Russia has not complied with oil cuts?

Not only has Russia not complied, it has barely managed to cut 150,000 b/d over the six months. 

@ncitayim

OPEC officials say Russia hasn't cut the amount of 300,000 barrels a day as promised over six months 

@summer

Oil tankers carrying roughly 2.5 million barrels of U.S. crude are currently en route to Asia, trade sources said on Wednesday, as U.S. producers take advantage of favorable prices to ship to Asia while OPEC ponders further supply cuts next week.

At least three vessels capable of moving 1 million barrels of crude each are sending domestic oil to Asian refiners, as well as some Mexican crude, several sources said.

OPEC members meet next week to discuss extending a global supply cut, but the possibility of U.S. supply eating into their market share will be a challenge. While member countries have largely restrained their supply, they have remained intensely focused on keeping market share with Asian refiners. But relatively cheap U.S. crude has buoyed exports to Asia.

Traders expect that May U.S. crude exports could reach around 1 million barrels per day, with a sizable portion of that going to Asia. Last week, U.S. crude exports touched 1.09 million bpd, the third highest on record, according to U.S. government data. If numbers remain elevated, they could surpass the record 1.2 million bpd seen in February.

"We expect that momentum to continue when (Dakota Access Pipeline) opens and as more Permian production hits Corpus Christi docks," said Sandy Fielden, director of oil and products research at Morningstar, of the exports.

Increasing traffic to Asia is possible because of a widening premium for Brent over U.S. crude, which touched a six-week high on Wednesday.

"Early May spot prices showed both Brent and Dubai trading at around a $3 per barrel premium to Brent and WTI Cushing, which is an open window," said Fielden.

Meanwhile, prompt Brent crude's premium to Dubai, also called the exchange of futures for swap narrowed to below $1 a barrel last month, hitting 46 cents a barrel on April 27, its tightest since 2010.

That spread has been tightening since OPEC agreed to production cuts in November, making U.S. cargoes more competitive. An extension to OPEC cuts may further benefit U.S. producers and exporters.

The Sydney Spirit, a Bahamas-flagged vessel, is delivering Alaskan North Slope (ANS) crude to Asia, according to two sources and Reuters vessel tracking data. Half of the crude onboard the vessel is unsold, one of the sources said.

Vessel tracking data available via Eikon system lists the ship as "for orders," which indicates there may not be a buyer for at least some of the crude. The ship is currently on its way to Asia.

Meanwhile, Japanese refiner Cosmo Energy loaded the Almi Star, a Aframax vessel carrying around 600,000 barrels of crude, with offshore Southern Green Canyon crude and Domestic Sweet Blend (DSW) outside of Houston, before picking up an additional 300,000 barrels of Maya crude at Dos Bocas, Mexico, two sources familiar with the matter said.

That ship will move through the Panama Canal, and then transfer crude to a larger Suezmax vessel loaded with 400,000 barrels of Mexican Maya crude for a voyage to Asia, the sources said.

The Montesperanza, another Suezmax, is headed to Singapore after loading at the Galveston Offshore Lightering Area. The ship is controlled by French energy firm Total SA, and the crude on it is expected to go to Japan, two sources said.

http://www.reuters.com/article/us-usa-crudeexports-idUSKCN18D2ZU

Jet fuel and LPG have turned out to be the shining stars in India's oil demand basket so far in 2017 as rapidly growing air travel and New Delhi's clean fuel energy push are helping the two fuels to post the sharpest growth rates among all oil products.

As air travel continues to grow amid intensifying competition among airlines offering competitive fares, jet fuel demand rose by 9.5% year on year in April, to 610,000 mt from 557,000 mt from a year earlier, according to data from the Petroleum Planning and Analysis Cell.

In the cumulative January-April period, jet fuel demand surged 12% year on year to 2.46 million mt from 2.19 million mt a year earlier.

"While demonetization has affected consumption of some oil products, it has not affected air travel because most air tickets are booked using credit cards. Not much cash is involved. Therefore, jet fuel demand remains robust, said Tushar Bansal, director at Ivy Global Energy, a Singapore-based oil and gas consultancy.

India announced the scrapping of 1,000 and 500 rupee notes with immediate effect on November 8, 2016, in a move aimed at curtailing the shadow economy but which also led to a slowdown in demand for various commodities over the following months.

According to CAPA - Centre for Aviation, an independent provider of market intelligence for the aviation sector, India is likely to overtake Japan in 2017 to become the world's third-largest domestic aviation market, behind the United States and China.

In reaching this milestone, India will have achieved average domestic annual traffic growth of over 15% since the liberalization of the sector commenced in 2003-04 (April-March).

While domestic traffic could grow by nearly 25% in 2017-18 (April-March) and approach 130 million passengers, international travel could growth by about 10%-12%, CAPA added. Strong economic fundamentals have contributed to the growth, although traffic has been over-stimulated by low fares.

"India's status as the fastest growing aviation market in the world creates tremendous opportunities. But risks are also heightened as the inadequacy of India's infrastructure planning, a fast emerging shortage of skills, flawed policy initiatives, and weak regulatory oversight threaten to become major stumbling blocks," according to a CAPA report on India's aviation outlook.

Prime Minister Narendra Modi has said that in the global civil aviation market, India, which is currently the eighth-largest market in the world, would become the third-largest by 2034, adding that growth in the aviation sector would multiply demand for aviation fuel in India four times by 2040.

Rising domestic demand is taking a toll on India's jet fuel exports as more cargoes find their way into local markets. Jet fuel exports in the first quarter of 2017 fell almost 12% year on year to 1.75 million mt, from 1.99 million mt in Q1 2016.

Market participants expect India's jet fuel exports to maintain a downward trend as domestic demand is expected to remain robust in the foreseeable future.

LPG SPREADS ITS WINGS

While LPG demand grew by only 2.6% year on year in April to 1.63 million mt, from 1.59 million mt a year earlier, it has been the second-fastest growing fuel this year, with demand rising by 6.1% year on year to 7.31 million mt in the January-April period, from 6.9 million mt in the same year-ago period, PPAC data showed.

"The government is expected to speed the pace of distribution of subsidized LPG connections to the poor. That will keep the demand growth at double digits," Bansal added.

India is expected to invest $3.9 million-$4.7 billion in developing infrastructure facilities for LPG to raise household connections to 95.5% by 2020, oil ministry officials said Friday.

State-own Indian Oil Corp plans to spend 10% of its overall capex of $3.1 billion for 2017-18 on strengthening the infrastructure for LPG including setting up of terminals and bottling plants.

But despite the capacity build-out, IOC's chairman B. Ashok said he expects India to continue importing LPG at least for the next 12 to 13 years after which he anticipates a slowdown in India's LPG demand growth.

India consumed 21.5 million mt of LPG in 2016-17, a 9.8% growth from the previous year (2015-16), according to the oil ministry updates. Half of the last year's demand was met via imports, mainly from the Middle East. India's LPG imports rose 23% year on year to 11 million mt of LPG in 2016-17.

"Our main import destinations will continue to be the Middle East as shale gas production has made LPG price relatively a competitive option," Petroleum Minister Dharmendra Pradhan said.

India aims to increase the number of households with LPG access to 268.7 million in 2018-19, up by around a third from 199 million in 2016-17, and to add 10,000 new LPG distributors by 2019, the minister said. The renewed push on LPG saw 4,600 new distributors open in 2016-17.

India's overall demand for oil products in April rose 2.3% year on year to 16.79 million mt, or 4.4 million b/d, PPAC data showed. January-April oil products demand fell 1% year on year to 65.7 million mt, or 4.3 million b/d.

"In line with our expectations, India's oil demand is on a recovery path as the impact of demonetization fades," said Sri Paravaikkarasu, Head of Oil, East of Suez, at consultancy FACTS Global Energy.

"Transport fuels should continue to propel oil demand growth in the coming months although LPG and other products will also contribute to a 5% to 6% average growth for the year," she added. "The double-digit growth in fuel oil in 2016 should reverse this year, while kerosene will track the negative trend."

https://www.platts.com/latest-news/oil/singapore/analysis-indian-jet-fuel-lpg-demand-shrugs-off-27831257

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UK-based energy giant BP has signed a deal to supply LNG to the Indonesian power utility Perusahaan Listrik Negara (PLN).

BP is to supply 16 LNG cargoes per year from its Tangguh LNG project in Bintuni Bay to PLN over 2020-2035.

The Tangguh LNG facility consists of offshore gas production facilities supplying two 3.8 mtpa liquefaction trains that have been in operation since 2009.

In July last year, the project partners have made a final investment decision to build a third train at the facility. The third liquefaction train will add 3.8 mtpa of production capacity to the existing facility, bringing total plant capacity to 11.4 mtpa. First production from the third train is expected in 2020.

Besides BP, the other partners in the Tangguh production sharing contract are MI Berau (16.30%), CNOOC Muturi (13.90%), Nippon Oil Exploration (Berau) (12.23%), KG Berau Petroleum and KG Wiriagar Petroleum Ltd (10.00%), Indonesia Natural Gas Resources Muturi (7.35%), and Talisman Wiriagar Overseas (3.06%).

http://www.lngworldnews.com/bp-inks-indonesia-lng-supply-deal/

The Organization of Petroleum Exporting Countries and its partners are expected to extend output curbs into early 2018 when they meet next week, in an ongoing bid to clear a global surplus. Yet the tailwinds that made cutting supply easier in the first half of the year -- from a seasonal lull in demand to temporary oil-field maintenance -- will be gone just as new obstacles are emerging.

To keep a lid on output this summer, Saudi Arabia will need to sacrifice an even bigger share of exports as consumption at home rises. Iraq yearns to expand capacity, and has already used the option of maintenance to keep oil fields idle. Meanwhile Nigeria and Libya, two OPEC nations exempt from the deal, are restoring lost output.

“They’re going to struggle,” said Michael Barry, director of research at consultants FGE in London. “This deal has been remarkable in its implementation. As time goes on, discipline is likely to erode. Almost every country wants their production to go up.”

As the world’s fuel-storage tanks remain brimming and prices languish, OPEC and its allies have conceded that the initial plan for six months of production cuts wasn’t long enough. Yet Saudi Arabia and Russia’s proposal that their 24-nation coalition, due to meet in Vienna on May 25, should extend the measures for another nine months may prove an unbearable strain.

“Production curbs for the first quarter of 2017 were comparatively easy to agree to,” said David Fyfe, chief economist at Geneva-based oil trader Gunvor Group. “They’ll likely agree to extend” but “the risk is higher they’ll leak extra barrels onto the market.”

OPEC showed an unprecedented level of commitment to this deal, implementing 96 percent of the cuts it promised during the first four months of the year, according to the International Energy Agency.

Holding Line

Some are optimistic that OPEC and its partners will maintain their resolve. The stakes are high enough that the organization will stick to its commitments, and as inventories decline producers will feel encouraged to stay the course, said Mike Wittner, head of oil market research at Societe Generale SA in New York.

“They’re going to hold the line,” said Wittner. “If we see stock draws happening soon, which we believe will be the case, those signs of success will bolster their determination. When you see light at the end of the tunnel, it’s easier to keep it together.”

Still, strong compliance was often attributable to Saudi Arabia cutting more than it was required, compensating for laggards like Iraq and the United Arab Emirates.

If the kingdom continues to restrain output, it needs to make another sacrifice. The Saudis typically boost production during the summer to maintain exports while meeting increased local demand from air conditioning. Keeping a cap on output would mean foregoing some exports and the revenues they bring.

Iraqi Question

Iraq, which still hasn’t made its full cut, plans to boost production capacity to 5 million barrels a day, an increase of about 6 percent, Oil Minister Jabbar al-Luaibi said on May 11. This won’t conflict with its commitment to freeze output, he said.

“We have question marks around Iraq,” said Harry Tchilinguirian, head of commodity markets strategy at BNP Paribas SA in London. “They have been reluctant since the very beginning, and were slow to implement their cuts. Most of the supply restraint in Iraq has come with the help of field maintenance.”

Maintenance in Iraq, Kuwait and the U.A.E. may have accounted for about 500,000 barrels a day of the output halted -- almost half the group’s total cut, according to FGE. For Iraq, this enabled them to avoid compensating foreign companies for unscheduled production shutdowns.

“Several countries basically used maintenance as a way of keeping production down but what they did was pull it forward from later in the year,” said FGE’s Barry. “Now maintenance is over the question is what do they do? More maintenance or cut at other fields? The pressure is on.”

OPEC also faces the challenge that the two members exempted from the deal because of production losses are recovering. Both Libya and Nigeria are showing progress in tackling the political crises that slashed their output.

Disciplinary Issues

Libya is producing at the highest level in more than two years after restarting its largest oil field, according to state-run National Oil Corp., while Nigeria has fixed a pipeline after a one-year halt that could boost its output by about 13 percent.

The 11 non-members joining OPEC’s effort have still only implemented about two-thirds of their promised reduction, according to the IEA, and also face problems in sustaining their curbs. Cutbacks in Russia came alongside the traditional seasonal stagnation in activity, and prolonging them would thwart plans by companies to expand output.

“It was easy to mask maintenance in the first half as voluntary cuts, but quite impossible to do it any further,” said Eugen Weinberg, head of commodities research at Commerzbank AG in Frankfurt. “There will be lower discipline within OPEC, and lower discipline from non-OPEC.”

https://www.bloomberg.com/news/articles/2017-05-16/opec-risks-deal-fatigue-as-maintaining-oil-curbs-gets-tougher-j2s5ws6u

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Brazil's state-controlled oil company Petrobras will pay its first shareholder dividend in three years if the company turns a profit in 2017, Chief Executive Officer Pedro Parente said on Wednesday.

Parente took the helm of the world's most indebted energy company a year ago and said he is ahead of schedule with an aggressive restructuring plan to cut its $95 billion debt, reduce costs and sell assets.

Petroleo Brasileiro SA, or Petrobras, made a record operating profit in the first quarter and if that continues throughout the year, chances are good that the firm will pay a dividend, Parente told Reuters in an interview in New York.

"We really are keen to start paying dividends as fast as we can," he said. "If at the end of the year I have a profit, we would be more than happy to start paying dividends."

Petrobras' bylaws say that shareholders are entitled to dividends if the company turns a profit, pending approval from the board and considering factors such as cash requirements and investment opportunities. Company executives have in the past said Petrobras is not obliged to pay dividends on its profits.

Rising output in Brazil's prodigious offshore fields is helping Parente turn Petrobras around from its nadir in 2014, when the firm last paid dividends.

Then, investors lost confidence as Petrobras sank into a political and financial maelstrom with the oil price fall reducing its revenues, a corruption scandal swamping the company and losses mounting due to government fuel subsidies.

Ratings firms downgraded Petrobras' creditworthiness, landing the firm with a huge interest bill to service its debt, which then stood at around $130 billion, accumulated to finance development of massive reserves in Brazil's deep Atlantic waters.

Parente says he was hopeful about hitting his key metric to reduce leverage by the end of this year - a full year ahead of schedule.

"It is likely we will reach that target ... before 2018. I hope, but I don't know." he said.

He is targeting reducing Petrobras' debt to 2.5 times its adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) from 5.1 times EBITDA at the end of 2015. At the end of the first quarter the ratio stood at 3.24.

Even if he hits that target, Parente has no plans to stop reducing debt or to let up on asset sales.

"We're not going to stop our plan... This is not yet a healthy leverage level for Petrobras," he said.

A more appropriate level that would put Petrobras in line with global oil majors would be around 1.5 EBITDA, he said. He has no plans, for now, to make that a new target.

Investors have rewarded Parente for the turnaround. The firm achieved an interest rate of below 5 percent this week on a five-year bond for the first time since the crisis, Parente said. At the worst point, the rate was around 13 percent.

Parente said he would consider serving as chief executive beyond the end of next year if the government that is elected in 2018 wants him to continue in the post. A full cycle of management at the company would be four years, he said.

Petrobras has yet to decide whether it will participate in three government auctions this year for oilfields, he said. If it does, it will be go for deepwater fields, as operating there is Petrobras' strength, he added.

The company will not adjust its five-year capital expenditure plan of $75 billion through 2021 to finance the development of new fields, Parente said, adding that the firm would fund any expansion through cost reductions.

Petrobras will not bid for onshore or shallow water oilfields, he said, and is committed to selling its participation in onshore and shallow water fields as part of a $21 billion divestment plan, he said.

He declined to say how much cash he hoped to raise with field sales.

Rising Brazilian output, both from Petrobras and from international oil firms operating there, has contributed to a strong rise in output from non-OPEC producers this year that is making it hard for the Organization of the Petroleum Exporting Countries to curb global supply and end a two-year glut.

Petrobras' crude exports rose to 725,000 barrels per day in the first quarter, up 72 percent on the year. The rise came in part because of higher output, but also because a recession in Brazil has hit domestic oil demand.

http://www.reuters.com/article/us-brazil-petrobras-idUSKCN18D2Y6

Iran is preparing to combine its massive North and South Azadegan oil fields for development as a single project and plans to invite IOCs to bid for the contract in coming weeks.

http://www.energyintel.com/pages/login.aspx?fid=art&DocId=961605

U.S. crude oil refinery inputs averaged over 17.1 million barrels per day during the week ending May 12, 2017, 363,000 barrels per day more than the previous week’s average. Refineries operated at 93.4% of their operable capacity last week. Gasoline production decreased last week, averaging over 10.0 million barrels per day. Distillate fuel production increased last week, averaging over 5.0 million barrels per day.

U.S. crude oil imports averaged 8.6 million barrels per day last week, up by 970,000 barrels per day from the previous week. Over the last four weeks, crude oil imports averaged over 8.3 million barrels per day, 9.3% above the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 696,000 barrels per day. Distillate fuel imports averaged 161,000 barrels per day last week.

U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) decreased by 1.8 million barrels from the previous week. At 520.8 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 0.4 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 1.9 million barrels last week but are in the upper half of the average range for this time of year. Propane/propylene inventories increased by 0.6 million barrels last week but are in the lower half of the average range. Total commercial petroleum inventories increased by 4.3 million barrels last week.

Total products supplied over the last four-week period averaged about 19.8 million barrels per day, down by 2.2% from the same period last year. Over the last four weeks, motor gasoline product supplied averaged 9.3 million barrels per day, down by 2.6% 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 0.8% from the same period last year. Jet fuel product supplied is up 6.1% compared to the same four-week period last year.

Cushing unchanged

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

                                                   Last Week  Week Before   Last year

Domestic Production '000.......... 9,305           9,314            8,791
Alaska ............................................... 510  .            531               506
Lower 48 ...................................... 8,795           8,783            8,285

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

Reported oil stocks have fallen much more slowly than OPEC anticipated at the beginning of the year, leading to scepticism about the effectiveness of the organisation's production cuts.

But the sluggish response may reflect the repositioning of formerly uncounted stocks to more visible locations rather than a failure to adjust the supply-demand balance.

In general, crude oil and refined products move down the supply chain from areas of net production to areas of net consumption.

Despite significant trading activity around particular cargoes, the movement of crude and products essentially occurs in only one direction.

For commercial reasons, it makes no sense to move crude and products back up the supply chain, away from consumers and back towards refiners and producers.

Crude and products stocks are positioned as close to refiners and final consumers as possible, subject to the availability and cost of storage.

OPEC ministers and officials have stated that the objective of production cuts is to eliminate the overhang of excess oil stocks and reduce inventories to the five-year average level.

Ministers and officials most often reference commercial crude and product stocks held in OECD member countries when talking about the overhang and market rebalancing.

OECD stocks are the most accurately and frequently reported so in some ways it makes sense to use them as the benchmark for assessing whether the production cuts are working.

The problem is that they are not necessarily representative of stockpiles held in producing and consuming countries outside the OECD.

According to the International Energy Agency, total OECD commercial stocks rose during the first quarter of 2017, but this was largely offset by a reduction in floating storage and stocks held outside the OECD ("Oil Market Report", IEA, May 2017).

The diverging behaviour of OECD and non-OECD oil stocks reflects their differing locations along the oil industry's supply chain.

While OECD countries are substantial net importers of crude and consumers of refined products most of the major oil-exporting countries are located outside the OECD.

OECD refining centres also contain lots of inexpensive storage options which make them the preferred choice for holding non-operational or speculative inventories.

The result is that storage tanks in the OECD tend to be the first to fill during a period of oversupply and the last to empty when global stocks are falling.

By targeting OECD stocks, OPEC has made achieving its objective harder in the short term, because these stocks will be the last to respond to its production policy.

There is some evidence excess global inventories have already fallen, with reductions in oil-exporting countries, floating storage and remote locations part way between producing and consuming centres.

Excess stocks are gradually being pulled along the supply chain from producers, floating storage and remote locations towards the major refining centres in the OECD.

But the behaviour of the supply chain introduces an important non-linearity into the response of OECD stocks to OPEC's production policy.

OECD stocks are likely to fall slowly at first, then accelerate once producer stocks and floating storage have been emptied.

As a result, OPEC's production policy often tends to appear relatively ineffective at first before gaining traction later.

In this instance, the stubbornly high level of OECD oil inventories during the first quarter of 2017 may have masked a broader tightening in the supply-demand-inventory balance.

Inventory movements coupled with stronger seasonal consumption during the northern hemisphere summer could result in a more pronounced decline in OECD stocks during the second and third quarters.

http://www.reuters.com/article/oil-inventories-kemp-idUSL8N1IJ260

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President Donald Trump’s pledge to open oil and gas drilling on federal lands has hit a bureaucratic log jam.

More than 3,000 applications for drilling permits are  awaiting review at the Bureau of Land Management, according to a report by E&E News, a trade publication.

Acting Director Mike Nedd told E&E the bureau is working on several strategies to speed the processing of applications. “It may be a strike team. It may be shifting the workload to a different office,” he said.

Revenue from oil and gas production on federal lands and waters declined sharply in recent years, after the collapse in commodity prices in 2014. Interior Secretary Ryan Zinke has ordered staff to review regulations and management to see how production can be increased.

“Every day that goes by while independent producers — companies with an average of 12 employees — wait for their permits to be approved means more money out of their own pockets,” Neal Kirby, spokesman for the Independent Petroleum Association of America, told E&E.

http://fuelfix.com/blog/2017/05/17/drilling-applications-backing-up-at-blm/

Canadian Natural Resources Limited announced today that Toronto Stock Exchange has accepted notice filed by Canadian Natural of its intention to make a Normal Course Issuer Bid through the facilities of Toronto Stock Exchange or other alternative Canadian trading systems. Purchases may also be made through the facilities of the New York Stock Exchange.

The notice provides that Canadian Natural may, during the 12 month period commencing May 23, 2017 and ending May 22, 2018, purchase for cancellation up to 27,931,135 shares, being 2.5% of the 1,117,245,428 outstanding common shares as at May 12, 2017. Canadian Natural will not acquire more than 25% of the average daily trading volume of its common shares during a trading day, being 591,186 common shares subject to certain prescribed exceptions. The price which Canadian Natural will pay for any such shares will be the market price at the time of acquisition. The actual number of common shares that may be purchased and the timing of any such purchases will be determined by Canadian Natural.

In addition to further strengthening its balance sheet, investing in exploration and development of its diverse asset base, and participating in acquisition opportunities, returns to shareholders remain a priority to create value for Canadian Natural’s shareholders. Funds flow in 2017 is targeted to be allocated to these four pillars and may also be used by Canadian Natural, depending upon future trading prices and other factors, to purchase its common shares, as it is believed to be a worthwhile investment, and in the best interests of Canadian Natural and its shareholders

http://boereport.com/2017/05/17/canadian-natural-resources-limited-announces-normal-course-issuer-bid-4/

Shale explorers pushing to expand oil production are struggling to find enough fracking crews after thousands of workers were dismissed during the crude rout.

Independent U.S. drillers underspent their first-quarter budgets by as much as $2.5 billion collectively, largely because they couldn’t find enough fracking crews to handle all the planned work, according to Infill Thinking LLC, a research and consulting firm focused on oilfield services and exploration. If the scarcity holds, output increases planned for this summer may get pushed into 2018, creating an unanticipated production bulge with “scary” implications for oil prices, said Joseph Triepke, Infill’s founder.

In some cases, active crews are walking away from jobs they signed up for months ago -- and paying early-termination penalties -- to take higher-paying assignments with other explorers. Workers earn anywhere from $29,000 to $72,000 a year before overtime, depending on the company and the region.

The tight fracking market “means U.S. oil production growth this year will be back-half weighted, and we may not understand the full extent of U.S. production growth until early 2018,” said Triepke, who previously was an analyst at Citadel LLC’s Surveyor Capital unit. “This point is particularly scary if you are a rooting for higher oil prices.”

Oilfield-service companies contributed the largest chunk of more than 441,000 jobs slashed globally as prices plunged from more than $100 a barrel over the last three years, according to Houston-based industry consultant Graves & Co.

Now, with the price of oil settling at around $50 a barrel, shale drillers are once again gearing up in areas such as the Permian Basin, where break-even costs are as low as $30 a barrel. The result: rising competition for workers and equipment, which means higher costs. Fracking companies are now charging 60 percent to 70 percent more than a year ago as explorers engaged in bidding wars to lock up crews, according to Infill data.

In response, servicers are scrambling to re-hire hands and retrieve gear from storage, said Andrew Cosgrove, an analyst at Bloomberg Intelligence.

Typical Crew

A crew typically consists of 25 to 30 workers who operate a huge array of powerful truck-mounted pumps, storage tanks for fluids and sand, hoses, gauges and safety gear. Fracking, which involves pumping tons of water, sand and chemicals into a well to smash open the surrounding oil- and gas-soaked rock, is the most expensive part of drilling a well, usually accounting for about 70 percent of the total cost.

So far, independent shale drillers are confident they’ll find ample fracking capacity and are leaving their ambitious double-digit output growth targets intact. West Texas Intermediate crude, the U.S. benchmark, is heading for a second weekly advance as U.S. stockpiles decline while Saudi Arabiaand Russia indicated a willingness to extend price-boosting production cuts. WTI on Thursday was trading 0.3 percent lower at $48.91 a barrel as of 1:07 p.m. in Singapore.

Those efforts could be dashed in coming months, however, if shale explorers deliver a larger-than-expected bubble of supply.

“Every single pressure pumper is saying their order books are full through the third quarter and some as far ahead as the first quarter of ’18,” Cosgrove said.

Walkaways

EQT Corp. was left short of fracking crews during the first quarter when some pumping companies walked away for higher-paying contracts. Still, the Pittsburgh-based shale driller expects to attract enough fracking capacity by the beginning of June to stay on track and hit its full-year growth forecast.

“A couple of our frack contractors decided to pay us the penalties to take their frack crews to jobs that were more profitable,” EQT Chief Executive Officer Steven Schlotterbeck said during an April 27 conference call with analysts. “So we will get some penalty fees but that obviously is far less than the value of having the wells fracked on the schedule that we would have liked.”

The last time the shale patch boomed, Parsley Energy Inc. CEO Bryan Sheffield remembers personally delivering breakfast and giving away World Series tickets to get into good graces with fracking companies.

Better-Paying Gigs

That was late 2011, when booming demand for fracking capacity meant service companies could fire clients to take better-paying gigs, Sheffield said in an interview. The 39-year-old Parsley founder was relatively unknown at the time, trying to get to the top of frack companies’ cancellation lists, so he could get a chance to hire them and get his oil flowing.

Those days are back, he said.

After the last boom that saw oilfield truck drivers commanding more than $200,000 a year in the Bakken of North Dakota, companies are again hunting for more truckers -- this time in the Permian Basin of Texas and New Mexico for hauling water, sand and oil. Fracking equipment prices began rising late last year, Sheffield said.

“This is exactly what we saw in 2011 and 2012,” Sheffield said. “The bottleneck moves down the chain.”

https://mail.google.com/mail/u/0/?shva=1#inbox?compose=15c1a494d2f1143e

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A coastal Oregon county overwhelmingly rejected a ballot measure aimed at blocking a proposed natural gas terminal dealing a blow to what was the latest in a series of efforts to thwart energy projects across the Pacific Northwest.

The measure, had it passed, would have banned transport of fossil fuels not intended for local use through Coos County, located about 200 miles (322 kms) south of Portland.

Around 76 percent of votes were cast against the measure, with 24 percent in favor, according to unofficial results posted on the Coos County government website late Tuesday.

"This ballot measure was not a good measure by any means, and I think (the voters) were able to see that," Coos Bay's mayor Joe Benetti, who opposed the measure, told local newspaper The World.

Backers called the initiative a response to a $7.6 billion proposal by Calgary-based Veresen Inc, to build a facility in the county where natural gas would be liquefied and transferred to tanker ships for sale abroad. They cast the measure as a local refusal to contribute to global warming.

Gary Cohn, head of the National Energy Council, in April singled out the Veresen project as a priority for the administration of Republican President Donald Trump.

The Coos County initiative was part of regional resistance in the Northwest to fossil fuel projects that has seen the blockage of several major export facilities.

Last year, the Lummi Nation Native American tribe and environmental groups blocked an export terminal in Northwest Washington state that would have moved Montana and Wyoming coal to markets in Asia.

In January, Washington State denied a permit for a coal export terminal in the city of Longview, citing concerns about the financial viability of the project.

In February, bowing to pressure from activists, Seattle's city council voted to divest approximately $3 billion from Wells Fargo, citing concerns over the bank's support of the North Dakota Access Pipeline, among other factors.

Passage of the Coos Bay measure would have been another blow for liquid natural gas projects on the West Coast, even as depots in other areas of the country have moved forward.

Cheniere Energy Inc opened a port in Louisiana last year and several other companies are set to open projects on the Gulf Coast in 2018 and 2019. Dominion Energy Inc plans to open the Cove Point LNG port in Maryland later this year.

http://www.reuters.com/article/us-oregon-energy-vote-idUSKCN18D0VB

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