$625 million Eagle Ford acreage acquisition makes WildHorse the second largest Eagle Ford player—for one fifth the price of Permian acreage

WildHorse Resource Development (ticker: WRD) today announced the purchase of 111,000 net acres in the Eagle Ford from Anadarko Petroleum (ticker: APC) and Kohlberg Kravis Roberts & Co (ticker: KKR).

In total WildHorse will pay $625 million for these properties. The deal is to be paid with $556 million cash to Anadarko and 6.3 million shares of WRD common stock to KKR.

Values the oil and wet gas focused acreage at $5,600/acre

The properties acquired are very close to existing WildHorse acreage, in the northern section of the Eagle Ford. Most acreage is in the oil window, but the southeast portion produces wet gas and condensate. In total, the properties are currently producing 7.6 MBOEPD, with proved developed producing reserves of 22.9 MMBOE. The $625 million purchase price equates to $5,600/acre, or $3,300/acre after adjusting for production.

This is far below the $30,000/acre or more often seen in recent Permian basin deals.

Most recent in series of transactions

This acquisition is the most recent in a series of purchases the company has made, establishing itself as a major player in the northern Eagle Ford. WildHorse’s acquisitions since 2015 have left the company with 385,000 net acres in the area, second only to EOG in Eagle Ford holdings. Pro forma to the acquisition, WildHorse produced 19.1 MBOEPD from its Eagle Ford properties, with 88% liquids.

Third generation frac design in the Eagle Ford yielding 55%+ IRRs

WildHorse has a new completion design that the company can use to develop its new acreage, its third generation of frac designs. Wells using this design typically outperform the company’s 91 BOE/ft. type curve, with recently drilled wells significantly outperforming. The company reports that its third generation wells yield IRRs of 55% or more, with the best wells approaching 140%. This new frac generation will be put to good use, as the acquisition adds 711 net locations where the 91 BOE/ft. type curve applies.

Carlyle to own 24% of the pro forma company

WildHorse will fund the cash portion of the acquisition through its credit facility and preferred stock. A total of $121 million will be provided by the company’s revolving credit facility, while the remaining $435 million will be funded by the Carlyle Group. In return the Carlyle Group, which currently has no ownership in WildHorse, will receive Series A Perpetual Convertible Preferred Stock. This preferred stock will pay a dividend rate of 6% per year, payable in kind, and may be converted to common stock in one year. Assuming full conversion, this gives the Carlyle group 23.8% ownership of the pro forma company. The transaction is expected to close around June 30.

WildHorse also reported first quarter results today, showing net earnings of $20.3 million, or $0.22 per share. First quarter highlights include:

Increased average daily production by 18% to 17.6 MBoe/d for the first quarter 2017 compared to 14.9 MBoe/d for the first quarter 2016
Increased Net Income to $20.3 million for the first quarter 2017 compared to a Net Loss of $14.2 million for the first quarter 2016. Increased Adjusted Net Income(1) to $0.1 million for the first quarter 2017 compared to a Net Loss of $13.7 million for the first quarter 2016
Increased Adjusted EBITDAX(1) by 95% to $34.6 million for the first quarter 2017 compared to $17.7 million for the first quarter 2016
Issued $350 million in senior notes due 2025 at 6.875% in February 2017
In early March 2017, WRD brought online its first Burleson North well and one of the strongest wells to date in the East Texas Eagle Ford, the Paul 134 #2H, with an IP-30(2) of 1,035 Boe/d (93% oil) on a 5,363’ lateral. When normalized for downtime and a 6,500’ lateral, the IP-30 is 1,321 Boe/d
In late March 2017, WRD brought online the Altimore #1H with an IP-30(2) of 1,048 Boe/d (84% oil) on a 6,435’ lateral and the Jackson #1H with an IP-30(2) of 958 Boe/d (85% oil) on a 6,297’ lateral

https://www.oilandgas360.com/wildhorse-ups-eagle-ford-stake-625-million-purchase-anadarko-kkr/

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Russian state oil firm Rosneft is struggling to close its $12.9 billion acquisition of India’s Essar Oil Ltd because six of Essar’s Indian creditors have yet to approve the deal, sources close to the talks said.

The state-run banks and financial institutions that are delaying Rosneft’s biggest foreign acquisition hold about $500 million of Essar’s debt, five industry and banking sources told Reuters.

Kremlin-controlled Rosneft, which sees the deal as vital to expanding in Asia’s fastest growing energy market, had aimed to close the deal at the end of 2016. Now a June target for completion may be in doubt.

“Tensions between Rosneft and Essar are running high,” said one of the industry sources, who like others asked not to be named.

The sources said the acquisition was still expected to go through, but one of them said Rosneft had written to Essar threatening to change the terms of the deal, including to pay a lower price, if the dispute over debt was protracted.

“The completion of the transaction was conditional upon receiving requisite approvals and satisfaction of customary conditions. The parties are working towards obtaining the requisite approvals to complete the transaction,” an Essar spokesman said.

“We are hopeful that the deal will be completed in the upcoming few weeks,” he added.

Rosneft Chief Financial Officer Pavel Fedorov told a conference call on Wednesday that the purchase was now expected to be completed by the end of June.

The six institutions holding up the transaction are IDBI Bank (IDBI.NS), Punjab National Bank (PNBK.NS), Syndicate Bank (SBNK.NS), Indian Overseas Bank (IOBK.NS), Life Insurance Corp of India and non-bank financier IFCI Ltd (IFCI.NS), the sources said.

The six lenders gave no official comment when contacted by Reuters.

Another industry source said Rosneft had wanted to finalize the deal in early June at the St Petersburg Economic Forum, where Indian Prime Minister Narendra Modi is due to meet Russian President Vladimir Putin. But he said those hopes have now faded.

Rosneft won a bidding war to buy Essar against Saudi Aramco, its biggest competitor in the oil export market.

The deal will give Rosneft a 49 percent stake, with a further 49 percent split between Swiss commodities trader Trafigura [TRAFGF.UL] and Russian fund United Capital Partners. The billionaire Ruia brothers will retain a 2 percent stake.

Russia’s VTB bank is acting as advisor on the transaction. It declined to comment on the hold up.

“The process of closing the deal is in its final stages and is expected to conclude soon,” a spokesman for Trafigura said, while UCP declined to comment.

CLEARING BAD DEBTS

The deal is also valuable for Modi’s government, as it seeks to clear India’s $150 billion in bad debt.

Essar Oil India owed about $5.5 billion to almost 30 Indian lenders. Apart from six, others have approved Essar’s transfer of ownership to Rosneft from its current owners Indian brothers Ravi and Shashi Ruia, banking sources said.

The State Bank of India (SBI.NS), the country’s biggest lender, has given its no-objection to the deal, the sources said.

https://www.oilandgas360.com/rosnefts-12-9-billion-essar-oil-deal-held-debt-issues/

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Cartel’s ‘current strategy is not working,’ says ETF Securities’ Shah

Oil traders largely expect the Organization of the Petroleum Exporting Countries to agree later this month to extend a production-cut agreement into the second half of 2017, but at least one analyst is very skeptical.

After all, the “current strategy is not working,” Nitesh Shah, commodity strategist at ETF Securities, wrote in a blog post Thursday.

He said that the most “credible options” for OPEC’s next move would be to either agree on a deeper cut or let the deal collapse. “The latter options seems the most likely outcome.”

OPEC members and some major non-OPEC oil producers agreed to reduce their collective output by 1.8 million barrels a day under a six-month agreement that began on Jan. 1.That pact is set to expire in June and OPEC is expected to make a decision on whether to extend it when members meet in Vienna on May 25.

Strong compliance with the cuts helped oil prices CLM7, +0.15%LCON7, +0.10% climb in February to their highest levels since the summer of 2015 but year-to-date, they have lost roughly 10%.

“The efforts of OPEC members with assigned quotas are being undermined” by growth in supply from OPEC members who don’t have quotas, as well as non-OPEC members who are part of the deal but aren’t sticking to it, and “rapid growth in supply from other countries, most notably the U.S.,” said Shah.

U.S. crude-oil production climbed to 9.31 million barrels a day for the week ended May 5, up from 8.77 million barrels a day at the end of 2016, according to data from the Energy Information Administration.

Meanwhile, in a monthly report released Thursday, OPEC raised its forecast for 2017 oil-production growth from countries outside of OPEC by more than 60%.

OPEC “repeating the same strategy for another six months will do little to shore up oil prices,” Shah said.

“OPEC nations have given up market share and have barely reaped any price gains,” he said. “Given that consensus expectations are for a simple deal extension (i.e. that is what is currently priced-in), following the status quo is unlikely to be met with a positive price response.”

If OPEC is “serious about getting the market to balance, it will have to cut deeper in order to ‘shock’ the market and drive prices higher,” said Shah.

But it would be a difficult to reach an agreement on a “bolder move,” with the “smaller and more financially-constrained members reluctant to give up more volume,” he said.

And if the cartel can’t reach an agreement for a deeper cut, the “default option,” said Shah, would be to do nothing and let the deal collapse.

And that’s exactly what he believes will happen. The meeting this month is likely to “surprise on the downside with a lack of agreement,” he said.

Under that scenario, WTI oil prices could fall close to $40 a barrel, which he sees as the “structural floor for oil prices, set by the break-even price of U.S. shale-oil production.”

http://www.marketwatch.com/story/heres-why-opec-might-just-let-the-deal-on-oil-output-cuts-collapse-2017-05-11

An aggressive turnaround helped Petroleo Brasileiro SA post a record operating profit in the first quarter and move ahead of schedule in reducing a debt burden that is the largest of any major oil firm.

Petrobras, as the state-controlled company is known, reported net income of 4.449 billion reais ($1.42 billion), well above a consensus estimate of 3.773 billion reais, while improving cash flow and debt metrics. Petrobras lost a net 1.246 billion reais in the first quarter of 2016.

Moves to increase output in some offshore fields, sell non-essential assets and keep expenses in check yielded the firm's best operating profit ever. Adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) rose 19 percent to 25.254 billion reais, beating the consensus forecast by 1.38 billion reais.

Chief Executive Pedro Parente said the strong result was driven by recurring factors such as cost controls, putting Petrobras ahead of a timetable to reduce net debt to 2.5 times annual EBITDA by the end of next year, from a ratio of 3.2 at the end of March.

"If we get to 2.5 (times EBITDA) before the end of 2018, that doesn't mean we're going to stop (reducing debt)," Parente told journalists. "We want to keep cutting so we can lower our interest payments."

A sharp drop in asset impairments also contributed to earnings as Petrobras moved on from a bribery scheme in which the book values of several projects were artificially inflated.

Free cash flow, the money left for holders of bonds and shares after operating and financial expenses, rose 12 percent from the fourth quarter to 13.368 billion reais.

"It was a strong beat across the board that brings about a tipping point for the case," said Pedro Albuquerque, who runs the Cosmos Capital hedge fund and has a position in Petrobras. "Parente still has room to keep cutting costs, so margins look sustainable."

Parente said the sale of natural gas pipeline NTS, which generated 6.7 billion reais in the second quarter, also boosted the odds of paying dividends for the first time since 2014.

To be sure, Parente still faces challenges such as oil prices near decade lows, a corruption scandal that highlighted governance flaws, and losses incurred over many years because of government-mandated fuel subsidies and money-losing investments.

Net revenue slipped 3 percent from a year earlier to 68.365 billion reais, about 1 percent below the consensus estimate.

http://www.reuters.com/article/us-petrobras-results-idUSKBN187352

Mercuria warns of undue impact of derivatives on dated Brent oil price

Trading in the North Sea crude oil physical market has seen a boost from a growing number of participants, but trader Mercuria warned on Thursday that more financial players meant derivatives could have an unduly large impact on the setting of the dated Brent benchmark price.

Dated Brent, which governs around two-thirds of the world's oil trades, is set using prices of physical barrels of four streams of North Sea crude, Brent itself, Forties, Ekofisk and Oseberg (BFOE) and a series of derivative rates.

Kurt Chapman, head of crude trading at Mercuria, a major player in both the physical and "paper" North Sea markets, said he welcomed the additional liquidity and vibrancy that a broader spectrum of market participants brought to the market, but said increased "financialisation" was not without consequence.

"The liquidity is appreciated, but we need to make sure we retain the robustness of the process," he said.

The pool of market players in the North Sea ranges from oil producers such as BP, Shell or Total, to traders such as Mercuria itself or Trafigura, as well as a range of more pure financial traders.

Market participants bid and offer cargoes of 600,000 barrels each traded on a platform run by pricing agency S&P Global Platts, known as "the window", and the lowest-priced crude will then set the daily price of dated Brent.

Mercuria is one of the world's largest traders of physical commodities. The company, which is based in Switzerland, traded 2.1 million barrels of oil equivalent per day in 2016.

This compares with 7 million bpd of crude and products traded by rival Vitol last year.

To manage price risk, traders use swaps such as contracts for difference (CFDs) to hedge cargoes, but not all participants in the North Sea derivatives market buy and sell physical barrels.

"Right now if you look at the Brent benchmark, in the window, there are physical bid and offers on the screen, fine, it's still a physical BFOE product," he said, adding that some derivatives eventually resulted in physical delivery," Chapman said during a panel discussion at the annual S&P Global Platts Crude Conference.

"The link between the two, the dated (price) and the BFOE (paper market) is actually a financial product, which are CFDs that are traded on the screen, more actively almost, by financial funds, 'curve shapers', or 'strippers', as we call them, who are trying to arbitrage opportunities between other financial products and they are setting a very significant portion of what ultimately becomes the dated Brent quotation."

The North Sea market, which is essentially backed by just 1 million barrels per day of supply, can be volatile and at times, just a handful of players will control a proportionally large number of barrels that they may need to service their own refineries or provide to customers, which in turn can create a temporary liquidity vacuum.

Financial players in the CFD market can accumulate large speculative positions that are never intended to result in physical delivery, but can have a knock-on effect on the price of a barrel of oil.

http://www.reuters.com/article/us-oil-nsea-trading-idUSKBN1871RF

When Khalid Al-Falih arrived at Davos in late January, the Saudi oil minister was exultant. The output cuts he’d painstakingly arranged with fellow OPEC states and Russia were working so well, he said, they could probably be phased out by June.

Almost five months later, U.S. production is rising faster than anyone predicted and his plan has been shredded. In a series of phone calls and WhatsApp messages late last week, Al-Falih told his fellow ministers more was needed, according to people briefed on the talks, asking not to be named because the conversations are private.

In their battle to revive the global oil market, OPEC and its allies are digging in for a long war of attrition against shale.

"OPEC is now recognizing they need longer -- and potentially deeper -- production cuts than they have anticipated," said Jamie Webster, a senior director for oil at the Boston Consulting Group Inc. in New York.

From the beginning, Saudi Arabia saw a quick one-off intervention: reduce production for a few months and speed up the recovery. The strategy had an option for a six-month extension, but Riyadh initially thought it wouldn’t be needed. U.S. shale, the plan assumed, wouldn’t recover fast enough.

And yet, shale has defied the naysayers. By the time OPEC meets in Vienna on May 25, U.S. output will be approaching the 9.5 million barrels a day mark -- higher than in November 2014 when OPEC started a two-year price war. The rebound has been powered by turbocharged output in the Permian basin straddling Texas and New Mexico.

Forced to adjust to lower prices, shale firms reshaped themselves into leaner operations that can thrive with oil just above $50 a barrel. Brent crude, the global benchmark, added 3 cents to $50.80 a barrel as of 1:04 p.m. in Singapore.

Since OPEC agreed to cut output six months ago, U.S. shale production has risen by about 600,000 barrels a day, wiping out half of the cartel’s cut of 1.2 million barrels a day and turning the rapid victory Saudi Arabia foresaw is turning into a stalemate. Al-Falih said this week Saudi Arabia is now pushing to extend the cuts "into the second half of the year and possibly beyond."

On Thursday, OPEC’s own monthly oil market report said that production from non-members would rise 64 percent faster than previously forecast this year, driven mainly by U.S. shale fields.

So far, OPEC hasn’t been able to "cut supplies faster than shale oil can increase,"  said Olivier Jakob of consultant Petromatrix GmbH.

To read a story on the revival of the U.S. shale industry, click here.

Al-Falih and his OPEC allies have made some progress. U.S. crude stockpiles have started to drop and the amount of oil in floating storage is contracting. The International Energy Agency and banks including Goldman Sachs Group Inc. predict a further contraction in stockpiles in the second half of the year.

Yet, the cartel faces big risks. The most prominent is that extending cuts lifts the oil price high enough for shale to hedge again, as it did earlier this year.

"The dilemma now for OPEC and their key non-OPEC partners Russia and Oman is that cutting to support prices risks stoking the embers of a shale fire storm," said Adam Ritchie, director at Petro-Logistics in Geneva.

Increasingly, the oil market believes the real battle between OPEC and Russia, on one side, and shale, on the other, will take place in 2018, when an increasing number of observers predict U.S. production will flood the market as it did in 2014.

"Risks are emerging to 2018 balances," said Martijn Rats, oil analyst at Morgan Stanley in London. "The U.S. is set up for strong supply growth next year, that could exceed one million barrels per day.”

U.S. shale producers used the price spike that OPEC triggered earlier this year to lock-in revenues for 2017, 2018 and, in some cases, even 2019. With their financial future relatively secure, they started deploying rigs. Since the count of active rigs in the U.S. reached a low last, producers have added an average seven units per week, the strongest recovery in 30 years.

The rig spree, coupled with efficiency gains, is yielding strong production growth. In the first quarter, EOG Resources Inc. and Pioneer Natural Resources Co., two of the largest U.S. shale producers, announced year-on-year output jumps of 18 and 19 percent respectively. Smaller companies, including DiamondBack Energy Inc., Parsley Energy Inc. and RSP Permian Inc., achieved 60 percent to 80 percent increases. A lot more is coming.

"Our break-even oil price is $20 a barrel," Frank Hopkins, Pioneer’s senior vice-president, told an industry conference in London this week. "Even in a $40 world, in a $50 world, we are making good returns.

According to the U.S. Energy Information Administration, American crude production will surpass the 10 million barrel a day mark by late next year, breaching the record high set in 1970. The shale boom will propel non-OPEC output up 1.3 million barrels a day next year, effectively filling up almost all the expected growth in demand.

"The supply and demand balance for 2018 looks very bad,” said Fared Mohamedi, chief economist at consultant The Rapidan Group in Washington. “That’s when the big fight is going to happen."

https://www.bloomberg.com/news/articles/2017-05-11/in-its-fight-against-u-s-shale-oil-opec-risks-lower-for-longer

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Turn So/So Shale Wells into High Performers with Refracking

Hold that decline curve!

Researchers at Los Alamos National Laboratory have done “extensive data mining” and analysis of 20,000 shale gas wells. In a paper published in the journal Applied Energy titled “The shale gas revolution: Barriers, sustainability, and emerging opportunities”,

Los Alamos researchers say that refracking existing wells with new technology can transform those wells from “diminished producers” (so/so wells) into “high-performers” long after the wells had supposedly hit peak production.

“We hypothesize that manipulating tail production could re-revolutionize shale gas extraction,” said lead author of the study, Richard Middleton.

Refracking eliminates the cost of drilling a new bore hole, and provides a smaller environmental footprint.

http://marcellusdrilling.com/2017/05/turn-soso-shale-wells-into-high-performers-with-refracking/

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OECD commercial oil stocks are falling but were still 3.01 billion barrels in March - 4.8 days of demand above 5-year average

@chris1reuters  

The Dutch TTF natural gas hub has now become the European benchmark for longer-term contracts, with its dominance over other European hubs only expected to increase in the future, a panel discussion at the Flame conference in Amsterdam said Thursday.

"It is becoming a global link, a Henry Hub for Europe... TTF will lead the way," said Patrick Barouki, head of gas trading & origination at Uniper Global Commodities. "There have been occasions when the entire move on the TTF can be put down to forex movements," with the increasing link of European pricing to US LNG, which is priced in US dollars.

"The TTF is the real market price. The NBP was the leader, TTF took over," said Didier Magne, head of Gas Europe at TrailStone. "TTF is the only place you can hedge the US LNG into Europe," Magne added, citing that liquidity on the further-out NBP seasons is poor compared to liquidity on the TTF Calendar Year contracts.

"TTF has turned out to be the benchmark hub, especially on the curve," said Gottfried Steiner, CEO of Central European Gas Hub. "People are happy with the TTF, it is the most widely used price index."

In a separate presentation, Thierry Bros -- senior research fellow at the Oxford Institute for Energy Studies -- said that "the TTF will become even more dominant compared to the UK," in the wake of Brexit, which he called a "great opportunity for the European gas industry due to more volatility in the price."

SPAIN, UKRAINE

Barouki said that the Spanish PVB hub was "quite exciting" with a "a large pick-up in liquidity over the past 12 months," on the back of within- day/day-ahead trading allied with new balancing rules.

"The [French] TRS has been a hindrance," Barouki said, as well as expensive regasification costs, however, he said that "over the next years, Spain could develop a major role for Europe."

"The further away you are geographically, the less influence TTF becomes," said Steiner, citing arbitrage opportunity for market participants in southern Europe given the high prices seen in Spain, France, and Italy this winter compared to northwest Europe.

On a potential Ukrainian gas hub, Magne said that he was "very optimistic" and that "huge progress" had been made by the Ukrainian government to facilitate the development of a hub as the country tries to reduce reliance on Russian gas.

However, the panel cited expensive entry costs as a hindrance and that market participants were not seeking access to underground gas storage capacity.

"Entry costs are Eur0.70/MWh into Ukraine, three times normal entry costs," Magne said. "It kills any advantage, just going in and out costs more than the most expensive storage in TTF."

Barouki said that the high entry costs make it "impossible to commercially use it."

As for access to Ukraine's 31 Bcm of storage capacity, Magne said that "Europe is over-engineered already, you don't need the storage."

https://www.platts.com/latest-news/natural-gas/amsterdam/dutch-ttf-natural-gas-hub-now-the-henry-hub-for-26733755

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China's state planner will lower gasoline retail prices by 250 yuan ($36.22) per tonne and diesel fuel by 235 yuan per tonne from Friday, the National Development and Reform Commission said in a statement on its website on Thursday.

The decrease is the fourth and the biggest so far this year as crude oil prices continued to drift lower.

http://www.reuters.com/article/chinia-fuel-prices-idUSB9N1IA00G

OPEC boosted estimates for growth in rival supplies by 64 percent as the U.S. oil industry’s recovery accelerates, threatening the group’s attempts to clear a surplus.

Production from outside the Organization of Petroleum Exporting Countries will increase by 950,000 barrels a day this year, OPEC said in a report, revising its forecast up by about 370,000. The projection is four times higher than in November, when the group announced a production cut to try and re-balance oversupplied world markets. Non-OPEC nations pump about 60 percent of the world’s oil.

Oil prices sank to a five-month low below $44 a barrel in New York last week on concern that the cuts by OPEC and 11 partners, including Russia, aren’t clearing the glut and that more supply is coming from U.S. shale drillers. While OPEC has signaled it will probably extend the cutbacks into the second half, the increased production outlook for competitors may fuel speculation their strategy has backfired.

“U.S. oil and gas companies have already stepped up activities in 2017 as they start to increase their spending amid a recovery in oil prices,” OPEC’s Vienna-based research department said in the report. “In addition to the growth in the U.S., higher oil production is expected in Canada and Brazil.”

The report echoed comments from officials such as Saudi Arabian Energy Minister Khalid Al-Falih and his Russian counterpart Alexander Novak that prolonged action will likely be required when ministers gather on May 25.

“Continued rebalancing in the oil market by year-end will require the collective efforts of all oil producers to increase market stability,” it said.

The organization raised its outlook for U.S. production growth by 285,000 barrels a day to 820,000 a day. The number of drilling rigs operating in the country has more than doubled since May, data from Baker Hughes Inc. shows, as shale explorers emerge from a two-year rout buoyed by the initial price gains after OPEC announced its plan.

Original Projection

When OPEC introduced its 2017 forecast for non-OPEC supply last July, it had projected a contraction of 100,000 barrels a day.

The report indicated that OPEC’s objective to reduce inventories to their five-year average remains some way off. While it noted that surplus oil held at sea diminished, stockpiles in the most industrialized nations increased from the fourth quarter by 31 million barrels to just over 3 billion. That’s 276 million above the five-year norm.

OPEC members are still sticking with their pledge to reduce output, the report showed. Production from all 13 members slipped by 18,200 barrels a day to 31.73 million last month, with Saudi Arabia continuing to pump below its official target.

https://www.bloomberg.com/news/articles/2017-05-11/opec-raises-2017-estimate-for-supply-growth-from-rivals-by-64

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Enbridge Inc, Canada's largest pipeline company, forecast a big rise in adjusted earnings before interest and taxes this year, following its acquisition of smaller rival Spectra Energy Corp.

Enbridge said last September it would buy Spectra, then valued at $28 billion, to create the largest energy infrastructure company in North America.

The deal, which closed on Feb.27, highlighted the pressure on pipeline companies to merge as they grapple with over-capacity and sliding tariffs.

Calgary, Alberta-based Enbridge, which reported a lower-than-expected profit on Thursday, said it expects adjusted profit before interest and taxes of C$7.2 billion ($5.25 billion) to C$7.6 billion in 2017, much higher than the C$4.7 billion it earned last year.

However, the company said it expects available cash flow from operations to fall to C$3.60 to C$3.90 per share this year, from C$4.08 per share in 2016.

Weak earnings from Enbridge's liquids pipeline business weighed on profit in the first quarter ended March 31.

Adjusted earnings in the unit fell 10 percent to C$970 million in the quarter.

Net earnings attributable to shareholders fell 47 percent to C$638 million, or 54 Canadian cents per share.

Excluding a C$416 million derivative gain and other one-time items, adjusted profit was 57 Canadian cents. The analysts' average estimate was 62 Canadian cents, according to Thomson Reuters

http://www.reuters.com/article/us-enbridge-inc-results-idUSKBN1871E3

Painted Pony Petroleum Ltd.  is pleased to announce increased credit facilities and first quarter 2017 financial and operating results.  The first quarter was notable for the announcement of the proposed strategic acquisition of UGR Blair Creek Ltd. through a share purchase agreement whereby Painted Pony agreed to acquire all of the issued and outstanding shares of UGR (“UGR Acquisition“), subject to shareholder approval on May 11, 2017 at the annual general and special meeting of Painted Pony shareholders.

FIRST QUARTER 2017 HIGHLIGHTS:

Entered into an agreement to increase credit facilities to $500 million conditional upon closing of the UGR acquisition, including available credit facilities of $400 million and a development line of $100 million, which becomes available in stages of $50 million by October 31, 2017 and $50 million by April 30, 2018, subject to borrowing base review at those dates;
Announced the planned expansion of Painted Pony’s Montney assets through the proposed UGR Acquisition, which will add average daily production of 51 MMcfe/d (8,500 boe/d) based on field estimates, Proved plus Probable reserves of 2.0 Tcfe (325.1 MMboe), 108 net sections of land, and 105 MMcf/d of owned natural gas processing capacity;
Generated net income for the first quarter of 2017 of $56.9 million compared to a net loss of $2.2 million in the first quarter of 2016, and income before taxes of $8.6 million, excluding the unrealized gain on commodity risk management contracts, compared to a $1.3 million loss before taxes during the first quarter of 2016;
Increased production by 116% to 215.3 MMcfe/d (35,878 boe/d), in-line with previously released guidance, compared to 99.6 MMcfe/d (16,601 boe/d) during the first quarter of 2016;
Increased liquids production by 270% to 3,149 bbls/d or 9% of total production volumes, compared to 852 bbls/d or 5% of total production volumes in the first quarter of 2016;
Received an average natural gas price of $2.87/Mcf, which represented a 7% premium to the AECO daily spot price, compared to a 12% discount during the first quarter of 2016;
Increased funds flow from operations by 226% to $24.8 million compared to $7.6 million during the first quarter of 2016;
Reduced operating costs by 30% to $0.62/Mcfe compared to $0.88/Mcfe during the first quarter of 2016, and;
Decreased general and administrative (“G&A“) expenses by 37% to $0.17/Mcfe compared to $0.27/Mcfe during the first quarter of 2016.

SUBSEQUENT EVENT

On April 5, 2017 Painted Pony closed an equity financing whereby the Corporation issued a total of 19,820,000 common shares (the “Offering“) in the capital of the Company (“Common Shares“) at a price of $5.60 per Common Share for net proceeds of $106 million.

UGR ACQUISITION

Upon closing, the UGR Acquisition will be a strategic expansion of Painted Pony’s world-class Montney project in NEBC. The Corporation’s Montney land position will increase by 52% to 314 net sections (201,009 net acres at an average 94% working interest) in one of the most productive areas of the Montney in British Columbia. Several of Painted Pony’s most prolific Montney wells were drilled on the Daiber area lands that are either contiguous with UGR acreage or on lands held jointly with UGR. The UGR Acquisition includes 197 net Proved plus Probable drilling locations which will complement the Painted Pony inventory and are expected to drive near-term growth in the Corporation’s proved developed producing reserves.

http://boereport.com/2017/05/10/painted-pony-reports-increased-credit-facilities-and-first-quarter-2017-financial-and-operating-results/

The BP Plc company logo sits on a sign outside the company’s headquarters in St. James’s Square in London, U.K., on Thursday, Feb. 28, 2013. BP Plc’s push to maximize profits and cut costs at the Macondo well was a “root cause” of the explosion that led to the 2010 Gulf of Mexico oil spill, a safety expert who studied the disaster said. Photographer: Chris Ratcliffe/Bloomberg

BP has fired up two natural gas fields in the Mediterranean Sea near Egypt, the start of a $12 billion development expected to supply nearly a third of the African country’s gas in coming years.

The British oil company began producing gas from the Taurus and Libra fields off the coast of Egypt eight months ahead of schedule, the company said Wednesday. Its fields are producing more than 700 million standard cubic feet of gas a day and 1,000 barrels of condensate, 20 percent more than anticipated.

It’s the second of seven major projects the British oil company plans to turn on this year, part of an effort to lift its daily energy production by 800,000 barrels of oil equivalent by the end of the decade. In a statement, BP CEO Bob Dudley said these projects “demonstrate momentum and a return to growth across BP.”In Egypt, BP’s West Nile Delta development is expected to make up a quarter of the energy production it expects to bring online by 2020.

Egypt’s growing population ballooned to 92 million late last year, pushing up energy demand in a country that only a few years ago suffered regular power blackouts because of a shortage of natural gas.

By 2019, gas production from BP’s Egyptian fields could reach 1.5 billion cubic feet of gas a day, about 30 percent of the country’s current output, it said. The company began sending gas from the Taurus and Libra fields to Egypt’s national gas grid in late March, and it recently ramped up production to a stable level.

Falling energy prices helped bring down the cost of supplies for the projects, BP said.

“Thanks to a clear focus on efficiency and capturing market deflation, this complex project has been delivered with lower capital levels compared to project sanction,” said Hasham Mekawi, North African regional president at BP, in a statement.

http://fuelfix.com/blog/2017/05/10/bp-fires-up-first-gas-fields-in-12-billion-egypt-project/

Realized NGL prices more than doubled

Cimarex Energy (ticker: XEC) reported first quarter earnings today, announcing net income of $131 million, or $1.38 per share. This result compares favorably to the $38.2 million income in Q4 2016 and the $231.5 million loss the company recorded in Q1 2016.

Total production up 11% sequentially

Total company production grew by 11% sequentially, more quickly than expected. Year-over-year realized commodity prices improved across the board, with oil prices increasing by 70% from $28.02. Natural gas prices increased by 57% to average $3.01/Mcf, and NGL prices more than doubled to $20.40/bbl, from $9.84/bbl received in Q1 2016.

Overall, Cimarex expects to produce an average of about 1.11 Bcfe/d in 2017, an increase of 15% beyond 2016 production. After completing 26 wells in Q1, the company plans to complete a total of 73 in the rest of the year, with an additional 44 wells drilling or waiting on completion at the end of the year.

Cimarex is currently running eight rigs in the Permian, where the company owns 225,000 net acres. Several tests of various facets of development are currently in progress in the company’s Delaware basin acreage. In northern Culberson County Cimarex is testing infill drilling in the lower Wolfcamp, evaluating six wells in the formation per section. While most wells are still in initial production, Cimarex reports that wells targeting both upper and lower landings in the zone are yielding good returns. Notably, wells in the upper landing zone currently have a higher oil yield.

Increasing frac intensity has also produced good results, as tests in the upper Wolfcamp in Culberson County and the Avalon Bone Spring in Lea County have each produced significant improvements in returns.

Extensive downspacing tests in Mid-Continent

In the Mid-Continent the company owns significant acreage in the stacked plays of the Meramec and Woodford. The company is running six rigs in the area, and brought ten net wells online in Q1 2017.

Cimarex reports that a total of 16 downspacing pilots are underway in the Meramec, and the company has interest or data in all but three. Cimarex itself is currently running the Leon Gundy pilot, where eight total wells are evaluating ten Meramec wells and nine Woodford wells per section. Farther south, where the Woodford dominates, Cimarex is testing 16 and 20 wells per section. The results of these tests will guide the company as it plans infill drilling on its extensive acreage.

Q&A from XEC Q1 2017 conference call

Q: Lea County, it seems like there’s been a lot of activity there lately or a lot, I guess, results coming out between yourselves, EOG had some nice wells. I know Devon’s doing some down-spacing in there. Can you just talk about, is this something different or I know you’ve been up there and you’re testing tighter spacing, but can you just talk a little more general about the area and what you’re seeing?

XEC CEO Thomas E. Jorden: We’ve always loved Lea County. One of the reasons that we haven’t aggressively developed our acreage at the multiple levels is because it’s really quite good and we wanted to make sure that we got our spacing and our science right because you can’t always back up and get a do over. There have been some offset well results. We’ve extended our mapping, and the play has just extended. And we’re quite bullish on the outset, not only for the Wolfcamp, but a number of different zones.

XEC SVP of Exploration John Lambuth: I would just say that you’ll see more of our activity moving into Lea County later this year. We have quite a bit of drilling we want to do up there. It’s not – like Tom said, we’ve always loved Lea County. It’s just over the last few years, with the pull back in our capital, most of our drilling has been to hold acreage that we needed to hold down in Culberson and Reeves. We are very fortunate that almost all of our position in Lea is a well-held HBP acreage, be it a previous drilling we’ve done mostly in the Bone Spring and other targets. So we’re just now starting to focus more energy to get in there and then taking advantage, as Tom said, of the fact that a lot of our competitors are “delineating” our acreage for us. So it looks very, very attractive and thus resulting in the updating we gave on the increase in the acreage there.

https://www.oilandgas360.com/cimarex-testing-downspacing-permian-mid-continent/

Oil is trading near $50 again, OPEC seems to be losing its ability to influence prices and a wave of new supply is hitting the market from Texas to Libya. For some, there’s never been a better time to buy.

Despite last week’s selloff, the global oil market is rebalancing rapidly, said Jeffrey Currie, head of commodities research at Goldman Sachs Group Inc. If the Organization of Petroleum Exporting Countries extends its cuts into the second half -- as the group has signaled -- demand will significantly exceed production, according to the IEA’s Head of Oil Industry and Markets Neil Atkinson.

“Do I want to be long oil? The answer is absolutely yes because we are going into a deficit market,” Currie said at the S&P Global Platts Global Crude Summit in London on Wednesday. “With demand continuing to surprise to the upside,” the global supply deficit may be as wide as 2 million barrels a day by July, he said.

Brent crude, the international benchmark, fell to a five month low of $46.64 a barrel last week amid doubts about the effectiveness of OPEC and Russia’s joint supply curbs. Subsequent signals from Saudi Arabia and Moscow that they could extend cuts into 2018 failed to trigger much of a price recovery. While the resurgence in U.S. shale oil continues to cause doubts about whether the three-year supply glut really is over, banks including Goldman and Citigroup Inc. say markets are nevertheless tightening and prices are poised to rise again.

The bulls got some powerful backing on Wednesday from the most keenly watched data on the market -- the U.S. Department of Energy’s weekly report on crude stockpiles. The nation’s inventories fell by 5.2 million barrels last week, the biggest reduction this year. West Texas Intermediate crude rallied as much as 3.3 percent to $47.40 within minutes of the data release. It was trading 0.6 percent higher at $47.59 a barrel as of 12:43 p.m. in Singapore. Brent gained 0.6 percent to $50.50.

Falling Stockpiles

The decline in global fuel stockpiles will accelerate this quarter, Currie said. The volume of crude held in floating storage on tankers -- often a key indicator of a supply surplus -- is dropping like a brick, he said.

The aim of OPEC’s supply deal was to shrink inventories, and by that measure it’s succeeding, said Bassam Fattouh, a director at the Oxford Institute for Energy Studies.

OPEC and its allies looks set to prolong their agreement into the second half of the year, but not everyone is convinced they’ll maintain the near-full cuts compliance seen in recent months.

For Russia, Iraq and Iran -- three of the largest producers involved in the agreement -- curbs in the first quarter were comparatively easy to implement, said David Fyfe, chief economist at oil trader Gunvor Group. The Middle Eastern producers were already close to their maximum production capacity, while Russia usually experiences a seasonal lull in the winter, he said.

“They’ll likely agree to extend into the second half of 2017, but the risk is higher that they’ll leak extra barrels onto the market,” he said.

Leaking Oil

Two OPEC members exempt from reducing output because of internal strife are already doing just that. Libya’s crude production has risen to 800,000 barrels a day as fields restart, the most since 2014. Nigeria’s 200,000 barrel-a-day Forcados oil pipeline is ready to export again after being shut down almost continuously since February 2016.

There’s little chance of OPEC cutting any deeper than they have already and demand growth this year will be lower than the IEA forecasts, said Fareed Mohamedi, chief economist of The Rapidan Group, a consultant based in Bethesda, Maryland. Prices could drop back as low as $30 a barrel by the first quarter of 2018, he said.

Still, Fyfe said stockpiles will probably keep falling even with “a bit of slippage” in OPEC compliance.

Goldman Sachs, which believes OPEC will extend and potentially deepen its cuts, sees West Texas Intermediate crude advancing to $55 and Brent climbing to $57 in the fourth quarter, said Currie.

“It is starting to become clear that if the objective of the OPEC cuts was to flip the market from a surplus into a deficit, that is slowly beginning to happen," said the IEA’s Atkinson.

https://www.bloomberg.com/news/articles/2017-05-10/goldman-to-iea-see-oil-bulls-back-on-top-as-cuts-dent-stockpiles

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Attached Files

U.S. Customs and Border Protection has withdrawn an Obama-era proposal to modify a law that governs shipping, which would have revoked waivers that make it easier for oil and gas operators to skirt restrictions, according to an agency bulletin published Wednesday.

For nearly 40 years the CBP has provided exemptions to the Jones Act, which mandates the use of U.S.-flagged vessels to transport merchandise between U.S. coasts. The exemptions have allowed oil and gas operators to use often cheaper, tax-free, or more readily available foreign flagged vessels.

The CBP has weighed revoking these waivers after President Barack Obama's administration proposed to put them on the chopping block two days before President Donald Trump took office.

The oil industry expressed relief about the CBP announcement. Oil and gas majors operating in the U.S. Gulf of Mexico had stepped up lobbying efforts over the last two months to urge the CBP not to remove the waivers.

“By rescinding the proposal, CBP has decided not to impose potentially serious limitations to the industry’s ability to safely, effectively and economically operate," said Erik Milito, director of upstream and industry operations for the American Petroleum Institute.

In the bulletin, CBP director Glen Vereb said that the agency received many comments in support of and opposing the proposed action and said it "should be reconsidered."

http://www.reuters.com/article/us-usa-oil-jonesact-idUSKBN1862QQ

Exxon Mobil Corp said on Thursday it has reached an agreement to buy a refining and petrochemical plant owned by Jurong Aromatics in Singapore that will boost its output and meet demand in Asia.

The company expects to complete the transaction in the second half of 2017, boosting its aromatics production in Singapore to more than 3.5 million tonnes per year (tpy), including 1.8 million tpy of paraxylene, a raw material for textiles and bottles.

The plant will be integrated with Exxon Mobil's existing petroleum complex on Jurong Island, said Gan Seow Kee, chairman and managing director of ExxonMobil Asia Pacific Pte Ltd.

Singapore houses Exxon Mobil's largest refining-petrochemical complex with a crude oil processing capacity of 592,000 barrels per day and two steam crackers.

The Korea Herald reported in March that Exxon Mobil had outbid Lotte Chemical Corp (011170.KS) with a price of 2 trillion won or about $1.7 billion for the JAC plant.

Exxon's spokeswoman said it is not the company's practice to discuss details of its commercial transactions.

JAC's condensate splitter and petrochemical units - at a construction cost of $2.4 billion - started operations in Asia in 2014 to produce paraxylene to meet demand from textile and bottle manufacturers in China.

JAC's debt mounted, though, as commodities went into freefall in the middle of that year, and it stopped operations at end-2014 to fix a technical issue. Its lender BNP Paribas appointed accounting firm Borelli Walsh as the receiver and manager of JAC.

The JAC plant resumed operations in July 2016 under tolling agreements with BP and Glencore.

http://www.reuters.com/article/singapore-exxon-mobil-idUSL4N1ID1R0

Pioneer Natural Resources CEO says his company breaks-even at $20

Pioneer Natural Resources CEO says his company breaks-even at $20 a barrel. "In a $40 world we make good returns".

Pioneer Resources says it wants to quadruple output to 1m b/d by 2026, focusing on Permian

#PlattsCOS

Carrizo Oil & Gas, a Houston-based driller, actively drills in the Eagle Ford Shale in South Texas, the Delaware Basin in West Texas, the Niobrara Formation in Colorado, and until mid-year in 2015, they did have an active drilling program in the Ohio Utica and Pennsylvania Marcellus.

No more. They haven’t drilled in Appalachia since 3Q15. During the company’s fourth quarter/full year 2016 earnings call, it seemed to us that Carrizo signaled a potential sale of their Marcellus/Utica assets.

Looks like we were right. Yesterday on an earnings call for 1Q17, Carrizo CEO S.P. “Chip” Johnson said, “We have elected to test the market for our Appalachian assets, as they do not currently compete for capital with our three core oily plays.

Monetization of these assets would leave Carrizo with a core position in three high-return, oil-weighted plays and should enhance our long-term production growth profile.” Translation: We’ve now put the “for sale” sign out on our Marcellus/Utica assets.

http://marcellusdrilling.com/2017/05/carrizo-og-puts-up-for-sale-sign-on-marcellusutica-assets/

U.S. crude oil refinery inputs averaged about 16.8 million barrels per day during the week ending May 5, 2017, 418,000 barrels per day less than the previous week’s average. Refineries operated at 91.5% of their operable capacity last week. Gasoline production increased last week, averaging about 10.1 million barrels per day. Distillate fuel production decreased last week, averaging about 5.0 million barrels per day.

U.S. crude oil imports averaged over 7.6 million barrels per day last week, down by 644,000 barrels per day from the previous week. Over the last four weeks, crude oil imports averaged about 8.2 million barrels per day, 5.0% above the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 953,000 barrels per day. Distillate fuel imports averaged 115,000 barrels per day last week.

U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) decreased by 5.2 million barrels from the previous week. At 522.5 million barrels, U.S. crude oil inventories are in the upper half of the average range for this time of year. Total motor gasoline inventories decreased by 0.2 million barrels last week, but are above the upper limit of the average range. Finished gasoline inventories increased while blending components inventories decreased last week. Distillate fuel inventories decreased by 1.6 million barrels last week but are in the upper half of the average range for this time of year. Propane/propylene inventories increased by 2.0 million barrels last week but are in the lower half of the average range. Total commercial petroleum inventories decreased by 3.6 million barrels last week.

Total products supplied over the last four-week period averaged 19.7 million barrels per day, down by 1.6% from the same period last year. Over the last four weeks, motor gasoline product supplied averaged over 9.2 million barrels per day, down by 2.4% from the same period last year. Distillate fuel product supplied averaged about 4.1 million barrels per day over the last four weeks, down by 0.7% from the same period last year. Jet fuel product supplied is up 6.7% compared to the same four-week period last year.

Cushing down 400,000 bbls

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

                                                   Last Week  Week Before     Year Ago

Domestic Production '000......... 9,314            9,293            8,802
Alaska .............................................. 531                526               487
Lower 48 ..................................... 8,783             8,767            8,315

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

Malaysian state-owned oil and gas company Petronas is looking to divert LNG volumes from Japan to emerging floating storage and regasification unit markets as supply contracts with Japanese utilities are due to expire next year without an extension agreement in place, a company executive said Tuesday.

"We are looking at all these emerging markets as a home for those volumes," vice president for LNG trading and marketing Ahmad Adly Alias said on the sidelines of the 19th Asia Oil and Gas Conference in Kuala Lumpur.

Among the contracts nearing expiry is the 7.4 million mt deal, including FOB and DES volumes, between Malaysia LNG, which is majority-owned by Petronas, and Japanese utilities Jera and Tokyo Gas. This contract is due to expire in 2018.

"Obviously, we would like to renew those contracts, but we have options," he said, adding that this was why Petronas was getting into the spot market.

Petronas sold 30-40 cargoes through spot and strip deals in 2016, and expects its share of spot trade volumes to continue to rise as growing supply, new market participants, and increasing availability of ships boosts liquidity in global LNG markets.

Executive adviser with Tokyo Gas Shigeru Muraki said on the sidelines of the conference that the Japanese utility was still considering an extension of its supply contract with Malaysia, worth 2.6 million mt/year, beyond 2018.

"We value our long-term relationship with Malaysia, so our priority is to recontract," he said.

But added the buyer would seek reduced volumes, more flexibility and price diversification if the contract was to be extended.

"Of course we will compare with other sources, and also consider the diversification of supply sources and diversification of the price," Muraki added.

"We need some evolution [in long-term LNG contracts]," he said.

https://www.platts.com/latest-news/natural-gas/kualalumpur/malaysia-petronas-eyes-new-lng-markets-as-japan-26732858

Most European refinery maintenance so far this year took place in the first quarter, with Q2 seeing works diminishing ahead of the start of the driving season which typically boosts demand for products and margins.

In Russia, maintenance accelerated somewhat in April, although remains lighter than last year.

NORTHWEST EUROPE

Some big maintenance is scheduled in Scandinavian countries later in the year, but Q2 works are mostly restricted to routine unit maintenance, taking place at Slagen, Gothenburg and Porvoo, as well as some longer albeit partial works at the Lysekil plant near Brofjorden.

So far works have had limited impact, predominantly on bunker and low sulfur fuel oil supply.

The UK's Grangemouth escaped unscathed from an ethylene gas leak at the nearby Grangemouth Kinneil Gas plant, and the Humber refinery restarted in early April after Q1 works.

In the ARA hub, Total's Antwerp integrated refinery and petrochemical platform has been affected by works/upgrade since Q1, with impact on operations likely until the upgrade is commissioned later this year.

In Germany, the maintenance season, having started early in the year, has been carried over into Q2 although to a somewhat lesser extent.

Partial works are to be carried out in Leuna, with the only large-scale works planned at the Lingen plant from mid-April.

In neighboring Austria, around half the facilities at Schwechat will be halted for about two months.

In central Europe, Romania's Petromidia is carrying out a full shutdown in May while Slovnaft has partial maintenance between April and June.

MEDITERRANEAN

In early May, Total's Feyzin refinery in the south of France halted operations due to a strike action. The duration of the strike remains unknown. In Spain, after a heavy maintenance in Q1, works were rather marginal in Q2 with Repsol's Cartagena undergoing works on diesel units.

Corunna concluded its maintenance in early April. Italy's ISAB has been carrying out works spreading over part of April and May and Taranto is offline for most of Q2 for planned works.

In Israel, the Ashdod refinery is due to carry out major works throughout May.

Algeria's Skikda is also carrying out works in Q2, although duration and extent of the works had been mired in uncertainty.

SOUTH AFRICA

Bunker traders especially have been concerned about fairly big maintenance in South Africa in Q2, with both Engen and Sapref carrying out work.

RUSSIA

The Moscow refinery has been slowly restarting after a lengthy maintenance and upgrade which started in January. Although restart has been underway throughout April, by early May the refinery was still not fully back to normal output, according to traders.

Another refinery that encountered some hurdles on the way to restarting was the Perm plant where a fire during the restart of the VDU unit resulted in the unit's halt.

Over the course of May, the Yaroslavl refinery should be gradually coming out of maintenance and by the end of the month both Astrakhan and Taneco are due back online.

Meanwhile, Antipinsky carried out short routine works for a week in April.

But maintenance is taking its toll in Siberia and the Far East, with Achinsk and Komsomolsk carrying out works with supply issues exacerbated by the prolonged maintenance of Khabarovsk.

https://www.platts.com/latest-news/oil/london/factbox-spring-refinery-maintenance-in-europe-26732675

Plains All American planned crude line -- to run from the Permian Basin in Texas to Cushing, Oklahoma -- will provide producers with yet another route to send their output, giving them the option of blending those light barrels to suit refinery demand, CEO Greg Armstrong said Tuesday.

"Rising production [out of the Permian] needs to find an outlet and a pipeline to Cushing is not on everybody's radar," he said. "But it will be in two to three years."

Also, a pipeline to Cushing will provide Permian producers with an option to "blend the lower gravity crude," Armstrong said.

To support growing output in Oklahoma, Plains is also working towards expanding capacity on its STACK pipeline to 250,000 b/d from 100,000 b/d by the fourth quarter, COO Willie Chiang said on the same investor conference call. But that capacity could even go to 350,000 b/d through the installation of pumps, Chiang said, without giving any details if that expansion has been underpinned by shipper interest.

The pipeline runs from the STACK area in Oklahoma to the storage hub in Cushing.

Also in Oklahoma, the company remains on track to complete the Diamond Pipeline by the fourth quarter despite protests from stakeholders, Armstrong said.

In the Permian, a combination of cost efficiencies and increasing drilling activities has resulted in a major surge in output there. According to Platts Analytics Bentek Energy, crude production is projected to grow from 2.43 million b/d in 2017 to 3.467 million b/d by 2022.

DRILLING EFFICIENCY SUPPORTS NEW INFRASTRUCTURE

While midstream players such as Buckeye Partners, Magellan, Enterprise and even Plains, have all proposed pipelines from the Permian to export facilities in Corpus Christi and the Houston Ship Channel, Armstrong said in a oil price environment of WTI $50/b to $60/b there will still be increased interest to move barrels out of that basin to other areas.

"Rigs are becoming more efficient and we expect transport volumes to ramp up in the latter part of the year, particularly in the Permian," he said.

Plains, which has about 4,000 miles of pipeline network in the basin, is seeing "tangible evidence" of pipeline utilization, with its open season for the Permian-to-Cushing pipeline launched on April 18 already attracting shipper interest, Armstrong said.

The pipeline, with origin points in the Midland and Colorado City areas of the Permian, will transport crude to Plains' terminal in Cushing. It will have a nameplate capacity of 350,000 b/d, with start-up targeted in mid-2019.

The Permian-to-Cushing pipeline has sufficient shipper interest of some 150,000 b/d of capacity, Chiang said.

Besides oil, the Permian has also attracted attention for the amount of associated gas that is located there. Midstream operators, some backed by private equity firms, are pouring billions of dollars into new infrastructure there.

Asked whether Plains sees a downside from the increased competition in the Permian, Armstrong said more capacity is a good thing because it is needed given the level of production.

"Between Plains and Magellan and Enterprise, we're doing the most prudent thing we can, bringing on as much capacity as we can so we don't see a train wreck out there," the CEO said.

https://www.platts.com/latest-news/oil/newyork/growing-permian-production-justifies-plains-crude-21686518

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Attached Files

Libya's oil production is running at above 800,000 barrels per day (bpd) for the first time since 2014, the National Oil Corporation (NOC) said on Wednesday, but a commercial dispute with German oil firm Wintershall [WINT.UL] has shut in a further 160,000 bpd.

National output could reach between 1.1 million and 1.2 million bpd if political obstacles were removed, the NOC said in a statement.

"We are able produce an average of 1.1 mln-1.2 mln (bpd) over the rest of this year, but for this to happen our oil must flow freely. A national effort is required," NOC Chairman Mustafa Sanalla said in the statement.

Sanalla said the dispute with BASF's oil and gas company Wintershall was linked to a decree issued by the Presidency Council of the U.N.-backed government in Tripoli giving it the power to negotiate investment agreements with foreign companies.

The NOC opposes the decree, Resolution 270, which Sanalla said had been "drafted with the assistance of Wintershall to benefit Wintershall".

"This is a very serious matter," Sanalla said. "We would be producing almost 1 million (bpd) if it were not for Wintershall's refusal to implement terms it agreed to in 2010."

Sanalla did not say what those terms were, but a Libyan oil industry source said the NOC was asking Wintershall to fulfill a commitment signed before the revolution in 2011 to switch to a production-sharing agreement, and that Wintershall was refusing to do so.

"I have asked the Presidency Council to withdraw Resolution 270 for this reason and because it oversteps their authority. It has declined, and has instead sided with Wintershall against NOC."

No one at Wintershall in Germany could immediately be reached for comment.

http://www.reuters.com/article/us-libya-oil-idUSKBN1861DC

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Attached Files

Russia boosts Urals oil flow to India as OPEC cuts output: traders

Russia has steeply raised Urals oil supplies to India, taking market share from OPEC countries that are cutting production as part of a global pact to prop up prices, traders said and shipping reports showed on Wednesday.

Historically, Russian crude oil exports to India did not exceed 500,000 tonnes per year, but since the start of 2017 supplies have surpassed 1 million tonnes and are expected to rise further, according to the traders and reports.

India's main crude suppliers, Saudi Arabia and Iraq, cut exports to India this year due to production curbs under the agreement between OPEC and other leading oil producers.

Iran, also a major supplier to India, is decreasing shipments due to a row over a gas field.

State oil giant Saudi Aramco will reduce oil deliveries to Asia by about 7 million barrels in June, including by 3 million barrels for India, as it consumes more crude domestically while its production remains curtailed by the OPEC pact.

“Large Urals flows to India have been one of the main new trends for Russian oil exports this year, and it was clearly triggered by OPEC cuts amid rising demand,” said a trader at a trading desk of one oil major.

A favourable Brent-Dubai spread, very thin since February, gives India access to a variety of Brent-linked grades, one of which is Urals.

Indian Oil Corp bought at least 4 million barrels of Urals crude for June delivery in its spot tender from Litasco and Trafigura, traders said.

Three cargoes of 1 million barrels each loading from Novorossiisk will be supplied by Litasco, while Trafigura will supply 1 million barrels of Urals, they added.

Urals was also sent to India this year by Shell and Vitol, traders said. They added that Vitol was likely to ship 1 million barrels of Urals to India for June delivery as well.

Indian refiners Reliance Industries and Essar Oil also bought Urals crude this year, according to traders and shipping reports.

Russian oil supplies to India will likely increase further if and when state oil major Rosneft closes a $12 billion deal to buy India’s Essar plant.

The active buying of Urals is due to attractive prices sellers can offer to India's refiners, which want to increase spot intake to improve their economic performance, but the trend is fragile, a trader with an Indian company said.

"All the market factors support Urals arbitrage - reasonable freight, thin Brent-Dubai, OPEC cuts - but as soon as something changes, sellers won't be able to offer India's refiners competitive pricing," a trader on the Mediterranean market said.

India's refiners are not yet ready to commit any term contracts for Urals supply, traders said.

Whether OPEC continues its production cut in the second half of the year is a key factor that will influence Urals arbitrage to India, traders said.

http://www.reuters.com/article/us-russia-india-oil-idUSKBN1861B1

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Attached Files

Royal Dutch Shell on Wednesday urged oil pricing agency S&P Global Platts to protect the dated Brent crude benchmark from declining North Sea supply by including other grades, such as Russian Urals, in its price-setting process.

The suggestion marks a shift from two years ago when Shell said adding Urals would not be "worth the trouble".

The benchmark, based on light North Sea crude grades, is used to price about two-thirds of the world's oil but a decline in North Sea output has led to concerns that physical volumes could become too thin and prone to large price swings.

Platts announced it would add a fifth grade, Troll, to the benchmark slate from January 2018 but Shell says more must be added in the next two to three years and considers Russian medium sour Urals as a top candidate.

The benchmark is now made up of Brent, Forties, Oseberg, and Ekofisk, known as BFOE.

"A good benchmark need not only be representative of what the region produces ... If you had to pick one grade of crude, Urals is the one which northwest European refineries should be designed to run optimally," Mike Muller, vice president of crude trading and supply at Shell, told the Platts Crude Summit in London.

Muller also suggested the price of dated Brent be derived from the average price of a basket of crudes, rather than by using the lowest priced of the four BFOE crudes on any given day. This would simplify the price-setting process, he said.

Two years ago, Muller said European refineries were already free to buy Urals - a crude stream that dwarfs North Sea streams in volume - as a substitute to the North Sea Forties grades as they are similar in quality.

Muller also called for the formation of a committee of independent experts to consult with Platts and the wider industry on future changes to the benchmark in order to ensure the views of all market players were represented.

Shell is one of the world's largest crude traders and one of the most active players in both the North Sea and Urals markets.

Shell’s North Sea production is set to drop by more than half to about 110,000 barrels per day after the sale of a large package of North Sea assets to private equity-backed Chrysaor last year. But Shell will market Chrysaor’s volumes for several more years.

http://www.reuters.com/article/us-oil-brent-shell-idUSKBN1860XA

Suncor Energy, Canada's largest oil and gas producer, is hoping to start building a new oil sands project later in Alberta this year, which would have an estimated production of up 160,000 barrels a day.

The Lewis project would be located about 25 km northeast of Fort McMurray and could eventually produce up to 160,000 barrels a day.

While the firm hasn’t officially sanctioned the Lewis project, located about 25 km northeast of Fort McMurray, it expects construction to begin in 2024, according to information posted in Suncor’s website.

The Calgary-based company also said it would consider using new technologies, including vaporized solvents and electromagnetic heating to replace steam, to produce the heavy bitumen crude through wells at Lewis. This would allow the company to use reduced amounts of energy and water.

The announcement comes as Canadians have been asked to weigh on another potential project, belonging to Teck Resources. Canada's largest diversified miner is proposing to build its Frontier mine about 110 kilometres north of Fort McMurray, in Alberta.

Alberta’s oil sands hold the world’s third-largest crude reserves, but they are also among the most expensive operations due to their remote location and energy-intensive production methods.

http://www.mining.com/suncor-plans-build-new-oil-sands-project-canada/

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Russia's Gazprom has achieved a good balance between oil-indexed and hub-based gas pricing in its contracts with European buyers and has no intention in moving increasingly towards hub indexation in the future, the CEO of Gazprom Export said Tuesday.

Speaking at the Flame conference in Amsterdam, Elena Burmistrova also slammed the concept of a price war between Russian pipeline gas and LNG in Europe, saying that some of the commentaries on the subject were "conspiracy theories."

At present, the share of hub-based and hybrid gas contracts (a mix of hub-based and oil-indexed pricing) makes up just more than 50% of the volumes of gas sold by Gazprom in Europe, she said.

"The rest are gas volumes with oil product indexation -- this is a great example of how our portfolio reflects the situation on the market," she said.

Asked whether there would be a move toward more hub pricing in the future, Burmistrova was categorical.

"In the short term, we are not going to do this. At the moment everyone is fully satisfied," she said.

"We make a lot of effort to balance our contracts, and at the moment we have the right balance," she said.

Burmistrova also made the point that despite oil indexation being unpopular while oil prices were high, consumers are now happier to have oil-based pricing given the lower oil price.

"Oil indexation, which was previously heavily criticized, has now become more appealing than ever before due to the drop in oil prices," she said.

She also continued Gazprom's long-standing argument that hub prices in Europe were still not a reliable pricing point.

"I would say that we still don't feel that the hub prices are the most reliable instrument," she said.

She said that with the exception of the Dutch TTF hub, many other market zones were not sufficiently developed to be used as an index for gas pricing.

"I wouldn't use the word 'manipulate' because it is too strong a word, but I would say they can be used by the big players to form a current price," she said.

GAS MARKET SHARE STRATEGY?

Russia's share of the European gas market grew in 2016 to 34%, Burmistrova said, adding that it was Gazprom's ambition to retain a share of around one third in Europe.

She said, however, that Gazprom was not looking to take more European market share, and dismissed the idea of using price to drive out rival suppliers.

"Market share is not a goal in itself for us. We don't want to take the market and die by doing this," she said.

"The European gas market is a territory of peaceful competition, not a war of 'all against all'. I'd like to cool the enthusiasm of the price war instigators: Gazprom never prioritizes volumes over prices or vice versa," she said.

Burmistrova said that the popular concept in the media of a price war was misplaced, adding that the debate ranged from "pure conspiracy theories to well-rounded analytics."

"Our strategic task is to keep a one-third share of European consumption and we will carry out the strategy in a peaceful way without a price war," she said.

There has been an expectation that much of the new supplies of US LNG -- which began to flow to world markets in February 2016 -- would land on European shores.

However, to date no US LNG cargoes have come to northwest Europe, with only a handful of cargoes arriving in Spain, Portugal and Italy.

Gazprom, meanwhile, hit an all-time European export high of 178.3 Bcm last year.

"This proves that Gazprom can compete with traditional pipeline suppliers, but also with LNG suppliers, including the ambitious LNG producers from the US," Burmistrova said.

"US LNG didn't really affect the market for us."

Asked how Gazprom would feel if its market share unintentionally exceeded one third because of increased European demand, she said Gazprom would theoretically be happy because it is a commercial company.

"But I'm not sure the European Commission would be," she said.

GAS AUCTIONS

Gazprom in recent years has introduced more flexible selling mechanisms, with some commentators saying it is part of the Russian company's strategy to appease the Commission.

Burmistrova said Gazprom was working on holding another gas auction in 2017 following three previous sales in 2015 and 2016.

"We are working on it quite carefully," she said, adding that the auction process was designed to help expand the European gas market, "not to conquer it and not to divide it."

Two of the previous three auctions were for delivery of gas into Germany, while the other was for delivery into the Baltic states.

She said that by 2025, Europe would need an additional 50 Bcm of imported gas given the decline in indigenous European natural gas production, giving an opportunity for "every supplier."

She pointed to the reliability of Gazprom's long-term contracts that give the company a competitive advantage.

"Last winter we witnessed cases when prices on gas hubs -- in particular in southern Europe -- hit the psychological mark of $500 [/1,000 cu m)," she said.

"At the same time, Gazprom's clients reliably received their volumes at prices below $200 [/1,000 cu m]. That is the benefit of the predictability of Gazprom's long-term contracts," she said.

She said that last year, the share of oil-indexed or quasi oil-indexed contracts in Europe was more than 54% compared with the share of hub-based contracts at just over 42%.

"Europe is still a hybrid market," she said.

https://www.platts.com/latest-news/natural-gas/amsterdam/gazprom-sees-no-increase-in-hub-based-gas-pricing-26731877

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New pipelines in the Permian Basin should have enough capacity to “accommodate” rising oil production in the Permian Basin, the U.S. Energy Information Administration said in a report Tuesday.

A lack of infrastructure between West Texas and refineries along the Gulf Coast., had at one point caused the crude in Midland to sell at a $15 a barrel discount to crude moving through the pipeline hub in Cushing, Okla, the agency said.

But that shortfall, ” is unlikely to be either as large or as persistent as it was following the rapid increase in Permian production from 2010 to 2014,” EIA said. “As crude oil production in the Permian Basin of western Texas and eastern New Mexico has increased, pipeline infrastructure has also increased to deliver this crude oil to demand centers on the U.S. Gulf Coast.”

Since 2010, oil production in the Permian has more than doubled to more than 2 million barrels a day,

http://fuelfix.com/blog/2017/05/09/feds-say-new-permian-pipelines-should-accommodate-rising-production/

Italian energy company Eni reported its best quarterly profits in two years on Wednesday buoyed by higher oil prices and production and confirmed its full-year targets.

Adjusted net profit for the first quarter rose to 744 million euros ($810 million) from breakeven a year earlier and topped the 610 million expected by analysts.

Like many of its peers, state-controlled Eni has benefited from higher crude prices after a two-year price downturn that rocked the industry.

BP, ExxonMobil, Chevron and Total have all beaten analysts' profit forecasts for the quarter.

CEO Claudio Descalzi confirmed Eni's targets for the year, and noted first-quarter cash generation of 2.6 billion euros was its strongest performance in seven quarters.

"We expect that in 2017 organic cash generation, coupled with proceeds from disposals, will allow us to fully fund our capex and dividend requirements at an oil price well below the current level," Descalzi said.

Eni, which in recent years has made major gas finds in Mozambique and Egypt, holds one of the best discovery track records in the industry.

On Wednesday it confirmed production would grow by 5 percent this year to 1.84 million barrels of oil equivalent per day (boed) lifted by start-ups in Egypt and Kazakhstan.

In the first quarter Eni produced 1.795 million boed, up 2.3 percent from a year earlier.

http://www.reuters.com/article/us-eni-sults-idUSKBN1860LN

The American Petroleum Institute (API) reported a hefty draw of 5.789 million barrels in United States crude oil inventories, compared to analyst expectations that markets would see a crude oil draw of 1.8 million barrels for the week ending May 5.

Gasoline inventories rose by 3.169 million barrels, according to the API, against an expected draw of 700,000 barrels. Gasoline inventories continue to worry markets, as refiners continue to turn crude oil into gasoline above demand for the fuel.

So while crude oil has experienced an overall drawdown over the last couple of weeks, it’s simply being converted to gasoline, and extra inventories are moving from one side of the refinery to the other. Gasoline inventories have continued to build for four weeks in a row, if the EIA confirms this week’s build tomorrow.

According to the EIA, gasoline inventories have climbed almost 5.1 million barrels in the last three weeks ending April 28—if confirmed, the four-week build would be over 8 million barrels.

http://oilprice.com/Latest-Energy-News/World-News/Oil-Rebounds-After-API-Reports-Biggest-Crude-Draw-This-Year.html

Higher crude output from the United States should limit any upside to global oil prices through the end of 2018, the U.S. government said on Tuesday, ahead of a meeting of major oil producers later this month to discuss extending supply cuts.

U.S. crude production is expected to rise by more than previously expected in 2017 to 9.31 million barrels per day from 8.87 million bpd in 2016, a 440,000 bpd increase, the U.S. Energy Information Administration said.

It expects total output for 2018 to rise to nearly 10 million bpd, with most of that coming from the increase to the 2017 forecasts. Higher output in non-OPEC countries, particularly the United States, Canada and Brazil, has offset OPEC's deal reached last year to cut production and kept pressure on oil prices.

The Organization of the Petroleum Exporting Countries and non-OPEC member countries will meet in Vienna on May 25 to discuss whether to continue output cuts of 1.8 million bpd in an effort to reduce a global crude glut and support prices.

The OPEC deal reached in November helped lift prices but also breathed new life into U.S. producers, who have boosted drilling in shale regions and raised U.S. output to levels not seen since mid-2015.

Last month the EIA forecast a 350,000 bpd year-over-year increase, according to its monthly short-term energy outlook.

For 2018, the EIA's growth forecast is 650,000 bpd, down from its previous forecast of 680,000 bpd. Its forecast for total output in 2018 rose to 9.96 million bpd from 9.90 million bpd.

"Also, we should start to see Dakota Access pipeline and other infrastructure improvements liberate more and more U.S. barrels. We have only just started to see the real rebound in shale," he said.

Top oil exporter Saudi Arabia said on Monday that it would "do whatever it takes" to rebalance a market that has been dogged by oversupply for more than two years.

The EIA forecast U.S. oil demand for 2017 to rise 290,000 bpd, up from its previous forecast for a 250,000 bpd increase. For 2018, oil demand is expected to increase by 300,000 bpd, down from a previously forecast rise of 340,000 bpd.

http://www.reuters.com/article/us-usa-oil-eia-steo-idUSKBN185297

Saudi Aramco will reduce oil supplies to Asia by about 7 million barrels in June, a source said on Tuesday, as the oil giant cuts output as part of global supply pact and trims exports to meet rising domestic demand for power during hot summer months.

An OPEC-led agreement to cut global oil supplies is currently due to end in June, although Saudi Arabia and other producers in the group of OPEC and non-OPEC states have indicated curbs could be extended to the end of 2017 or beyond.

OPEC and other producers are expected to discuss an extension at a meeting on May 25.

When OPEC announced the cuts, Saudi Arabia was quick to tell its customers in Europe and the United States that they would receive lower volumes but shielded most of Asia from the cuts.

However, summer is a peak period for power demand in the desert kingdom, as citizens turn up air conditioners to keep homes and offices cool, pushing up domestic oil consumption.

This year is likely to see an earlier spike in demand as the Muslim fasting month of Ramadan starts sooner, beginning in late May. The traditional big evening meals with family and friends to break the fast tend to create a surge in power demand.

As a result, Asia will now also face heavier cuts from the world's top oil exporter in June.

According to the June nomination plans, Aramco will cut supplies by 1 million barrels each to Southeast Asia, China and South Korea, a source, who has knowledge of the nominations but did not wish to be identified, told Reuters.

A separate industry source said the action in June did not mean Saudi Arabia was preparing to deepen cuts to Asia in the rest of 2017.

The kingdom will cut supplies by a little more than 3 million barrels for India and slightly less than 1 million barrels for Japan, the source with knowledge of the nominations said. In total, the cuts should be equivalent to about 233,000-234,000 barrels per day (bpd).

Under the global supply pact, OPEC states, Russia and other major producers agreed to cut output by about 1.8 million bpd from Jan. 1 until June 30.

Saudi Arabia accounts for about 40 percent of the cuts pledged by OPEC. It has reduced output by more than 500,000 bpd so its total production now runs slightly below 10 million bpd, mostly involving cuts in output of medium and heavy oil grades.

Industry sources told Reuters in April that higher domestic demand for oil in the summer would weigh on exports especially if Saudi Arabia kept output at about 10 million bpd.

Saudi Arabia usually burns about 700,000 bpd of oil for power generation to keep the nation cool in the hottest months from May to August.

This summer, the kingdom is planning to raise energy prices and use more natural gas in power stations to reduce oil usage. Those measures are expected to cut consumption by about 200,000 bpd, industry sources said.

http://www.reuters.com/article/us-aramco-oil-idUSKBN1851ZK

U.S. shale explorers are boosting drilling budgets 10 times faster than the rest of the world to harvest fields that register fat profits even with the recent drop in oil prices.

Flush with cash from a short-lived OPEC-led crude rally, North American drillers plan to lift their 2017 outlays by 32 percent to $84 billion, compared with just 3 percent for international projects, according to analysts at Barclays Plc. Much of the increase in spending is flowing into the Permian Basin, a sprawling, mile-thick accumulation of crude beneath Texas and New Mexico, where producers have been reaping double-digit returns even with oil commanding less than half what it did in 2014.

That’s bad news for OPEC and its partners in a global campaign to crimp supplies and elevate prices. Wood Mackenzie Ltd. estimates that new spending will add 800,000 barrels of North American crude this year, equivalent to 44 percent of the reductions announced by the Saudi- and Russia-led group.

“The specter of American supply is real,” Roy Martin, a Wood Mackenzie research analyst in Houston, said in a telephone interview. “The level of capital budget increases really surprised us.”

Drilling budgets around the world collapsed in 2016 as the worst crude market collapse in a generation erased cash flows, forcing explorers to cancel expansion projects, cut jobs and sell oil and natural gas fields to raise cash. The pain also swept across the Organization of Petroleum Exporting Countries, which in November relented by agreeing with several non-OPEC nations to curb output by 1.8 million barrels a day.

Oil prices that initially popped above $55 in the weeks after the cut was announced have since dipped to around $46, reflecting pessimism that the OPEC-led deal can withstand the onslaught of U.S. shale.

So far, independent American explorers such as EOG Resources Inc. and Pioneer Natural Resources Co. are holding fast to their ambitious growth plans. Some recently finished wells in the Permian region yielded 70 percent returns at first-quarter prices, EOG Chief Executive Officer Bill Thomas told investors and analysts during a conference call on Tuesday.

EOG, the second-largest U.S. explorer that doesn’t own refineries, plans to boost spending by 44 percent this year to between $3.7 billion and $4.1 billion. Pioneer is eyeing a 33 percent increase to $2.8 billion. The sub-group that includes North American shale drillers like EOG and Pioneer is collectively targeting $53 billion in spending this year, up from $35 billion in 2016, according to the Barclays analysts led by J. David Anderson.

U.S. oil production is already swelling, even though output from the new wells being drilled won’t materialize above ground for months. The Energy Department’s statistics arm raised its full-year 2017 supply estimate to 9.31 million barrels a day on Tuesday, a 1 percent increase from the April forecast.

Next year, U.S. fields will pump 9.96 million barrels a day, 0.6 percent more than the department estimated last month.

To be sure, most of the biggest U.S. and European explorers -- an elite caucus of five companies known as the supermajors -- are pursuing a contrary path and cutting expenditures this year. As deepwater, oil-sands and other high cost, high risk investments soured during the slump, the supermajors were battered and had to regroup. But shale drillers, unburdened by such large-scale projects, have been better able to quickly respond to price changes.

Holding Tight

Royal Dutch Shell Plc, Chevron Corp., Total SA and BP Plc are reducing or holding flat on 2017 spending. Only Exxon Mobil Corp., the largest member of the group, is pushing up its budget, planning to spend $22 billion this year compared to $19.3 billion last year.

West Texas Intermediate, the U.S. benchmark, lost 14 percent of its value since April 11 amid signals the global crude glut isn’t shrinking at the expected pace. The futures fell 1.3 percent to $45.82 at 1:15 p.m. on the New York Mercantile Exchange. The price hasn’t poked above the $50 mark since April 26.

Shale drillers can afford to be sanguine despite oil’s recent tumble because they’ve cushioned themselves with hedges, Martin said. Hedges are financial instruments that lock in prices for future output and shield producers from volatile market movements.

“There is some price malaise creeping in,” Martin said. “But the aristocracy of the U.S. independents have insulated themselves” through hedging.

https://www.bloomberg.com/news/articles/2017-05-09/shale-drillers-challenging-opec-with-84-billion-spending-spree

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Demand isn’t expanding as much as expected: Vitol’s Asia head
Shale production is growing faster than forecast: Vitol’s Kho

OPEC and its allies are seeking to pump less for longer in a quest for higher prices. The world’s biggest independent oil trader says their efforts could be in vain.

Demand isn’t expanding as much as expected, and U.S. shale output is growing faster than forecast, according to Vitol Group. That’s increasing the burden on the world’s biggest producers, who need to stick to their pledges to cut supply just to keep prices from falling, said Kho Hui Meng, the head of the company’s Asian arm.

Oil has given up all its gains since the Organization of Petroleum Exporting Countries and other producers signed a deal late last year to limit supply for six months from January. Prices have been hit by surging output in the U.S., which is not part of the agreement. Any recovery in crude will depend on sustained usage by nations such as China, India and the U.S. as much as OPEC’s efforts to control supply.

“What we need is real demand growth, faster demand growth,” Kho, the president of Vitol Asia Pte., said in an interview in Kuala Lumpur. “Growth is there, but not fast enough.”

While consumption was forecast to expand this year by about 1.3 million barrels a day, growth has been limited to about 800,000 barrels a day so far in 2017, he said, adding that U.S. output had grown 400,000-500,000 barrels a day more than expected. “If demand goes back to where it should, where it’s forecast, then it’ll help, but my gut feel tells me it is still a bit long,” he said.

The International Energy Agency has trimmed its forecasts for global oil demand growth this year by about 100,000 barrels a day to 1.3 million a day as a result of weaker consumption in Organisation for Economic Co-operation and Development member countries and an abrupt slowdown in economic activity in India and Russia, according to a report last month. The Paris-based IEA cut its estimate for India’s 2017 oil-demand growth by 11 percent.

There’s also concern that consumption may slow in China, the world’s second-biggest oil user. Independent refiners, which account for about a third of the nation’s capacity, have received lower crude import quotas compared with a year earlier, prompting speculation their purchases could slow.

“The oil market is looking for growth but there’s no growth,” Vitol’s Kho said, adding that the refiners may only get approval for the same volume of imports as last year. And while U.S. gasoline consumption is expected to hit its seasonal summer peak soon, demand growth “is not there yet,” he said.

The world’s biggest crude exporter is nevertheless bullish. Saudi Arabia expects 2017 global consumption to grow at a rate close to that of 2016, Energy Minister Khalid Al-Falih said on Monday. “We look for China’s oil demand growth to match last year’s, on the back of a robust transport sector, while India’s anticipated annual economic growth of more than seven percent will continue to drive healthy growth,” he said in Kuala Lumpur.

While some fear a slowdown in Chinese oil demand, Sanford C. Bernstein & Co. doesn’t see any cause for concern. Growth in the nation’s car fleet will support gasoline demand, with increasing truck sales and air travel also helping fuel consumption, it said in a report dated May 9.

Saudi Arabia and Russia, the world’s largest crude producers, signaled this week they could extend production cuts into 2018, doubling down on an effort to eliminate a surplus. It was the first time they said they would consider prolonging their output reductions for longer than the six-month extension that’s widely expected to be agreed at an OPEC meeting on May 25.

Global oil inventories probably increased in the first quarter despite OPEC’s near-perfect implementation of production cuts aimed at clearing the surplus, the IEA said last month.

Shale Boom

“We’ve always talked about the call on OPEC, how much OPEC oil is needed to satisfy world demand,” said Nawaf Al-Sabah, chief executive officer of Kufpec, a unit of state-run Kuwait Petroleum Corp. “Now, in this new paradigm, it’s really becoming the call on shale. And the market is setting itself at the marginal cost of a shale barrel.”

U.S. output has jumped for 11 weeks through the end of April to 9.29 million barrels a day, the most since August 2015, Energy Information Administration data show. American benchmark West Texas Intermediate is trading near $46 a barrel in New York, while global marker Brent crude is near $49 a barrel in London. Both are more than 50 percent below their peaks in 2014.

“I am still watching the U.S. summer gasoline demand,” said Vitol’s Kho. “OPEC has said it will try and extend its output cuts beyond June. So if that happens, and the discipline is good, and if the U.S. lack of growth in demand changes into summer, then we may see oil go back to the low $50s, but the prevailing mood today is not.”

https://www.bloomberg.com/news/articles/2017-05-09/top-oil-trader-warns-shaky-demand-risks-scuppering-opec-mission

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Carrizo Oil & Gas Announces First Quarter Results and Increases 2017 Production Guidance

Carrizo Oil & Gas, Inc. today announced the Company’s financial results for the first quarter of 2017 and provided an operational update, which includes the following highlights:

Crude oil production of 28,844 Bbls/d, 12% above the first quarter of 2016
Total production of 46,367 Boe/d, 10% above the first quarter of 2016
Net income of $40.0 million, or $0.61 per diluted share, and Net Cash Provided by Operating Activities of $76.4 million
Adjusted Net Income of $12.1 million, or $0.18 per diluted share, and Adjusted EBITDA of $94.2 million
Increasing 2017 crude oil production growth target to 26%Borrowing base recently increased to $900 million, with an elected commitment of $800 million

Carrizo reported first quarter of 2017 net income of $40.0 million, or $0.61 per basic and diluted share compared to a net loss of $311.4 million, or $5.34 per basic and diluted share in the first quarter of 2016. The net income for the first quarter of 2017 and net loss for the first quarter of 2016 include certain items typically excluded from published estimates by the investment community. Adjusted net income, which excludes the impact of these items as described in the non-GAAP reconciliation tables included below, for the first quarter of 2017 was $12.1 million, or $0.18 per diluted share compared to $9.2 million, or $0.16 per diluted share in the first quarter of 2016.

For the first quarter of 2017, Adjusted EBITDA was $94.2 million, an increase of 2% from the prior year quarter due to higher production volumes and commodity prices, partially offset by lower cash receipts for derivative settlements. Adjusted EBITDA and the reconciliation to net income (loss) are presented in the non-GAAP reconciliation tables included below.

Production volumes during the first quarter of 2017 were 4,173 MBoe, or 46,367 Boe/d, an increase of 10% versus the first quarter of 2016. The year-over-year production growth was driven by continued performance from the Company’s Eagle Ford Shale and Delaware Basin drilling activity, the addition of production from the Sanchez property acquisition in late 2016, and an increase in Marcellus Shale production given improved netbacks. Oil production during the first quarter of 2017 averaged 28,844 Bbls/d, an increase of 12% versus the first quarter of 2016; natural gas and NGL production averaged 78,088 Mcf/d and 4,508 Bbls/d, respectively, during the first quarter of 2017. First quarter of 2017 production exceeded the high end of Company guidance due primarily to stronger-than-expected production from the Company’s Niobrara Formation and Delaware Basin assets.

Drilling and completion capital expenditures for the first quarter of 2017 were $128.2 million. More than 85% of the first quarter drilling and completion spending was in the Eagle Ford Shale, with the balance weighted towards the Delaware Basin and Niobrara Formation. Land and seismic expenditures during the quarter were $14.5 million. As a result of the improvement in commodity prices earlier this year, Carrizo has seen a material increase in planned non-operated activity on its acreage in the Niobrara Formation and Delaware Basin. Given this, the Company has increased its planned non-operated budget by approximately $30 million. Carrizo expects to offset this incremental capital through efficiency gains realized since the beginning of the year as well as a slight reduction in planned completion activity in the Eagle Ford Shale during the year. As a result, the Company is maintaining its 2017 drilling and completion capital expenditure guidance of $530-$550 million. The Company is increasing its land and seismic capital expenditure guidance to $45 million for the year from $20 million previously.

Based on the continued strong performance from the Company’s operated activity, Carrizo is increasing its 2017 oil production guidance to 32,400-32,700 Bbls/d from 31,400-31,900 Bbls/d previously. Using the midpoint of this range, the Company’s 2017 oil production growth guidance increases to 26% from 23% previously. For natural gas and NGLs, Carrizo is adjusting its 2017 guidance to 71-75 MMcf/d and 5,300-5,500 Bbls/d, respectively, from 69-73 MMcf/d and 5,600-5,900 Bbls/d, respectively. Carrizo continues to expect to deliver a three-year compound annual growth rate of more than 20% for its crude oil production. For the second quarter of 2017, Carrizo expects oil production to be 31,800-32,200 Bbls/d, and natural gas and NGL production to be 67-71 MMcf/d and 4,800-5,000 Bbls/d, respectively. A full summary of Carrizo’s guidance is provided in the attached tables.

S.P. “Chip” Johnson, IV, Carrizo’s President and CEO, commented on the results, “We are off to a good start in 2017 with production exceeding our expectations. While sequential crude oil production growth in the first quarter was impacted by a large number of planned shut-ins, the underlying production from each of our key regions continues to perform well. As a result, we expect to see a double-digit sequential increase in our crude oil production in the current quarter and now expect to grow our crude oil production by approximately 26% in 2017. This is up from 23% previously without any increase to our planned drilling and completion capital expenditures for the year.

http://boereport.com/2017/05/09/carrizo-oil-gas-announces-first-quarter-results-and-increases-2017-production-guidance/

President Donald Trump has chosen a longtime aide to Senate Majority Leader Mitch McConnell and a state utility regulator to serve on the Federal Energy Regulatory Commission, bringing the agency one step closer to regaining its power to rule on natural gas pipelines and utility mergers.

Trump plans to nominate Neil Chatterjee, a senior energy adviser to McConnell who previously worked for the National Rural Electric Cooperative Association, and Robert Powelson, a member of the Pennsylvania Public Utility Commission, for terms expiring in 2021 and 2020, respectively, an emailed statement from the White House late Monday shows. Kevin McIntyre, co-head of Jones Day’s global energy practice, is said to be Trump’s pick to lead the agency.

Federal lawmakers and industry groups including the Independent Petroleum Association of America and Interstate Natural Gas Association of America have been urging Trump to fill the three vacancies on the Federal Energy Regulatory Commission quickly. The agency lost the quorum it needs to make major decisions when former chairman Norman Bay resigned in February, leaving two Democrats to serve on the panel. His departure has threatened to stall a massive expansion of the U.S. gas pipeline network brought on by the shale boom.

The confirmation process could take two to three months if expedited, cautioned Brandon Barnes, an analyst at Bloomberg Intelligence. The last time a commissioner was confirmed, Bay in 2014, it took six months.

“It’s a very political process where there’s horse-trading, negotiating,” said Martin Edwards, head of government affairs for the Interstate Natural Gas Association of America. “It means delays in deploying project capital to build infrastructure.”

More than $50 billion worth of project applications are pending before the commission, including an application for the $2 billion Nexus gas line in the Midwest, which is scheduled to start by year-end. Other issues awaiting agency action are a proposed rule on commercial battery storage, and a decision on the commission’s income tax allowance policy for pipelines run by master limited partnerships.

COMPLIANCE, ENFORCEMENT

As an adviser to McConnell, Chatterjee served as an architect of major energy and environmental policy in the Senate, helping to coordinate attacks against President Barack Obama’s Clean Power Plan that requires power plants to cut carbon dioxide-emissions.

Powelson has been on the Pennsylvania Public Utility Commission since June 2008, and also served as its chairman, according to the commission’s website. He was elected president of the National Association of Regulatory Utility Commissioners, a Washington-based advocacy group, in November.

The commission normally consists of five members who serve five-year terms. Cheryl LaFleur, a Democrat and former utility executive, has been on the commission since 2010. The only other commissioner right now is Colette Honorable, a Democrat who previously served as chair of the Arkansas Public Service Commission. Honorable’s term ends in June, and she has said she won’t pursue another one.

http://boereport.com/2017/05/09/trump-names-picks-for-u-s-energy-agency-crippled-without-quorum/

India is likely to offer 26 unexplored oil and gasfields to domestic and international exploration and production (E&P) majors to kick-start the government’s newly unveiled Open Acreage Licensing Policy (OALP).

Prospective investors have been allowed access to geological data of these oil and gas fields and, although no official confirmation was available, sources say the bidding process will open in the next two months.

Under the OALP, prospective bidders will be free to bid for any of the potential oil and gas fields, but the government has reserved the right to invite counter bids before awarding the field.

Last month, the government formally approved the launch of OALP under which domestic and foreign E&P will be free to carve out areas from demarcated fields and choose where they would want to explore.

An official familiar with the process pointed out that once an investor carved out a block and submitted an offer, it would trigger an invitation for counter bids, which would also be considered before the government awards the bid.

The directorate general for hydrocarbons would provide prospective investors with access to the National Data Repository, which would enable the investor to make an informed decision on putting in bids for exploration and subsequent production, the official added.

“In the new model, the government will not micro-manage, micro-monitor the producers. The government will only take a share of the revenue. It will be an open and regular affair,” Petroleum and Natural Gas Minister Dharmendra Pradhansaid in a recent media statement.

Although officials were hesitant to divulge details, claiming that it was still “too early days of the new OALP”, industry sources say it is possible that the government will put on offer an estimated three-million square kilometers of unexplored sedimentary basin in the current financial year.

The OALP will demand stricter prequalification requirements than the marginal and small oil and gas fields that government recently awarded. The OALP requires that an investor has at least a year’s experience in operating, as well as a record of holding an acreage as per specific technical parameters laid down under the policy.

http://www.miningweekly.com/article/bidding-said-to-open-soon-for-oil-and-gas-exploration-under-indias-new-oalp-2017-05-09

Urals CIF Rotterdam established a premium over Urals CIF Augusta after Monday's assessment as a change to fundamentals of the crude loading out of the Baltics and the Black Sea has moved the grades in opposite directions over the past month.

The Urals CIF Rotterdam premium over Urals CIF Augusta stood at 3 cents/b Monday after trading at a discount to its Mediterranean counterpart since January 2015, S&P Global Platts data showed.

The change in the spread comes as a result of Urals CIF Rotterdam climbing to 2.5-year high Thursday and only reverting marginally since, while Urals CIF Augusta hit a one-month low Monday.

Over the past three weeks, the spread between the two grades weakened by $1.05/b, a magnitude not seen in the last two years.

The flip in the spread is largely seen as a result of a fundamental supply structure of Urals exports on the back of pipeline maintenance feeding Urals to the port of Primorsk.

The Sever pipeline network links Vtorovo-Yaroslavl-Kirishi-Primorsk and ships ultra low sulfur diesel from Russian refineries for export to Europe.

A number of pumping stations along the route are due for launch in the second half of this year, and one of the measures Transneft, the pipeline operator, has taken is to upgrade some of the current crude pipelines so that they can also be used for diesel transportation.

The second stage of the conversion project is due for completion in 2018.

The result of the upgrading and maintenance work is that crude exports out of the Baltics were down by some 244,887 b/d month on month in May, while exports out of the Black Sea were at their highest of the year at 555,077 b/d.

For the June program, some traders are expecting a further significant decrease in Baltic-loading crude exports, with one trader saying that "I would not be surprised to see a double-digit drop in Urals loadings out of Primorsk in June compared to May."

Trading sources said that the crude intended to be exported via Primorsk and Ust-Luga will now be sent via pipeline to Novorossiisk for export via the Black Sea, as well as larger volumes being shipped to Belarus after Russia and Belarus settled their gas pricing disputes earlier this year.

"Once the pipeline has been upgraded, volumes will be increasing again out of the Baltics, but there is an expectation in the market that supply fundamentals will change in the long run nevertheless as an overall larger amount of barrels exported from the Black Sea and less crude exported from the Baltics, compared to 2015 average values," a Urals trader said.

Market participants currently expect the pipeline upgrade to be done in August, while others said it could take until the end of the year.

However, the CIF Rotterdam premium above CIF Augusta is not widely expected to last for long.

"Urals CIF Rotterdam have ticked up a lot in recent days and I am wary there is much room for further increases. On the contrary, Urals CIF Augusta, at the current price level, should be capturing some of the West Mediterranean business, [which usually takes Urals from the Baltics] and that could exert some bearish force on Urals NWE and bullish pressure on Urals Med," a refiner sourcing Urals crude said.

https://www.platts.com/latest-news/oil/london/urals-cif-rotterdam-crude-oil-grade-at-premium-26731532

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Malaysia's state energy firm Petronas may try shorter-term LNG contracts and smaller cargo sizes to entice buyers, senior company officials said, at a time when it has major contracts coming up for renewal and the market is awash in supply.

The liquefied natural gas (LNG) marketing drive at Petroliam Nasional Berhad, or Petronas, coincides with rising production after the start-up of Train 9 at its Bintulu export terminal and its first floating LNG unit. Malaysia is the world's third-largest LNG exporter.

The global LNG market has become a buyers' market as growth in new supplies, mainly from Australia and the United States, exceeded demand and depressed prices. Asian spot LNG prices have dropped by more than 70 percent since 2014.

"New demand creation is becoming a norm," Ahmad Adly Alias, vice president of Petronas' LNG Trading & Marketing said at the Asia Oil & Gas Conference on Tuesday.

"We have recently restructured our organization to put a lot more focus on Middle East and South Asia... We've also set up a team to cover Southeast Asia," he said.

The company's upstream chief executive officer Mohd Anuar Taib told Reuters on Monday that it sees significant potential demand growth in India, Pakistan, Bangladesh and some parts of Southeast Asia.

In China, Petronas plans to work with a partner to sell smaller parcels to meet the demand of small buyers, Ahmad said.

Petronas is also exploring LNG sales as a transportation fuel for trucks and ships, the officials said.

CONTRACT NEGOTIATIONS

Producers, who used to sell their cargoes on long-term contracts, now have to become more flexible on selling terms, including allowing customers to swap contracted supplies and sell more cargoes in the spot market.

Petronas will soon start negotiating with customers in Japan, its biggest buyer, as some contracts are set to expire next year, with some even looking to reduce the volume of LNG they buy.

Japan's biggest utility Tokyo Electric Power Company has a contract to buy up to 4.8 million tonnes per year (tpy) of LNG, while Tokyo Gas Co's contract is for up to 2.6 million tpy. They both expire in March 2018.

"(Our) priority is to recontract in Malaysia but probably volume-wise it will be changed. And, how we can agree to new terms and conditions with better flexibility or pricing," said Shigeru Muraki, executive advisor at Tokyo Gas.

"We will compare with other sources, we will consider the diversification of supply sources or diversification of pricings."

Petronas' Ahmad said the company was currently working with long-term buyers to renew the contracts, but did not give details.

In the interview Monday, upstream CEO Anuar said long-term contracts have "almost become a novelty." Petronas could do both short- and long-term contracts, he said.

http://www.reuters.com/article/malaysia-petronas-lng-idUSL4N1IB2ID

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LNG Limited has announced that its wholly owned subsidiary, Magnolia LNG LLC, has received Notice to Proceed (NTP) from the Federal Energy Regulatory Commission (FERC) to begin initial site preparation activities for the Magnolia LNG project.

The project – based in the Port of Lake Charles, Louisiana, US – involves the construction and operation of up to four LNG production trains, each of which will have a capacity of 2 million tpy or more, utilising the OSMR® process technology. The project will also include two 160 000 m3 full containment storage tanks, ship, barge and truck loading facilities and loading infrastructure. The LSTK EPC contract includes all elements of the project required to bring the facility into full guaranteed production operations. Magnolia LNG is fully permitted – having received its FERC order and both FTA and non-FTA approval from the Department of Energy (DOE). A final investment decision (FID) and the initiation of construction is expected upon the execution of sufficient offtake agreements to support financing.

The Chief Operating Officer at Magnolia, John Baguley, said: “We are appreciative to FERC for the issuance of the NTP on our request for authorisation to commence initial site preparation activities. FERC’s comprehensive review of our submittals and concurrence that we have complied with Conditions for these initial activities as required under the April 15, 2016 FERC Order demonstrate the project’s readiness.”

The Managing Director and CEO of LNG Limited, Greg Vesey, added: “The FERC NTP for initial site preparation is a key milestone for the project and underscores our position as ‘Shovel Ready’. Nevertheless, the pacing item for our Final Investment Decision (FID) and initiation of construction for Magnolia remains the finalisation of our LNG offtake agreements, and our team remains fully engaged in advancing this activity.”

https://www.lngindustry.com/liquefaction/05052017/magnolia-lng-receives-ferc-approval-to-commence-site-preparation/

Japan's trade ministry on Monday reported success in producing gas last week by extracting methane gas from methane hydrate deposits offshore Japan's central coast.

The tests being run at two different wells are the first since 2013, when Japan achieved the world's first-ever extraction of gas from offshore deposits of methane hydrate, a frozen gas known as "flammable ice".

Japan's Ministry of Economy, Trade and Industry (METI) said the methane hydrate production tests will continue for a combined four to five weeks. Japan's first methane hydrate tests in 2013 ended abruptly after less than a week due to problems with sand flowing into the well.

Japan, which imports nearly all of its energy sources, has been aiming to launch private sector commercial production of methane hydrates by between 2023 to 2027, but METI officials have said the goal will still be a challenge as many obstacles remain to be solved.

Japan is the world's top importer of liquefied natural gas (LNG), and its need for domestic gas resources has become greater since the Fukushima nuclear crisis in 2011 shut down most of its nuclear power plants and sharply raised fossil fuel imports such as LNG and coal.

Methane hydrate is formed from a mixture of methane and water under certain pressures and conditions. India, Canada, the United States and China are among the countries also looking at exploiting hydrate deposits as an alternative source of energy, the trade ministry said.

A Japanese study has estimated that at least 40 trillion cubic feet (1.1 trillion cubic meters) of methane hydrates lie in the eastern Nankai Trough off the country's Pacific coast, equal to about 11 years of Japanese gas consumption.

http://in.reuters.com/article/japan-methane-hydrate-idINL4N1IA35A

Shell’s giant Prelude FLNG facility will come on stream offshore Western Australia next year, Chief Financial Officer Jessica Uhl said.

“Prelude remains on schedule… We’ve indicated that start-up was in 2018 and we remain confident in that timing,” Uhl told journalists on a conference call on May 4 after discussing the company’s first-quarter results.

The Hague-based LNG giant Shell has never been clear on when it expects to start producing chilled gas from the giant floating facility to be located at the Prelude gas field off Australia.

However, the company’s Chief Executive Ben van Beurden said at an event last year that Shell expects “real material cash from Prelude in 2018.”

Shell’s Prelude FLNG facility is the largest of its kind with 488m in length and 74m in width.

It is currently being built at Samsung Heavy Industries’ Geoje shipyard in South Korea, where an incident took place on May 1.

Six people died and more than 20 were injured when a crane collapsed during the construction of an oil platform for French energy company Total.

Uhl expressed condolences to everyone impacted by the “unfortunate incident”, adding that it did not have anything to do with Shell’s assets.

The incident is expected not to have any effect on the construction of the Prelude FLNG.

“The project itself is progressing well and the timeline for 2018 remains a good timeline,” she said.

The Prelude FLNG facility is expected to stay moored at the Prelude gas field for 25 years. It is designed to produce 3.6 mtpa of LNG, 1.3 mtpa of condensate and 0.4 mtpa of LPG for export.

 http://www.lngworldnews.com/shell-says-prelude-flng-to-start-production-in-2018/

Indonesian oil and gas major Pertamina is to sign an agreement with a portfolio seller by the end of 2017, for a swap of 0.7 million mt of LNG over five years from its contractual offtake commitment with US-based Cheniere, a senior official from Pertamina said Tuesday.

Pertamina is already in negotiations with the portfolio seller, Djohardi Angga Kusumah, Pertamina's gas and power senior vice president, said at the 19th Asia Oil and Conference in Kuala Lumpur, Malaysia.

The swap is to take place over the initial five years of Pertamina's contract with Cheniere, which expands over 20 years starting from 2018-2019, Kusumah added.

The volume is nearly half of its contractual commitment with Cheniere for the offtake of 1.52 million mt/year, including 0.76 million mt that is to be supplied from the Corpus Christi LNG plant in the US Gulf.

The agreement will be similar to another US LNG swaps deal Pertamina signed with France-based portfolio seller Total in February 2016, Kusumah said.

Under the agreement with Total, the French company will purchase from 2020 onwards around 0.4 million mt/year of Pertamina's contracted LNG volumes from Corpus Christi LNG in Texas, where operations at both trains are expected to begin in 2019.

In parallel, Total will supply from its global portfolio to Pertamina a volume growing over time from 0.4-1 million mt/year of LNG.

https://www.platts.com/latest-news/natural-gas/kualalumpur/indonesias-pertamina-to-swap-07-mil-mt-of-lng-27827748

Libya is pumping the most oil in more than two years as the OPEC member restores output amid progress in mending the nation’s political divisions. The increase adds pressure on the world’s biggest producers who just signaled they may extend production cuts amid a slump in oil.

The North African country’s production has reached 796,000 barrels a day, Mustafa Sanalla, the chairman of state producer National Oil Corp., said Monday in a statement. Libya was producing about 700,000 barrels a day at the end of April, Jadalla Alaokali, an NOC board member, said at the time.

A revival in Libyan output adds to the challenge that the Organization of Petroleum Exporting Countries and other major producers face after agreeing last year to pump less crude to stem a glut and shore up prices. In separate statements just hours apart on Monday, Saudi Arabia and Russia said publicly for the first time they would consider prolonging their output reductions for longer than the six-month extension OPEC is widely expected to agree to when the group meets on May 25. Libya was exempted from OPEC’s cuts because of its internal strife.

Political divisions, clashes between armed groups and closures of fields have disrupted output in Libya as the country with Africa’s largest crude reserves struggles to revive its most vital industry. Libya’s feuding administrations agreed last week to unite state institutions and build a national army under civilian leadership after two days of talks in Abu Dhabi.

Oil Recovery

Libya’s largest oil field, Sharara, is currently pumping about 225,000 barrels a day, according to a person familiar on Monday. The person asked not to be identified because they lack authorization to speak to the media. Crude from Sharara started flowing to the Zawiya refinery following a three-week closure.

El Feel, the oil field also known as Elephant, restarted last month as well, after having been halted since April 2015. The resumption of operations at Sharara and El Feel, both in western Libya, has helped lift total national output to the highest since October 2014, when the country pumped 850,000 barrels a day, data compiled by Bloomberg show.

Fighting in early March caused two of Libya’s main oil terminals to close, forcing a number of fields to stop pumping. The ports, along the central coast, have since reopened. Libya pumped as much as 1.6 million barrels a day before an uprising in 2011 led to a plunge in output, and it’s currently one of the smallest producers in OPEC.

Sharara has a capacity of 330,000 barrels a day and is operated by a joint venture between Libya’s NOC and Repsol SA, Total SA, OMV AG and Statoil ASA. El Feel, operated by a joint venture between the NOC and Eni SpA, can pump as much as 90,000 barrels a day.

The NOC will sell about 600,000 barrels of Mellitah blend crude from El Feel in a tender to be announced after mid-May, a person familiar with the situation said. The Mellitah sale will be the first since the field halted in 2015, the person said, asking not to be identified because they lack authority to speak to media.

https://www.bloomberg.com/news/articles/2017-05-08/libya-adds-to-opec-s-burden-as-output-reaches-highest-since-2014

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EOG Resources collected its first profit in nearly two years in the first quarter, wringing money from a revived oil patch amid higher energy prices, the company said Monday.

The Houston oil explorer pumped more oil than ever as it slashed the costs of bringing wells into production in Texas and North Dakota.

The company banked a $28.5 million profit, or 5 cents a share, in the first quarter, compared to a $471.8 million loss, or 86 cents a share, in the same period last year. It was EOG’s first profit since the second quarter of 2015. Revenue rose to $2.6 billion from $1.4 billion.

EOG lifted its oil production 18 percent to 315,700 barrels a day, thanks to technological breakthroughs and its shift to a strategy that focuses on pumping oil from only the most prolific fields.

Essentially, the company invests only in fields that will yield a 30-percent return at $40 a barrel oil. It said it expanded this so-called premium inventory of oil by 27 percent to 6.5 billion barrels of oil equivalent in the first quarter, through techniques including extending the length of horizontally drilled wells.

Over the past year, EOG said, it has cut the cost of turning on oil wells by 6 percent in the Eagle Ford Shale in South Texas, the Delaware Basin in West Texas and the Bakken Shale in North Dakota. Its lease and well expenses increased 4 percent because it sold off natural gas-rich, lower cost acreage.

http://fuelfix.com/blog/2017/05/08/eog-banks-first-profit-in-nearly-two-years-pumps-record-oil/

Northern anticipates more production growth in 2H 2017

Northern Oil and Gas, Inc. (ticker: NOG) reported total production of 1.2 million BOE for the first quarter, averaging 13,299 BOEPD.

Northern’s business model is as a non-operator franchise in the  Bakken and Three Forks plays in the Williston Basin of North Dakota and Montana.  Northern operates under a capital allocation model that calls for the company to acquire non-operated positions in high quality acreage about to be drilled, that provide for high internal rates of return on capital and to partner with leading E&P operators with a successful track record in the Williston Basin.

Northern’s GAAP net income for the first quarter of 2017 was $16.9 million.  Adjusted net income for the quarter was a loss of $0.1 million.  Adjusted EBITDA for the quarter was $29.6 million, the company reported.

Interim CEO and CFO Tom Stoelk said, “Increased well productivity is being aided by the enhanced completion designs, which is improving returns as we execute on our capital allocation focused business plan.  As the weather improves, an increase in completions is expected to drive production growth during the second half of 2017.”

Northern leased approximately 151,672 net acres targeting the Williston Basin Bakken and Three Forks formations.  As of March 31, 2017, approximately 84% of Northern’s North Dakota acreage position, and approximately 82% of Northern’s total acreage position was developed, held by production or held by operations.

Northern continues to expect 2017 total annual production to equal or modestly exceed 2016 total production.  Northern expects that it will add approximately 12 net wells to production during the year, based on a preliminary capital budget of $102.2 million (including acreage and development capital).  Net well additions will be weighted to the second half of 2017, which should result in sequential production growth in the third and fourth quarters. Management’s current expectations for 2017 operating metrics are as follows:

2017
Operating Expenses:
Production Expenses (per Boe)$9.00 – $9.30
Production Taxes (% of Oil & Gas Sales)10%
General and Administration Expense (per Boe)$3.00 – $3.50
Average Differential to NYMEX WTI $7.00 – $9.00

At March 31, 2017, Northern had $134.0 million in outstanding borrowings under its revolving credit facility, a $10 million reduction from December 31, 2016.  In May 2017, Northern completed the semi-annual redetermination under its revolving credit facility with the borrowing base established at $325 million.  Based on this new borrowing base, Northern had available liquidity of $196.5 million as of March 31, 2017, composed of $5.5 million in cash and $191.0 million of revolving credit facility availability.

https://www.oilandgas360.com/northern-oil-gas-enhanced-completions-generate-13-mboepd/

$750 Million CapEx split between Wattenberg and Delaware

Wattenberg producer PDC Energy (ticker: PDCE) reported first quarter results on May 5, showing net income of $46.1 million, or $0.70 per diluted share. This significantly outperforms the $71.5 million net loss in Q1 2016 or the $55.6 million loss in Q4 2016.

Average sale price up 73%

First quarter production was 6.65 MMBOE, an increase of 45.5% over the 4.57 MMBOE PDC produced in Q1 2016. The commodity price recovery makes this increase even more meaningful, as PDC’s weighted average sale price increased 73% from $16.49/BOE in Q1 2016 to $28.53/BOE in Q1 2017. The company expects to continue to grow at a rapid pace, with total production growing from the current average of 73.9 MBOEPD to 105 MBOEPD by the end of the year.

Next up: Delaware basin

PDC will devote considerable spending to developing its newly acquired Delaware basin properties, spending $290 million out of a total budget of $750 million. The company now owns 62,500 net acres in the Delaware, where it is operating three rigs currently. In total, PDC expects to spud 31 wells in the Delaware this year, primarily in the Eastern portion of its acreage. While most of PDC’s wells in the Delaware have only been active for a short period, preliminary results show several wells outperforming the acquisition type curve.

PDC owns 95,500 acres in the Wattenberg, and plans to spend $465 million developing this asset this year. The company will spud 139 wells in the play this year, with an average lateral length of 6,800’.the company’s extended reach lateral wells, wells with lateral lengths around 9,500’, are outperforming the 1.1 MMBOE type curve in recent development. PDC reports that these XRL wells cost $4.5 million and have significantly over 100% IRRs.

Midstream capacity in the Wattenberg continues to increase for both oil and gas, with about 440 MMcf/d of expansions expected by mid-year 2019. Current planned construction of oil processing is expected to be more than sufficient through at least 2020.

https://www.oilandgas360.com/pdc-targets-42-production-growth-2017/

Genscape: Cushing +582k w/w.

@zerohedge

Construction of the offshore section of the TurkStream gas pipeline to send Russian gas to Turkey began on Sunday, project operator Gazprom said in a statement Monday.

The project -- which will consist of two 15.75 Bcm/year pipelines -- is designed to offer a new transit route for Russian gas to Turkey and Europe, bypassing the traditional Ukraine transit corridor.

One of the lines will serve the domestic Turkish market, while the other is planned to link in with other planned pipeline infrastructure to southern Europe.

Both are expected to be operational by the end of 2019.

"Today we have started the practical stage of the project -- the subsea laying of the gas pipeline," Gazprom CEO Alexei Miller said.

"The project is implemented strictly according to plan and by the end of 2019 our Turkish and European consumers will receive a new reliable route for the import of Russian gas," he said.

The laying of the pipeline is being carried out by Allseas, the contractor for both lines of the offshore link.

https://www.platts.com/latest-news/natural-gas/amsterdam/construction-of-subsea-section-of-turkstream-26730439

Iran plans to raise its crude production capacity by 3 million b/d, oil ministry news agency Shana quoted a senior official as saying Monday.

Speaking on the sidelines of a petroleum exhibition in Iran, National Iranian Oil Co.'s deputy head for engineering and development, Gholam-Reza Manouchehri, said the aim of boosting the country's output capacity by such a substantial amount would be to promote and stabilize its footing in OPEC and the global market, Shana reported.

The agency did not mention any target date envisioned for the increase.

It also reported Manouchehri as saying that NIOC for considering signing $80 billion of deals with domestic and international contractors within the next two years.

Following the lifting of international nuclear sanctions on Iran in January 2016, NIOC has so far signed 24 memoranda of understanding with domestic and international companies seeking to join oil and gas development projects in the country, including a recent MOU with Philippine National Oil Co. for studies of Iran's Pazanan and Darkhowin oil fields, he said.

Iran produced 3.77 million b/d of crude in April, the latest S&P Global Platts survey of OPEC production shows.

Manouchehri made his remarks as Iranian president Hassan Rouhani campaigns for re-election in voting scheduled for May 19.

The NIOC official was promoted in April 2016 to his current position, as head of what was then a newly formed division of the national oil company, in a surprise move by Iran's oil minister Bijan Zanganeh.

https://www.platts.com/latest-news/oil/dubai/irans-nioc-plans-to-boost-crude-oil-output-capacity-26730426

Russia's exports of the medium sweet ESPO crude blend in June are set to fall 17.2% from May to 2.4 million mt, according to the latest monthly loading program seen by S&P Global Platts.

The June loading program runs from May 30 to June 30 and will comprise a total of 24 cargoes of 100,000 mt each, according to the program.

In comparison, ESPO exports in May totaled 2.9 million mt, which comprised 29 cargoes of 100,000 mt each.

The loading rate for ESPO exports will average around 547,500 b/d in June, down from 622,647 b/d scheduled for May.

The June program showed state-owned Rosneft holding 10 cargoes, Russia's Surgutneftegaz with seven, Swiss-based Tenergy holds six cargoes and Lukoil a single cargo for June.

Traders have attributed the shorter program for ESPO Blend crude in June to a field maintenance, although further details were unclear.

The lower volumes has helped provide a bit of support for ESPO Blend crude premiums for June-loading cargoes, traders said.

June-loading ESPO Blend crude cargoes have traded at premiums ranging between $1.25/b and $1.50/b to the Platts front-month Dubai crude assessments, slightly up from premiums of closer to $1/b towards the end of the trading cycle for May-loading cargoes.

Surgutneftegaz was most recently heard to have sold its tender for five cargoes of ESPO Blend crude at premiums of $1.20-$1.35/b to the Platts front-month Dubai crude assessments on FOB basis.

The cargoes, for loading over June 10-14, June 14-18 and June 23-27, were heard sold to JXTG, an unnamed trader, and ChemChina. Two cargoes, for loading over June 17-21 and June 19-23, were heard sold to Unipec.

Platts last assessed the second-month ESPO Blend crude at a premium of $1.35/b to Dubai on Friday.

Last week, Russia's energy minister Alexander Novak was quoted by local media as saying that the country has exceeded its obligation under the OPEC deal, having reduced production by 300,790 b/d.

Under the deal, Russia committed to gradually reducing its production to reach 300,000 b/d in cuts by May and stay at that level till the deal's expiry.

Russia is inclined to extend the OPEC/non-OPEC crude output cut deal beyond mid-year, which it sees necessary for the full recovery of the oil market, Novak said.

OPEC, as a whole, committed to cutting production by 1.2 million b/d from October 2016's levels, with several major non-OPEC producers, led by Russia, agreeing to cut 558,000 b/d.

The group will gather in Vienna on May 25 to decide on the potential extension of the output cuts.

https://www.platts.com/latest-news/oil/singapore/russias-june-exports-of-espo-crude-oil-to-dip-26730427

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BP and joint venture partner Kosmos Energy revealed a major gas discovery off Senegal on Monday, adding to other recent finds off the West African coast.

Oil majors including BP and Total are investing in the waters of Senegal and Mauritania in the hope of repeating the recent exploration success of smaller players.

"Yakaar-1...further confirms our belief that offshore Senegal and Mauritania is a world-class hydrocarbon basin," Bernard Looney, BP Upstream chief executive officer, said.

New York-listed Kosmos in 2015 discovered a gas pool in the Tortue 1 exploration well, part of the Greater Tortue Complex spanning Senegal and Mauritania, which contained more than 15 trillion cubic feet of gas.

Since then, BP has formulated plans to acquire a 30 percent interest in the two offshore blocks called Saint-Louis Profond that includes the Senegalese sector of the Tortue field and Cayar Profond. BP has also agreed to buy a stake of close to 60 percent in Kosmos' Mauritania exploration blocks.

Gas from the Tortue field is due to begin flowing in 2021 and is set to be exported from a liquefied natural gas (LNG) facility. The two firms said on Thursday that the Yakaar-1 find contained sufficient reserves to warrant another LNG project.

Kosmos spokesman Thomas Golembeski, declined to give further details on the nature or timing of the project, adding that further appraisal work was planned.

http://www.reuters.com/article/us-senegal-oil-idUSKBN1841H5

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Tokyo Gas said that through its unit, Tokyo Gas America, it has purchased a 30 percent equity in Castleton Resources, a company focused on developing oil and gas assets in east Texas and Louisiana.

Castleton Resources, a unit of Castleton Commodities International, focuses on developing the unconventional Haynesville assets.

The company owns and operates over 160,000 net acres of leasehold in East Texas with access to the Cotton Valley and Haynesville shale and has a net production of 238 mmcfepd, Tokyo Gas said.

Speaking of the acquisition, Craig Jarchow, president and CEO of Castleton Resources, said the company will remain “focused on optimizing and growing” its upstream and midstream assets in the region.

Speaking to reporters, Tokyo Gas’ senior general manager of global business development, Isao Hosoya, said that, although the acquisition will allow Tokyo Gas to expand its business in the natural gas value chain, it does not plan to realise an LNG project through the joint venture, Reuters reports.

http://www.lngworldnews.com/tokyo-gas-invests-in-u-s-shale-player-castleton-resources/

Hurricane Energy, which specialises in extracting oil from naturally fractured rock, said on Monday the amount of oil estimated to be recoverable from its Lancaster field in the North Sea is 162 percent higher than previously thought.

The company said the latest independent analysis of reserves at the field showed 523 million barrels of oil could be recoverable, more than double the amount assessed in 2013.

The total volume of oil in place at the field was put at 2.3 billion barrels, up 120 percent from the 2013 report, Hurricane said.

"We believe this has the scale to attract interest from major oil companies," said analysts at RBC Capital Markets.

North Sea oil and gas production levels have slumped from a peak around the turn of the century and a three-year oil market downturn has curbed exploration for new resources.

However a series of small oil explorers deploying new techniques to retrieve hydrocarbons at lower costs and more efficiently, including Hurricane, have revived hopes that Britain's remaining 24 billion barrels can be retrieved.

Hurricane said 37.3 million barrels of proven reserves (2P) at Lancaster were worth $525 million.

"We expect to publish CPRs (Competent Person's Report) relating to Halifax and Lincoln later in 2017, which we are confident will be a material addition to our already significant resource base," Hurricane Chief Executive Robert Trice said.

In March, Hurricane said its Halifax oil discovery, extending into its Lancaster field, was the largest undeveloped discovery on the UK Continental Shelf.

http://www.reuters.com/article/hurricane-oil-north-sea-idUSL8N1IA1KG

One of the factors behind the recent slump in crude oil prices may be the realisation among market participants that there is a difference between production cuts and export flows.

While OPEC and its allies appear to have been relatively successful in implementing their planned output cuts of 1.8 million barrels per day (bpd), this has yet to show up in a meaningful way in the amount of crude oil being transported by ships.

The seeming easy availability of crude despite the output cuts helped drive crude prices lower, with Brent dropping as low as $46.64 a barrel on May 5, just above the close of $46.38 on Nov. 29, the day before OPEC and its allies announced the deal to trim production and down about 20 percent since its recent peak in early January.

The 11 members of the Organization of the Petroleum Exporting Countries that agreed last November to restrict output by 1.2 million bpd for the first six months of 2017 achieved 90 percent compliance in April, according to a Reuters survey.

Output by the 11 countries was 29.92 million bpd in April, up fractionally from 29.9 million in March and only about 116,000 bpd above the agreed target.

The non-OPEC countries that agreed to curb their output by a combined 600,000 bpd also largely claim to be compliant, with major producer Russia saying it has exceeded the 300,000 bpd it agreed to cut as part of the deal aimed at boosting oil prices.

Top OPEC producer Saudi Arabia and Russia appear to be in favour of extending the agreement for another six months, a move that is likely to be confirmed when OPEC and its allies meet on May 25.

Ultimately the output cut is supposed to tighten the oil market by reducing supplies and draining inventories.

The problem is assessing how successful OPEC and the other producers are being in this endeavour.

One method is to look at vessel-tracking data as an indicator of physical flows.

While ship data doesn't capture oil moved by pipeline, it still represents more than half of the global market and is therefore a useful indicator.

The broadest measure of the data captures all movement by tankers, including domestic voyages and ship-to-ship transfers, and provides a universal picture of the amount of crude moving around the world.

In April this totalled 45.23 million bpd, down from March's 46.4 million bpd and February's 46.2 million bpd, but up from January's 44.3 million bpd, according to Thomson Reuters' Eikon vessel-tracking and port data.

For the first four months of the year, the average was 45.5 million bpd, which was actually higher than the 45.1 million bpd in the last four months of 2016.

While this wide measure of data does show that there is no shortage of oil being shipped around the globe, it doesn't say how much of this is new production being exported or inventories being drawn down.

OPEC EXPORTS DOWN

To gain a clearer picture of how much OPEC is actually exporting, the data can be filtered to show only vessels that have discharged their cargoes, are in the process of discharging, or are underway to their destination.

On this basis, OPEC members exported 24.7 million bpd in April, down from 25.6 million bpd in March and 26.4 million bpd in February, and level with January's exports. This is only tanker exports, and doesn't count any pipeline movements.

For the first four months of 2017, OPEC exports by tanker averaged 25.4 million bpd, down from 26.1 million bpd for the preceding four months.

This represents a drop of 700,000 bpd, which is below the pledged output cut of 1.2 million bpd, suggesting that OPEC members may have been drawing down internal inventories in recent months.

But it's also worth noting that the reduction in exports by OPEC doesn't appear to have resulted in less oil moving by tanker, meaning the shortfall has been made up by producers outside the agreement pumping more crude, or by inventories being drawn down.

The question of inventories emerges as the key factor for the success of the deal between OPEC and its allies.

If global crude flows by tanker were higher in the first four months of this year compared to the preceding four months because of producers outside the agreement pumping more, this is bearish for OPEC and shows the group has considerably more to do in order to boost the price.

On the other hand, if global crude flows were being bolstered by inventories being drawn down as market participants feared the market was heading for backwardation, then this may be bullish over the medium to longer term for OPEC's aim of increasing the price.

This makes inventory levels key to the outlook for prices, and this is an area with incomplete global data.

While detailed information is available for many developed countries, data is patchy or non-existent for much of the developing world.

But what is known is that U.S. crude inventories fell by a smaller than expected 930,000 barrels last week to 527.8 million barrels, but they are also 3 percent higher than a year ago.

OPEC said on April 12 that inventories in OECD nations dropped in February, but were still 268 million barrels above the five-year average.

This suggests that OPEC and its allies still have a long road to travel to drain inventories, and that the market may not re-balance as quickly as they would prefer

http://www.reuters.com/article/column-russell-crude-opec-idUSL4N1IA2B7

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Nigeria has almost tripled the budget for an amnesty program for militants in its oil-producing heartland, the presidency said on Saturday, a key factor in maintaining a tenuous peace in the Niger Delta and supporting crude production.

An additional 30 billion naira ($98.47 million) would be released for the former militants and an extra 5 billion naira added at some later stage, the presidency said in a statement. Until 2016 the annual budget was 20 billion naira.

Funding of former militants under the 2009 amnesty is key to maintaining the relative stability in the Delta and stopping attacks on oil facilities, as it was last year by militants who cut crude output by as much as a third.

Under the amnesty program, each former militant is entitled to 65,000 naira a month plus job training. But in March a special adviser to Nigeria's president said the program was facing a cash crunch.

"Currently the Amnesty Office has now paid up all ex-militants backlog of their stipends up to the end of 2016," the presidency said in a statement.

Authorities had previously cut the budget for cash payments to militants to end corruption. They later resumed payments to keep pipeline attacks from crippling vital oil revenues.

Last month, former militant leaders in the Niger Delta urged the government to pay out delayed amnesty stipends or face protests.

The government has been holding talks with militants to end the attacks that cut Nigeria's output by 700,000 barrels a day (bpd) for several months last year, reducing total production at that time to about 1.2 million bpd. It has since rebounded.

The presidency also said all promises made by Vice President Yemi Osinbajo on recent visits of the Niger Delta to boost development would be kept.

The damage from attacks on Nigeria's oil industry has exacerbated a downturn in Africa's largest economy, which slipped into recession in 2016 for the first time in 25 years, largely due to low oil prices.

Crude oil sales make up around two-thirds of government revenue.

Gas producer ExxonMobil has highlighted the opportunity for further investment in the Bass Strait, on the back of completing it’s A$5.5-billion Kipper Tuna Turrum development.

ExxonMobil Australia over the weekend unveiled the completion of its Longford gas conditioning plant, which will process gas from the Kipper Tuna Turrum development, supplying some 1.6-trillion cubic feet of gas to eastern Australia.

“The gas conditioning plant helps maintain current gas supply levels from Bass Strait, which has been producing for more than 40 years and providing energy to power the economy,” said ExxonMobil Australia chairperson Richard Owen.

“This project is breathing new life into Bass Strait, and allowing us to continue what’s been a tremendous record of providing domestic gas to south eastern Australia,” Owen said.

“We’re hoping this is just the start of being able to develop further resources in Bass Strait and essentially create Bass Strait 2.0. We recognise the significant amount of effort that has gone into the project, not just in terms of construction effort, but also the effort from technical, operations and maintenance side.  We have a tremendous workforce here who have done great job in completing a complex project.”

http://www.miningweekly.com/article/exxonmobil-weighing-further-investment-in-bass-strait-2017-05-08

Whatever the election result, South Korea is likely to see a boost in LNG imports at the expense of coal-fired and nuclear power generation capacity as major candidates' top pledges remain focused on addressing public concerns over worsening air pollution.

Fine dust pollution has emerged as a key issue in the presidential election, set for May 9, to replace former President Park Geun-hye, who was impeached in March over a corruption scandal involving large family-run business conglomerates, or chaebol.

All three main candidates have pledged to reduce coal-fired and nuclear power capacity to address the country's public health concerns, and instead increase gas-fired power production and renewable energy resources to offset the supply shortfall.

The candidates' pledges come at a time when South Korea has been increasingly hit by higher concentrations of fine dust in the air.

South Korea runs more than 50 coal-fired power plants that supply about 40% of the country's total electricity, followed by nuclear (30%), LNG (25%), oil (3%), and renewable sources such as hydropower, solar, wind and fuel cells (2%).

Front-runner Moon Jae-In has unveiled the strongest measures among the major candidates, having promised to reverse the country's existing plans to build new coal-fired power plants and nuclear reactors, with the goal of reducing fine dust pollution by 30%.

Following years of stagnant LNG demand growth, Platts Analytics forecasts South Korea's consumption to see steady growth from 2019 onwards, reaching 37.3 million mt by 2022, although still below the record 39 million mt imported in 2013.

SILENT ON OVERSEAS DEVELOPMENT

But the presidential candidates have stopped short of unveiling policies on the country's overseas oil and gas development, as their state expenditure plans are heavily focused on welfare programs and national defense in the wake of mounting nuclear threats from North Korea.

In addition, state-run developers such as Korea National Oil Corp. and Kora Gas Corp., which have in the past led the country's upstream projects, are now under great pressure to reduce heavy debts after an asset shopping spree when oil prices were high.

They are now seeking to divest some assets, but facing hurdles due to the slump in oil prices since late 2014.

With public attention focused on welfare and North Korea, oil and gas development has been sidelined in the presidential election campaign, with analysts warning about the lack of a long-term energy policy and energy supply troubles.

This is particularly important for South Korea, which has to import almost all its energy requirements from overseas. South Korea is the world's fifth-largest crude oil buyer and second-largest LNG buyer.

"Consistent efforts for oil and gas asset acquisition are necessary for South Korea, which is vulnerable to price volatility," said Sonn Yang-Hoon, a prominent energy expert at Incheon University, west of Seoul.

"A fundamental shift is underway in the global energy market following the oil price slump since 2014, which offers opportunities to import-dependent South Korea. Whoever becomes the next president is urged to use the changing market to boost its energy security," he said.

Below are the candidates' key energy policies:

MOON JAE-IN

The 64-year-old former human rights lawyer represents the progressive opposition Democratic Party, the biggest party, with 121 seats in the 300-seat National Assembly.
Maintains a strong lead with a support rating of about 40%, according to recent public surveys.
Says he will shut aged coal-fired power plants and scrap plans for nine coal-fired power plants where construction is less than 10% complete.
Vows to close down the aged Wolsong-1 nuclear reactor and halt construction of two large nuclear reactors, Shin Kori 5 and 6.
Vows to take measures to replace aged gasoil-powered vehicles, considered another cause of fine dust emissions, with electric vehicles and those powered by compressed natural gas and LPG, which could affect the country's demand for auto fuels.

AHN CHEOL-SOO

Former medical doctor and software mogul represents the People's Party. Latest public surveys peg his support rating at 20%.
Has promised to scale back electricity production from coal-fired power plants and nuclear reactors and replace them with LNG and renewables.
Aims to increase the ratio of renewables in the country's electricity mix from the current 1.1% to 20% by 2030 and use LNG as a bridge to clean renewables.

HONG JOON-PYO

Represents the Liberty Korea Party and has a support rating of 15%, according to recent public surveys.
Vows to scrap plans for new coal-power plants and nuclear reactors.
Promises to lower taxes on oil products by up to 50% as part of efforts to boost sagging domestic consumption. Lower taxes, which account for half of retail oil prices, could boost South Korea's oil demand, which has been on the decline due to rising domestic prices and slow economic growth.

https://www.platts.com/latest-news/natural-gas/seoul/analysis-south-korea-headed-for-lng-import-boost-27826809

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May 8 China's crude oil imports during the January to April period this year gained 12.5 percent over a year earlier to 139 million tonnes, Chinese customs said on Monday.

Natural gas imports during the same period were up 5.4 percent from a year ago to 20.11 million tonnes, the customs said.

http://www.reuters.com/article/china-economy-trade-crude-idUSB9N1HZ01T

China’s April Crude Oil Imports -11.71% M/m to 34.39m Tons

@zerohedge

Saudi Arabia’s oil minister said he’s confident that an agreement by producers to curb crude output and shrink a market glut will be extended into the second half of the year and possibly beyond.

While U.S. shale output growth and the shutdown of refineries for maintenance have slowed the impact of cuts by OPEC and its partners, producers are determined to reach their goal of reducing bloated stockpiles, Khalid Al-Falih said at the Asia Oil and Gas Conference in Kuala Lumpur on Monday. He said he’s confident the global oil market will soon rebalance and return to a “healthy state.”

Surging U.S. production has raised concern the Organization of Petroleum Exporting Countries and partners are failing to reduce an oversupply and prop up prices. Oil has surrendered all its gains since their deal late last year to cut output and with OPEC meeting in Vienna later this month, several nations have said they’d support an extension of the 6-month agreement that began in January. This is the first time the Saudi minister has suggested it could be extended beyond 2017.

“Based on the consultations I have had with participating members I am rather confident the agreement will be extended into the second half of the year and possibly beyond,” Al-Falih said. “The producer coalition is determined to do whatever it takes to achieve our target of bringing stock levels back to the five-year average.”

West Texas Intermediate crude rose 1.2 percent to $46.76 a barrel by 12:20 p.m. Singapore time on the New York Mercantile Exchange. Brent, the benchmark for more than half the world’s oil, was up 1.3 percent to $49.73 a barrel on the London-based ICE Futures Europe exchange. Both are still more than 50 percent below their peaks in 2014, when the U.S. shale boom exacerbated a market glut and triggered the biggest price crash in a generation.

Al-Falih said last month that OPEC and its partners have failed, after three months of limiting output, to achieve their target of reducing oil inventories below the five-year historical average. Group member United Arab Emirates said earlier in May that the producer group should extend the collective production cuts into the second half of the year when an expected upturn in demand will help to re-balance the crude market.

Vienna Meeting

Russia, which is not member of OPEC but is part of the deal, also thinks it will be necessary to extend the reduction deal, according to Energy Minister Alexander Novak. The producers agreed last year to curb output by as much as 1.8 million barrels a day starting January. OPEC will meet in Vienna on May 25 to decide whether to prolong the deal beyond June.

While the producers curbed supply, production in the U.S., which is not part of the agreement, has risen to the highest level since August 2015 as drillers pump more from shale fields. But American crude inventories are showing some signs of shrinking, falling for the past four weeks from record levels at the end of March.

Despite lingering headwinds, the oil market is improving from early last year when markets were at a low, Al-Falih said. Stockpiles at sea have declined and U.S. inventories will continue their downward trend, he said. Global demand, meanwhile, will probably be stable from the “healthy rate” seen last year, driven by China and India, the Saudi minister said, adding that Asia was the most important market.

There’s about 20 million barrels a day of combined demand growth and natural oil-field output declines that need to be offset, Al-Falih said. “No matter how fast U.S. shale grows, it wont make a dent in that number,” he said.

https://www.bloomberg.com/news/articles/2017-05-08/saudi-oil-minister-says-output-cuts-may-extend-beyond-2h-of-2017

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The number of offshore drilling rigs operating in the U.S. waters has climbed this week by two units when compared to the previous week, Baker Hughes reported in its U.S. weekly rig count report.

BHI Rig Count: U.S. +7 to 877 rigs

http://www.offshoreenergytoday.com/weekly-u-s-offshore-rig-count-climbs-to-19-units/

Drilling activity in the U.S. has increased yet again, with Baker Hughes weekly rig count reporting seven additional rigs this week. The total number of rigs active in the U.S. is now 877, more than double the 415 rigs that were operating this time last year.

Oil-targeting rigs increased by six this week, totaling 703 rigs. Gas-targeting rigs added two to end the week with 173 active rigs. One “miscellaneous” rig came offline, leaving only one miscellaneous rig active in the U.S.

Four directional and horizontal rigs came online this week, while one vertical rig shut down. Drilling offshore increased, with one “inland waters” and two offshore rigs coming online this week.

Texas again saw the largest increase in rigs, with six added this week bringing its total to 443. Louisiana added four rigs, while Wyoming and Alaska each added two and Colorado and New Mexico each added one. Seven rigs shut down in Oklahoma, and North Dakota and West Virginia both had one rig go offline.

Permian, minor basins add rigs

Rigs moved away from major basins, with only the Permian and the Haynesville adding rigs. Seven additional rigs in the Permian and one more in the Haynesville were offset by four shutdowns in the Cana Woodford, three Marcellus rigs coming offline, and one less in the Ardmore Woodford, Arkoma Woodford, Mississippian and Williston. Ten rigs moved to basins not individually tracked by Baker Hughes.

Canadian rigs continued to decrease, albeit at a slower pace than previous weeks. Three rigs shut down in Canada this week, leaving 82 active. Rigs in Canada have fallen by 77% from a high of 352 in February. This is the standard spring decrease, as seen every year. Historically, the spring drop usually begins to reverse in early May, so Canadian rigs may begin to recover soon.

https://www.oilandgas360.com/u-s-rig-count-climbs-sixteenth-straight-week/

“It will get to a point where it’s actually artificial intelligence that’s drilling our wells for us, with us observing” – Tim Dove, CEO, Pioneer Natural Resources

There are a lot of smart E&P companies rambling around West Texas, the place that has dominated the energy spotlight for the past year or two. Ask anybody who’s been looking at shale: it’s all about the Permian basin.

The basin is booming. It’s crushing most of the others in production numbers, dollars being paid per acre to enter, ability to offer significant stacked pay and strong economics with oil in the $40s-$50. But fast growth comes with plenty of headaches. How are these operators viewing and solving problems they have in common as they step on the Permian accelerator?

Analysts burned up the phone lines on this week’s Q1 earnings calls, asking a lot of questions that brought out sometimes startling viewpoints from some of the top E&P CEOs whose companies are smashing records in the too-hot-to-touch Permian.

How will you source water in the Permian?

Pioneer Natural Resources (ticker: PXD) President and CEO Tim Dove

Q – Jeffrey L. Campbell: On water investment, while the cost savings certainly shouldn’t be ignored, isn’t it fair to see your water effort as necessary to secure supply for future growth? In other words, that it’s an important exercise in risk management?

A – Timothy L. Dove: Well let me put it this way: Water is perhaps the most misunderstood and undervalued aspect of the impediments that the industry could face. As Joey said, when we are today sourcing 350,000 barrels a day, if nothing changes to how we do things, 10 years from now that’s 1.4 million barrels a day. Today we represent 8% of the Permian rig count. So when you start doing the math, you realize, oh my gosh, we’re in a difficult situation to be able to source that kind of water. Which means we’re going to have to go, as I mentioned, more towards the recycling of produced water that also comes back to us after the frac. And so that has to be in our thoughts long term. But I think being ahead of this is tantamount to substantial risk avoidance going forward. We are just not going to be put in a position where we have that kind of impediment that’s unsolvable. We’re solving it ourselves.

WPX Energy (ticker: WPX) Sr. VP and Chief Operating Officer Clay Gaspar, Sr. VP Business Development Bryan Guderian

Kashy Harrison: So, can you update us on just what the A&D market looks like right now in the Delaware for – specifically for acreage swaps to help you build a more contiguous acreage position in the region?

A – Bryan K. Guderian: Sure. I think I’d just start out by saying the availability of acreage for transaction continues to surprise us. The buy-side resilience, I think, continues to surprise us as well. So, near-term, our focus is really what we would call kind of blocking and tackling. We have our footprint in place. We’re really nicely blocked up in Stateline and some of the nearby areas there. We have some other acreage that is a little bit more one-off, but we see really nice opportunities dealing with probably four or five different trading partners in and around Stateline, and in particular, the northern part of the Texas side of our position. And we’ve had some great success already dealing with those folks to block up and drill longer laterals.

Kind of along those lines, we are also finding that there is still some additional acreage, generally smaller tracts, some expirations, still opportunity to bolt-on and add to those positions in small ways. The same is probably true up in New Mexico, although I would say that, given the Federal lands and some of the larger tracts that we deal with in New Mexico that has not been as much of a focus for us recently.

Looking more broadly across the basin, there are a number of fairly sizeable deals that are in the market currently or that we expect to come to market. I’m going to say that they tend to be a little more fringy. There are a couple of deals over in the eastern side of the basin that we would anticipate being marketed this year. I won’t go into names because I don’t know the exact status of those, but likewise still I think some opportunities over on the west side of the basin and obviously we took advantage of one with our Taylor Ranch acquisition.

And then, I would expect to continue seeing some private equity monetization. I think we all realize, we’re probably in the seventh or eighth inning of that process, but, again, the availability of acreage as much as we think we know about the basin, things continue to come to market, but more in small packages at this point.

And I think back to sort of the theme of our story, we’re going to stick to our knitting. We really like the footprint that we have. And so, our primary objective is bolting on and adding efficiency to the position that we already have.

Concho Resources (ticker: CXO) Chairman of the Board, Chief Executive Officer and President Tim Leach

Concho Resources Permian basin acreage

Q – Brian Singer: There have been a couple of acquisitions of assets that would seemingly show up on your maps in Lea and Eddy County. And as a company that’s been very, very active in consolidation, I wonder if you could just talk about your interest in consolidation and why maybe sometimes it does or doesn’t make sense for operators that have acreage in the region to be consolidated in that acreage versus new entrants?

A – Timothy A. Leach: All right. Well, as we’ve highlighted, having big, blocky acreage positions with high ownership is very important to development. So I think you’ll see a lot of trading going on between the big operators to block up their acreage.

When things come up for sale, we have a very high bar on since we have so much opportunity. Things that are contiguous to properties we already own, things that allow us to extend our lateral length are much more valuable to us than kind of scattershot acreage. And also, I’d say with the inventory we have today, it depends on what price you have to pay to get acreage and whether or not we’d be interested in it. So, we’re in a good position to evaluate does making acquisitions add value to our company. And we are very, very focused on these big, blocky, machine-like development projects we’re going to have in the future and making sure that we have all the blocky acreage we need for those things. So, I think we’re in good shape.

As we’ve said in the past, we look at everything in the Permian Basin because it’s our backyard. And so, it’s not unusual for us to be in data rooms and things like that, but we’ve been very picky on what makes sense for us to buy.

https://www.oilandgas360.com/permian-thought-leaders-talk-turkey/

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The energy industry scrutinizes U.S. oil stockpile data every week for evidence that OPEC supply cuts are ending a global crude glut, but growing domestic output means the world's largest oil consumer may be the last place to feel the cuts.

Stubbornly high U.S. inventory levels have shaken market confidence that a deal by the Organization of the Petroleum Exporting Countries (OPEC), Russia and other top producers to cut 1.8 million barrels per day (bpd) from supply will end the two-year glut.

This week, benchmark Brent crude prices slipped below $50 a barrel. Brent has given up all the gains made since the supply cuts were agreed late last year. [O/R]

U.S. inventories are a trusted barometer for the health of global oil markets because of the transparency of the data and their location in the country that consumes around a fifth of the world's oil.

But U.S. crude inventories have only grown since the supply cuts took effect. The initial spike in oil prices after the deal reinforced already resurgent production from the U.S. shale industry.

The rush back into the fields boosted U.S. shale output to an estimated 5.2 million bpd in May from 4.5 million at the end of 2016. The increase of 700,000 bpd in U.S. supply has replaced much of the output cuts delivered under the OPEC-led agreement.

Offshore production in the Gulf of Mexico has also hit a record, bringing total U.S. output to 9.3 million barrels a day, its highest since August 2015.

That has helped keep U.S. stockpiles full.

"As long as U.S. producers are able to pump oil at a profit then the rebalancing in the U.S. is going to take time," said Mark Watkins, regional investment manager at U.S. Bank.

"It's going to be an extended period of time still. I would look to at least the end of the year."

In addition, producer countries that pumped a lot of their own oil into storage at home have recently been exporting from those tanks to consumer countries such as the United States.

OPEC members typically do not disclose their stock levels. So even though the export of stored oil is part of the effort to draw down global inventories, it also has pushed previously invisible inventories into global storage data.

Those OPEC shipments may now be easing. Thomson Reuters shipping data shows crude exports from the group dropped from March to April by about 50 million barrels to 741.2 million barrels.

U.S. STOCKPILES RISE

U.S. crude inventories hit records earlier this year, and remain up 10 percent since the OPEC-led supply cuts took effect on Jan. 1.

U.S. crude stocks stand at 527.8 million barrels, nearly 30 percent higher than the average of the past five years, according to government data.

Exports from the United States have been steadily rising and have also regularly reached records this year. If markets tighten elsewhere, U.S. exports will increase and this should drain domestic inventories more quickly.

"What you're going to have to see is global supply across the world drop and U.S. crude ship out before you start to see a meaningful drop in U.S. inventories," said Watkins.

"And that's something that's started a little bit, but it's pretty marginal."

Despite the high domestic output, there are some signs that efforts to reduce the global glut may be having an impact in the United States.

A recent four-week run of U.S. inventory draws has been larger than the 2011-2016 average for this time of year, said Credit Suisse in a note on Friday.

IMPACT ELSEWHERE

More tangible impacts on inventories can be seen elsewhere, some analysts said; inventories simply need more time to return to average levels.

There have been some signs of drawdowns in global inventories, particularly in floating storage, when oil is stored in a tanker anchored offshore. According to Clipperdata this type of storage has been falling near the refining hub of Singapore.

Singapore "acts as such a parking lot for tankers and should we see Singapore floating storage be drawn down materially that would indicate that the market is tightening," said Matt Smith, director of commodity research at Clipperdata.

Clipperdata estimates that 50 million barrels are floating off Singapore, down sharply from February's peak of 64 million barrels, which was the highest point in at least a year.

"The lack of visible stock declines ... undermined oil market confidence and dragged markets lower," said oil consultants PIRA Energy in a note this week.

"Market jitters are unwarranted; oil on the water is declining, OPEC output is declining and stocks are declining. Onshore stock declines are inevitable, but the exact timing is tricky."

Great Scott! Eclipse Drills New Longest Lateral in World – in Utica

Eclipse Resources, a Marcellus/Utica pure play driller headquartered in State College, PA that drills mostly in Ohio, has done it again. Yesterday as part of Eclipse’s first quarter 2017 update, the company announced it has broken its own record for drilling the longest land-based lateral well in the world by drilling a Utica well with a lateral that’s 19,300 feet long (3.7 miles). Incredible!

You may recall Eclipse was the previous holder of that record with their Purple Hayes well (18,500 feet long), drilled one year ago. Eclipse seems to have taken a chapter from Rice Energy by naming their wells with creative names. Purple Hayes, named after the landowner (Hayes). The new record-holder? Great Scott–presumably named after the landowner (Scott).

Eclipse reports drilling its newest record setting “Super-Lateral” well, the Great Scott 3H, with a total measured depth of 27,400 feet and completable lateral extension of 19,300 feet in less than 17 days from the drill bit hitting the ground to total depth (called spud to TD) in the company’s Utica Shale condensate area.

If you’re an MDN subscriber, you were already expecting this big news. Back in April MDN editor Jim Willis attended the Oil & Gas Investment Symposium in New York City and reported on Eclipse’s session. At the time Jim reported: “They [Eclipse] plan to drill 11 “super lateral” wells that exceed 15,000 feet long. Two wells they hope to drill will break the existing Purple Hayes record–by going to 19,000 feet!”.

Just a month later and the company is already delivering on its promise. Even bigger news: Eclipse is currently drilling a second well of the same length next to Great Scott!

http://marcellusdrilling.com/2017/05/great-scott-eclipse-drills-new-longest-lateral-in-world-in-utica/

The price swoon of the last few weeks has no doubt disappointed -- if not frustrated -- OPEC's 13 members, who have seen their efforts to cut production to support prices seemingly thwarted by stubbornly high inventories.

But all along, OPEC officials have maintained that their goal with the production cut deal can not and should not be measured by how the market reacts day to day, or even week to week.

Their eyes are focused on the third quarter, when OPEC's own analysis, as laid out in its most recent monthly oil market report, estimates global demand for OPEC crude will rise to 33.13 million b/d, some 1.3 million b/d above current levels.

OPEC will issue its newest monthly oil market report next Thursday.

"The good news is that the market is moving towards rebalancing," Saudi Aramco CEO Amin Nasser said at the International Oil Summit in Paris last week. "There has also been a rapid drawdown of floating storage in the first quarter of this year. This is being driven by improving fundamentals and the OPEC deal."

Iranian deputy oil minister Roknaddin Javadi added: "I am very optimistic that good days for the oil and gas industry are ahead."

The deal, signed late last year, calls on OPEC to cut 1.2 million b/d from its October levels, while 11 non-OPEC countries led by Russia agreed to cut 558,000 b/d in concert.

To be sure, OPEC had intended its production cuts to have brought down global oil stocks to their five-year average by mid-year. That has not been the case, particularly in the US, where bloated gasoline stocks, in particular, has given the market jitters.

US gasoline stocks were 19.5 million barrels above the five-year average at 241.2 million barrels the week that ended April 28, according to the US Energy Information Administration.

Analysts with PIRA, a unit of S&P Global Platts, say the market's fretting over US inventory statistics may be overblown.

"The lack of visible stock declines have undermined oil market confidence and dragged prices lower," PIRA said in a recent note. "Market jitters are unwarranted; oil on the water is declining, OPEC output is declining and surplus stocks are declining. Onshore stock declines are inevitable, though the exact timing is tricky."

EXTENSION TALKS

The production cut deal, as signed, was to last from January to June, although ministers have said they reserve the option to extend the deal if market conditions have not been to their satisfaction.

OPEC appears to be moving towards an extension, with Saudi Energy Minister Khalid al-Falih recently saying there was a growing consensus that one was needed.

But still unresolved are the particulars of any extension -- its length, the level of cuts, and whether Libya and Nigeria, which were given exemptions from the cuts, and Iran, which was allowed a slight rise in production, will continue to receive special dispensation.

Falih has floated the idea of a three-month extension, instead of a six-month one, while Kuwaiti oil minister Essam al-Marzouq has said that if demand is healthy in the second half of the year, the production cuts may not need to be as deep.

Iraqi officials, however, have indicated they are not on the same page, having insisted the deal concerns exports, not production, contrary to the text of the agreement posted on OPEC's website.

"We are committed to the agreement with OPEC. Still, our internal demand is increasing, so our production can be increased without affecting our commitment," Naufel Alhasan, deputy chief of staff to Iraqi Prime Minister Haider al-Abadi, told Platts in Houston this week.

OPEC, along with the 11 non-OPEC deal participants, will meet in Vienna on May 25 to review the deal and negotiate any extension.

Given the resilience of US producers, who have ramped up output by some 600,000 b/d since the deal was signed, according to the EIA, OPEC may need to show the market a stronger hand with a more stringent extension, said Mohammed al-Sabban, a former advisor to the Saudi oil ministry.

This may include sharper cuts or a requirement that Libya, Nigeria and Iran join in, he said.

"The agreement extension should not be an automatic rollover, we may need to have deeper cuts," he told Platts. "The competition with American oil is going to be more severe in the coming months."

Nigeria and Libya, which have seen their oil sectors hit hard by militancy over the past year, will seek a renewal of their exemptions, even with their prospects improving recently.

Their combined production this year, while volatile, has averaged just 6,300 b/d more than October, the benchmark month that the production cut deal is measured from, according to the latest Platts OPEC survey.

Iran, meanwhile, has yet to be asked to join in the output cuts as part of an extension, "to my knowledge," Javadi told Platts.

COMPLIANCE UNREWARDED

On compliance, OPEC has performed very well.

The Platts OPEC survey for April, released Thursday, found that the 10 members required to lower output under the deal achieved 105% of their cuts.

As a whole, OPEC's total April output of 31.85 million b/d remains 80,000 b/d above the organization's stated ceiling of about 31.77 million b/d, not including Indonesia, which suspended its membership in November and is not counted in the Platts survey.

That has exceeded the expectations of many OPEC watchers, given the organization's tattered history of adhering to previous production agreements. Nevertheless, the market has stopped rewarding OPEC for its high level of compliance, amid the US shale rebound. Analysts say an extension of the cuts is already priced into current market expectations, even with prices having given up all of their gains since the OPEC/non-OPEC deal was signed.

ICE Brent futures were $48.57/b at 1015 GMT Friday, recovering from a sharp fall in earlier trading.

Even as they remain resolute on their intermediate-term goal of drawing down inventories, OPEC is likely to be mindful of 2016's price volatility when the bloc's members were engaged in a brutal market share battle.

"They'll have to extend [the deal], or the show's over," one Platts survey participant said. "The market will fall very quickly if they don't."

https://www.platts.com/latest-news/oil/london/analysis-as-prices-fall-opec-looks-to-q3-for-27826622

TransCanada Corp's quarterly profit more than doubled, as Canada's No. 2 pipeline operator incurred lower charges.

The company's net profit attributable to shareholders rose to C$643 million ($467 million), or 74 Canadian cents per share, in the first quarter ended March 31 from C$252 million, or 36 Canadian cents per share, a year earlier.

The latest quarter included about C$48 million in charges, mainly related to the acquisition of Columbia Pipeline Group. The year-ago quarter included charges of about C$211 million, mainly related to the termination of Alberta power purchase agreements.

Revenue rose 35.5 percent to C$3.39 billion.

http://www.reuters.com/article/transcanada-results-idUSL4N1I73D9

Russia's largest oil producer Rosneft posted a worse than expected rise in first-quarter net income on Friday, hit by a stronger rouble despite higher output and crude prices.

While the price of Russian Urals oil rose 28 percent year on year in rouble terms, Rosneft said that the currency's strength had a negative impact on its performance in the first three months of 2017.

Though a stronger rouble helps to lower payments of debt denominated in foreign currencies, it also reduces revenue from exports.

"The environment remains difficult. Continuing world commodity markets volatility, rouble appreciation -- all of this impacted the company's financial results," Rosneft's Chief Executive Igor Sechin said on Friday.

Net income rose 8.3 percent year on year to 13 billion rubles ($221.4 million), against a consensus forecast of 22 billion rubles among analysts polled by Reuters. [nL8N1I65K4]

Rosneft shares were down 0.6 percent at 308.10 rubles in early trade as Russian assets were pressured by a drop in oil prices amid a global supply glut.

Rosneft also said that first-quarter free cash flow declined by 22.6 percent from a year ago to 89 billion rubles.

The company said on Wednesday that its oil and gas condensate production rose by 13 percent in the first quarter to 4.62 million barrels per day.

http://www.reuters.com/article/us-rosneft-oil-results-idUSKBN1810TM

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Shell's realised natural gas price in Europe rises in Q1 to $5.08/Mcf

Shell saw its average realised gas price in Europe in the first quarter of 2017 edge up to $5.08/Mcf ($4.94/MMBtu) compared with the previous quarter, the company said in its Q1 earnings statement Thursday.

The gas price increase was triggered by increased demand on cold weather across Europe in January and the early part of February, which saw wholesale gas prices surge.

Its European realised price was $4.94/Mcf in Q4 2016.

However, Shell's realized European price in Q1 was still below the spot price average in Q1.

According to Platts assessments, the Dutch TTF spot price averaged $5.77/MMBtu in Q1, up from $5.41/MMBtu in Q4 2016, while the UK NBP spot price averaged $6.00/MMBtu in Q1 compared with $5.62/MMBtu in Q4 2016.

Shell's European gas price boost helped push its global average realized gas price to $4.29/Mcf in the last quarter, up from $4.03/Mcf in Q4 last year.

Europe accounts for a significant chunk of Shell's gas production -- it averaged 3.43 Bcf/d in Q1 out of a total of 10.94 Bcf/d.

GRONINGEN 'CONVERSATION'

But Shell warned that its gas output in the second quarter would be impacted by some 50,000 b/d of oil equivalent due to the production cap at the giant Groningen field due to the earthquake risk.

CFO Jessica Uhl, speaking to reporters on a webcast later Thursday, said Shell -- which is part of the NAM operating venture with ExxonMobil -- would continue to engage with the Dutch authorities on the subject.

"NAM is an important investment for Shell, and this is a very important issue for the country," Uhl said.

"We are working closely to ensure the asset is operated appropriately and sustainably. We are continuing to engage in that conversation. That's the focus -- meeting the needs of the various stakeholders," she said.

The Dutch government is making preparations to introduce a 10% cut in the production quota for gas from Groningen field from the start of the next gas year on October 1 following an increase in earthquakes in the area around Loppersum.

If adopted, the move would see the production quota cut from the current level of 24 Bcm/year to 21.6 Bcm/year.

In addition, a Dutch appeals court on April 20 ruled that NAM should face an investigation into whether it has been criminally negligent in causing earthquakes in the region.

LNG SALES

Shell, which became a much bigger player in gas with the acquisition last year of the UK's BG Group, is now also a leading LNG company.

LNG liquefaction volumes were 8.18 million mt in Q1, up 16% year on year, but down from 8.57 million mt in the previous quarter.

LNG sales in Q1 were 15.8 million mt, up by 29% year on year and by 3% quarter on quarter.

"Compared with the first quarter 2016, LNG liquefaction volumes mainly reflected the start-up of Gorgon in Australia and the contribution of BG assets for an additional month," Shell said.

"LNG sales volumes mainly reflected increased trading of third-party volumes and higher liquefaction volumes compared with the same quarter a year ago."

https://www.platts.com/latest-news/natural-gas/london/shells-realized-natural-gas-price-in-europe-rises-26728042

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Profitable WPX Sees 3 Keys for Ramping Up in the Delaware

In today’s conference call, WPX discussed three main requirements for ramping up production.

Geology

First and foremost is the local geology. However, WPX believes that it has mostly solved this question. While spacing and a few other nuances will require further investigation, the geology itself is well-established.

“There is no question,” WPX COO Clay Gaspar commented, “especially where we’re at in the Delaware Basin is world-class rock and there is tons of opportunity.”

Hedging providing confidence

The second primary determining factor for development is commodity price. WPX responded to this factor with aggressive hedging to lock in economic prices. The company has about 72% of its expected 2017 oil production hedged at an average of $50.84/bbl and 76% of its gas production hedged at $3.02/MMBTU. With oil currently trading below $46/bbl, this hedge position is paying off for WPX.

Clay Gaspar remarked that this position gives the company confidence. Mentioning the recent dip in oil prices, Gaspar noted, “I imagine there are a lot of our peers that are fully exposed that are really pulling their hair out, and I can tell you it’s very reassuring to have that confidence to be able to go to the team and say, yep, we’re still doing, [and] go to our key vendors and say, guys, we’re still plowing ahead, stay with us.”

Permian needs takeaway capacity

The massive increase in Permian activity has also created a situation that is usually restricted to the Marcellus. Permian midstream capacity must be able to grow and keep up with development, or Permian producers would be stuck with large differentials like those seen by Marcellus producers.

Gaspar reported that the company has been working on several deals to deal with transportation before it becomes a problem. Most significant among these is a potential midstream joint venture. WPX is considering a JV to handle takeaway from its core Delaware Basin assets, which would ensure transport remained available. While the company declined to provide further details, an agreement is expected midyear.

Multiple Permian acquisitions in Q1

WPX has been very active in the Permian this year, with several major acquisitions. In January the company acquired Panther Energy and Carrier Energy, adding about 120,000 net acres for $775 million. More recently, the company purchased 17,900 acres in Culberson County for $38 million. This acquisition is exploratory in nature, and is farther west than the core of the Delaware Basin. With an acreage cost of about $2,000/acre, however, this is much less expensive than many Permian transactions in recent months.

The company now owns about 135,000 net acres in the Delaware basin, and is producing a total of 90 MBOEPD from its Permian, Bakken and San Juan properties. WPX will spend about $620 million over the rest of the year to grow production by about 20%.

WPX Energy reported first quarter earnings yesterday, showing net income of $88 million, or $0.22 per diluted share. This significantly exceeds the $175 million loss the company took in Q4 2016, or the $17 million loss in Q1 2016.

https://www.oilandgas360.com/profitable-wpx-sees-3-keys-ramping-delaware/

Australia's top energy retailer, Origin Energy, said on Friday it doubled its stake in the Beetaloo Basin shale gas field in Australia's Northern Territory.

The company said it increased its share in the undeveloped prospect to 70 percent, after purchasing a 35 percent share from Sasol Petroleum Australia Ltd. It did not disclose a purchase price and said the transaction is subject to "certain conditions," without elaborating.

"It is not expected to impact on Origin's short-term focus on debt reduction as there are no immediate capital requirements in the Beetaloo," Origin said in a statement.

In February, Origin said it estimates contingent resources in the field to be 6.6 trillion cubic feet. But its extraction depends on the Northern Territory government lifting a ban on hydraulic fracking. The government is reviewing the ban but has set no deadline for making a decision.

Origin last week reported soaring gas revenues, thanks to a sharp rise in sales, as a supply crunch in Australia pushes prices higher.

Falcon Oil and Gas Australia owns the remaining 30 percent of the joint-venture.

http://www.reuters.com/article/origin-energy-gas-idUSL4N1I70ET

U.S. shale exploration company Marathon Oil Corp reported a smaller-than-expected quarterly loss on Thursday, helped by higher crude prices.

In the wake of rising crude prices, oil and gas producers have increased their capital spending to acquire shale-rich properties, especially in the Permian basin, and have put more rigs back to work.

The company in March bought about 70,000 acres for $1.1 billion, and in a separate deal acquired 21,000 acres for $700 million, both in the top U.S. shale field, the Texas Permian basin.

Average realized prices for crude oil and condensate in North America was $48.46 per barrel in the quarter ended March 31, up from $28.21 a year ago, the company said.

Total production at Marathon Oil averaged 338,000 barrels of oil equivalent per day (boe/d) in the quarter, marginally below the 339,000 boe/d in the year-ago period.

However, the company's net loss widened to $4.96 billion, or $5.84 per share, from $407 million, or 56 cents per share, a year earlier, due to an impairment charge related to the sale of its Canadian oil sands business.

Marathon Oil sold its Canadian oil sands business to Royal Dutch Shell (RDSa.L) in March in a deal valued at $7.25 billion.

Excluding one-time items, the company lost 7 cents per share, beating analysts' average estimate of a loss of 10 cents per share, according to Thomson Reuters I/B/E/S.

Houston-based Marathon Oil's revenue rose 88 percent to $1.07 billion.

http://www.reuters.com/article/us-marathn-oil-results-idUSKBN1802QD