linn Energy LLC kept undeveloped reserves on its books at the end of 2014 even after cutting its drilling budget by 61 percent. Both companies have gone bankrupt in recent months owing a combined $8.1 billion. Neither would comment for this story.

For many drillers, “development plans weren’t realistic,” said Julie Hilt Hannink, head of energy research at CFRA, an accounting advisory firm in New York.

Rising Bankruptcies

Penn Virginia Corp., a company in which billionaire George Soros had a stake, booked paper wells in natural gas prospects where it hadn’t drilled in years, according to letters from the SEC.

“Your actual drilling has consistently failed to follow schedules,” the SEC wrote in an April 2015 letter. Penn Virginia responded that it had intended to get to the wells within five years but its plans changed when prices fell.

That’s not what company executives told investors, according to conference call transcripts. H. Baird Whitehead, Penn Virginia’s chief executive officer, said in a November 2012 call that “under almost no scenario” would the company resume gas drilling. Yet, when Penn Virginia filed its report with the SEC three months later, the prospects accounted for more than 40 percent of its reserves.

During an April 2013 call, Whitehead said, “We don’t plan on drilling natural gas wells.” Still, the undeveloped natural gas wells comprised 19 percent of the company’s reserves at the end of that year. Patrick Scanlan, a spokesman for Penn Virginia, declined to comment.

The company intended to follow the SEC’s five-year rule, according to a person familiar with Whitehead’s thinking.

Penn Virginia erased most of its undeveloped reserves this year. The company filed for bankruptcy May 12 with $1.2 billion in debt. Records show Soros sold his six million shares in the first quarter.

http://www.bloomberg.com/news/articles/2016-06-15/shale-drillers-paper-wells-draw-sec-scrutiny-before-vanishing

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Oil producer Canadian Natural Resources Ltd sharply raised its cash-flow forecast for the year as it gains from a rally in crude oil prices.

The company said on Wednesday that it now expected free cash flow of C$670 million ($519 million) in the fourth quarter, nearly double the C$338 million it forecast previously.

The oil producer also said it expected the final part of the second phase of its Horizon oil sands project, located north of Fort McMurray in Alberta, to start in four months, with estimated initial production of 45,000 barrels per day.

Canadian Natural plans to start the third phase of the project in the fourth quarter of 2017.

http://www.reuters.com/article/cdn-natural-rsc-outlook-idUSL4N1974A9

U.S. shale oil producer Devon Energy Corp said on Wednesday it would sell Texas acreage to Pioneer Natural Resources Co and an undisclosed buyer for $858 million, as the pace of asset sales picks up on recovering oil prices.

The sale is part of a push by Devon to shed up to $3 billion in noncore assets as it tries to strengthen its balance sheet after the worst price crash in a generation.

"We anticipate our total noncore asset sales to be at or above the top end of our $2 billion to $3 billion guidance," CEO Dave Hager said in a statement.

Devon also increased its 2016 capital budget by $200 million, saying it now plans to spend $1.1 billion to $1.3 billion this year, and slightly raised its 2016 production guidance for core operations to between 540,000 and 560,000 barrels of oil equivalent per day (boepd).

Devon said the acreage it sold to Pioneer for $435 million is mostly undeveloped and currently produces around 1,000 boepd.

Current production from acreage sold to an undisclosed buyer for $423 million is about 22,000 boepd.

Pioneer said it was issuing 5.25 million common shares to help pay for the purchase of 28,000 acres from Devon's Midland Basin acreage for $435 million.

Pioneer, known for its aggressive hedging program, also said it would add five drilling rigs in Texas starting in September, bringing its total rig count to 17 as oil prices recover to $50 a barrel.

These rig additions will add about $100 million to the company's capital budget for 2016, lifting it to $2.1 billion.

http://www.reuters.com/article/us-devon-energy-divestiture-idUSKCN0Z12LE

Liquefied Natural Gas Limited’s unit, Bear Head LNG, received Governor in Council approval for its licence to import natural gas from the United States and export LNG from the plant to be located on the Strait of Canso in Richmond County, Nova Scotia.

Bear head LNG was granted a licence to import and export natural gas in August last year, however that licence was subject to the approval of the Governor in Council, LNg Limited’s statement reads.

Commenting on the approval on Thursday, Greg Vesey, managing director and CEO of LNG Limited and president of Bear Head LNG said the approval positions the Bear Head LNG to become a major LNG supplier.

According to the licence, Bear Head LNG can import up to 14.2 billion cubic metres of natural gas per annum, which would be sufficient to export up to 12 mtpa of LNG from Canada, both licences are for a period of 25 years.

The project has already secured approval from the United States Department of Energy to export US-sourced natural gas to countries that have and those that do not have a free-trade agreement with the US.

http://www.lngworldnews.com/bear-head-lngs-licence-approved-by-governor-in-council/

Pioneer Natural Resources Company today announced that it has priced an underwritten public offering of 5.25 million shares of its common stock for gross proceeds of approximately $827 million. The Company has granted the underwriters an option for 30 days to purchase up to an additional 787,500 shares of the Company’s common stock. Credit Suisse, J.P. Morgan, Deutsche Bank Securities and Morgan Stanley are acting as joint book-running managers for the offering. The underwriters may offer the shares from time to time in one or more transactions on the New York Stock Exchange, in the over-the-counter market, through negotiated transactions or otherwise at market prices prevailing at the time of sale, at prices related to prevailing market prices or at negotiated prices. The offering is expected to close on or about June 21, 2016, subject to customary closing conditions.

The Company expects to use a portion of the proceeds from the offering to fully fund its recently announced pending acquisition of oil and gas properties in the Midland Basin (the “Pending Acquisition”) and the remaining portion of the proceeds for general corporate purposes, including funding the drilling program on the acreage to be acquired in the Pending Acquisition and continuing to develop its acreage position in the Spraberry/Wolfcamp play in West Texas. The offering is not conditioned on the consummation of the Pending Acquisition, and if the Pending Acquisition is not consummated, the Company intends to use the proceeds from the offering for general corporate purposes, including continuing to develop its acreage position in the Spraberry/Wolfcamp play in West Texas.

The offering is being made pursuant to an effective shelf registration statement filed with the Securities and Exchange Commission (the "SEC"). The offering may be made only by means of a prospectus supplement.

http://www.businesswire.com/news/home/20160615006616/en/Pioneer-Natural-Resources-Company-Announces-Pricing-Common

Rex Energy has always been one of our favourite smaller drillers in the Marcellus/Utica region. Yes, we know you’re not supposed to love some of your drilling children more than others–but we do!

We’ve often called Rex “the little energy company that could, and does.” Like most E&Ps (exploration and production companies), Rex has had a tough time coming through the recent crash in the price of gas and oil;

Rex Energy 1Q16: Lost $62M, but Still Drilling in the Marc/Utica; and Rex Energy Swapping $631M in Private IOUs for Public IOUs.

Rex has always concentrated on two regions: the Marcellus/Utica, and the Illinois Basin. No more. Rex is now a “pure play” driller after announcing it will sell all of its Illinois Basin assets–for $40 million to Campbell Development Group…

http://marcellusdrilling.com/2016/06/rex-energy-selling-illinois-basin-assets-focus-100-on-marcellus/