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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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  

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

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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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/

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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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

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

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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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

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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$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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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/

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