CNBC/ 3 October 2017

• A coalition of energy industry groups asked regulators to reject a rule proposed by the U.S. Department of Energy on Friday.
• The rule would bolster coal-fired and nuclear power plants by requiring wholesale markets to compensate them for certain attributes.
• The groups say the Energy Department proposed “unreasonable timelines” for stakeholders to offer feedback on a rule with “significant ramifications for wholesale markets.”

A coalition of 11 industry groups is pushing back on Energy Secretary Rick Perry’s efforts to quickly implement a major change to the way electric power is priced in the United States.

The Energy Department on Friday proposed a rule that stands to bolster coal and nuclear power plants by forcing the regional markets that set electricity prices to compensate them for the reliability they provide. Perry asked the Federal Energy Regulatory Commission to consider and finalize the rule within 60 days, including a 45-day period during which stakeholders can issue comments.

On Monday, groups representing petroleum, natural gas, electric power and renewable energy interests urged FERC to reject the expedited process, as well as the Department of Energy’s request that the regulatory commission consider putting in place an interim rule.

They say the time frame is “aggressive” and the department didn’t provide adequate justification for fast-tracking a process that could have huge impacts on wholesale electricity markets.

“This is one of the most significant proposed rules in decades related to the energy industry and, if finalized, would unquestionably have significant ramifications for wholesale markets under the Commission’s jurisdiction,” the groups said in the motion filed with FERC.

“The Energy Industry Associations urge the Commission to reject the proposed unreasonable timelines and instead proceed in a manner that would afford meaningful consideration of public comments and be consistent with the normal deliberative process that it typically affords such major undertakings,” they said.

The groups are requesting a 90-day comment period, as well as another period for reply comments. FERC, which has authority to regulate interstate transmission and sale of electricity and natural gas, is not required to decide in favor of the rule but must consider it.

Expediting the process or imposing an interim rule is generally limited to emergencies, the groups said. The Energy Department’s letter to FERC does not even attempt to establish that an immediate threat to U.S. electricity reliability exists, they allege.

The groups cite a recent Energy Department report on grid reliability that concluded: “reliability is adequate today despite the retirement of 11 percent of the generating capacity available in 2002, as significant additions from natural gas, wind, and solar have come online since then.”

The Department of Energy did not return a request for comment.

The Energy Department’s rule marks a flashpoint in the battle between natural gas-fired and renewable energy and so-called baseload power sources like coal and nuclear.

Gas, wind and solar power have eaten into coal and nuclear’s share of U.S. electric power generation in recent years. That is thanks to a boom in U.S. gas production that has pushed down prices, the rapid adoption of subsidized renewable energy and President Barack Obama‘s efforts to mitigate emissions from power plants.

Electric power is priced in deregulated, wholesale markets in many parts of the country. Utilities typically draw on the cheapest power sources first.

Some worry that the retirement of coal-fired and nuclear power plants undermines the nation’s ability to reliably and affordably deliver electricity to households and businesses.

President Donald Trump has vowed to revive the ailing coal industry. Trump, Perry and other administration officials reject the consensus among climate scientists that carbon emissions from sources like coal-fired plants are the primary cause of global warming.

 

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The Straits Times/3 October 2017

RIYADH (AFP) – Saudi Arabia is inviting bids for a “utility-scale” 300-megawatt solar project, a first for the world’s top oil exporter.

“Today’s bid opening represents a significant milestone for the National Renewable Energy Programme, and an important step on the way to diversifying Saudi Arabia’s domestic energy mix and building a cutting edge domestic renewable energy sector,” Energy Minister Khalid al-Falih said on Tuesday (Oct 3).

Bidders for the Sakaka solar energy project – to be located in the country’s northern Al-Jouf region – will be shortlisted on Nov 28, a government press release said.

The renewable energy programme also envisions a 400-megawatt wind power facility in Al-Jouf.

The kingdom has already shortlisted 25 companies – including GE, Siemens and EDF Energies Nouvelles, a subsidiary of the French public energy company – for that project, with bidding set to close in January 2018.

Saudi Arabia and other Gulf monarchies have been examining ways to cut their energy bills and diversify their power sources away from oil, their main export commodity.

Riyadh has set a target of 9.5 gigawatts of renewable energy by 2023.

Virtually all of Saudi Arabia’s power currently comes from crude or refined oil or natural gas.

Its renewable energy programme is estimated to be worth up to US$50 billion (S$68 billion).

 

News Source: The Straits Times

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The Straits Times/3 October 2017

NEW YORK (REUTERS) – Oil prices hit a more than two-year high on Monday (Oct 2) after major producers said the global market was on its way towards rebalancing, while Turkey threatened to cut oil flows from Iraq’s Kurdistan region toward its ports.

The November Brent crude futures contract was up US$1.51, or 2.5 per cent, at US$58.37 a barrel by 11:33am EDT (1533 GMT), its highest since July, 2015.

US West Texas Intermediate crude for November delivery rose US$1.02, or 2 per cent, to US$51.68 a barrel, close to highs last seen in May.

“It’s all driven by the idea is that the production cut is starting to work and the rebalance is underway,” said Gene McGillian, director of market research at Tradition Energy in New York.

Even as both contracts rallied, concerns about US production growth weighed on WTI, widening the spread between the two, he said.

The discount of the WTI to Brent futures widened to US$6.61, the widest since August 2015.

Turkey has said it could cut off a pipeline that carries oil from northern Iraq to the global market, putting more pressure on the Kurdish autonomous region over its independence referendum.

The Iraqi government does not recognise the referendum and has called on foreign countries to stop importing Kurdish crude oil.

“If this boycott call proves successful, a good 500,000 fewer barrels of crude oil per day would reach the market,”Commerzbank said in a note.

The Organization of the Petroleum Exporting Countries, Russia and several other producers have cut production by about 1.8 million barrels per day (bpd) since the start of 2017, helping to lift oil prices by about 15 percent in the past three months.

Kuwaiti Oil Minister Essam al-Marzouq, who chaired Friday’s meeting in Vienna of the Joint Ministerial Monitoring Committee, said output curbs were helping to cut global crude inventories to their five-year average, OPEC’s stated target.

Russia’s energy minister said no decision on extending output curbs beyond the end of March was expected before January, although other ministers suggested such a decision could be taken before the end of this year.

Iran expects to maintain overall crude and condensate exports at around 2.6 million bpd for the rest of 2017, a senior official from the country’s state oil company said.

The energy minister from the United Arab Emirates said the country’s compliance with Opec’s supply cuts was 100 percent.

Nigeria is pumping below its agreed output cap, its oil minister said.

 

News Source: The Straits Times

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Rigzone/3 October 2017

(Bloomberg) — Not every oilman is gaining from the U.S. shale boom. Just ask Joe Warren.

Warren, a partner at Brown & Borelli Inc., is caught in a historical hiccup, of sorts. More than a third of the 65 to 70 old-line vertical wells his company operates in Oklahoma are negatively affected by horizontal drilling, he says. The new-style wells can run sideways for miles in a shale play, carrying sand, water and chemicals that can leak into older wells, gumming up the works.

The cost: For Warren’s company, it’s about $250,000 a year in lost production and $150,000 in added operating expenses, he said. It’s an issue spurring rising anxiety among small drillers. Already, several lawsuits have been filed while a group representing old-guard drillers is gathering data, aiming to force legislation guaranteeing compensation when damages occur.

“We should not be sacrificing our property to these guys for horizontal development,” Warren said by telephone. “We don’t want to stop horizontal development — we just want to make the rules fair.”

Some of Warren’s wells saw a slight drop in output while others, hit multiple times, weren’t salvageable, he said. Warren hasn’t been involved in litigation himself but expects more legal action to occur in the region moving forward, even though cases can be costly and take several years to resolve.

51 Wells

Already, a study by the Oklahoma Energy Producers Alliance, the group representing conventional drillers, has found 451 vertical wells in one county that were negatively affected by horizontal drilling, 80 percent of which were located outside of horizontal well unit boundaries.

The damage can add costs to replace equipment, clean out water or sand, or address environmental damage, according to Mike Cantrell, a board co-chair for the group. It can also kill a well outright, he said.

“I’m afraid when we look into further, we’re going to find out it’s much worse,” he said.

Horizontal drilling has allowed producers to tap into shale reserves more economically. When explorers tap shale, they are actually drilling into the rocks where the oil feeding those old-line vertical wells was created. Geologists refer to it as “source rock.” The technique allows drilling to continue laterally for up to two miles, replacing the need for multiple vertical wells. Kingfisher County, where Warren’s well are largely located, is part of the so-called Scoop and Stack region, where drilling has increased since the oil slump.

Oil rigs in that area’s Cana Woodford basin have climbed to 62 from 36, just since the start of the year.

Many of the vertical well most affected are so-called stripper wells, which produce a daily average of 15 barrels of oil or less. Though they may be inconsequential to large companies, for small operators, it’s a matter of their livelihood, Cantrell said.

In August, a district court ordered Devon Energy Corp. to pay $220,000 after two operators alleged negligence and “subsurface trespass” that led to two damaged wells. Devon inherited the wells in question from Felix Energy LLC, according to the company.

‘Safe and Responsible’

“Devon always seeks to conduct its operations in a safe and responsible manner, with respect for the rights of other well operators,” spokesman John Porretto said in an emailed statement. “When evidence shows that Devon’s operations may have damaged an existing vertical well, Devon is proactive in attempting to negotiate fair compensation for the affected vertical well owner.”

The company also noted, “the jury awarded the vertical well owner an amount that was both significantly lower than what was demanded at trial and less than what Devon had previously offered the well owner as compensation to settle the claim.”

The case belies a broader problem, said Matt Skinner, public information officer at the Oklahoma Corporation Commission, a regulatory body. The agency tried and failed to require operators to report incidents even if they didn’t cause environmental damage, he said, but couldn’t get support from bigger players in the industry. As a result, companies are not required to report incidents that result only in monetary damage to a well. Those issues must be taken to district court.

The main obstacle has been a lack of data, according to Skinner. So now, the commission is focusing on encouraging vertical well operators to report problems. They’ve confirmed 20 incidents and have at least 55 more pending, Skinner said.

“We know it’s happening, we know it’s an issue,” he said. “We have every reason to think there are more incidents out there than we know of.”

Cantrell’s organization, meanwhile, is pushing to slow down further development of horizontal drilling until better data is gathered on their effect on existing wells.

“We need to slow this process down until we can get the regulatory regime to keep up with it,” he said. “We’ve applied a vertical regulatory regime to a horizontal world.”

 

News Source: Rigzone

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CNBC/2 October 2017

• Citigroup’s Ed Morse says the oil price rally is “for real” and is being driven by fundamentals and financial positioning.
• Citigroup’s fourth-quarter price target for U.S. crude is $54 a barrel.
• Natural gas prices could rise to $3.70 per mmBtu by the end of the winter, Morse added.
• Morse is the well-known global head of commodities research at the bank.

Oil prices were in retreat on Monday following a big surge into the end of the third quarter, but Citigroup’s Ed Morse still has faith the market can keep rallying.

“We think it’s for real,” the global head of commodities research told CNBC on Monday. “We’re in the middle of a bit of a sell-off, maybe even testing the $50 level for WTI, but the sell-off is profit-taking more than anything else, and the momentum in the physical markets, joined by the momentum in the financial markets, really point to a higher price between now and the end of the year.”

On Monday, WTI fell towards $50 a barrel, while Brent slipped below $56. Citigroup’s forecasts call for U.S. West Texas Intermediate crude of $54 a barrel for the fourth quarter, and $58 a barrel for Brent crude, the international benchmark.

That would mark a divergence from the historical trend. U.S. crude oil more often than not falls in the final three months of the year, according to a study performed by CNBC using hedge fund analytics tool Kensho.

U.S. WTI year-to-date performance, source: FactSet

Energy markets are going to be “in the driver’s seat” for the rest of the year after metals and other commodities led the rally in the first two months of the third quarter, Morse said. Commodities closely linked to China’s economy are now ceding the way to the oil market, where the market is tightening after three years of oversupply, he said.

Crude stockpiles in the OECD, a group of mostly developed countries, have recently fallen toward the five-year average as OPEC, Russia and other oil producers cut production to drain a global glut. They stood about 190 million barrels above that level in July, according to the International Energy Agency.

“We’re seeing inventories draw,” Morse said. “Finally, the market is recognizing that these draws in inventories of products and crude oil combined are for real and they’re going to last through the end of the year. Maybe next year is a different story, but this year looks quite positive from now until the end of December.”

As for natural gas, Morse said Citigroup would not be surprised to see prices at $3.70 per million British thermal unit by the end of winter. The current price is $2.91 per mmBtu. Natural gas prices rise in the winter as heating demand rises.

Henry Hub natural gas 1-year performance, source: FactSet

After that, it depends on when pipelines are completed to alleviate takeaway constraints in key producing regions like Appalachia’s Marcellus Shale and the Permian Basin in western Texas and southeastern New Mexico.

“We don’t see much in the way of incremental pipeline, particularly from the northeast, coming into the market until late in 2018, so we think we’re in a relatively tight position until then,” he said.

 

News Source: CNBC

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Rigzone/2 October 2017

(John Kemp is a Reuters market analyst. The views expressed are his own)

LONDON, Oct 2 (Reuters) – The U.S. Energy Information Administration (EIA) is distorting oil prices by being far too optimistic in its forecasts for U.S. production, according to Harold Hamm, the chief executive of Continental Resources.

Hamm, who also chairs the Domestic Energy Producers Alliance (DEPA), a lobbying group, blames EIA for both the outright decline in U.S. oil prices and their underperformance compared with Brent since June.

Hamm faults EIA for being too optimistic about U.S. production, creating an impression there will be surplus of crude and depressing futures prices for West Texas Intermediate (WTI).

EIA currently forecasts U.S. crude production will climb to 9.69 million barrels per day (bpd) by December while DEPA predicts output will total no more than 9.35 million bpd (http://tmsnrt.rs/2yiw1gq).

“They need to get it right. If they don’t we see distortion happen. And we are seeing distortion happen right now,” Hamm said in an interview with Argus (“Continental CEO says EIA forecast caps WTI”, Sept. 27).

“The Brent-WTI spread is a good example. Here we are, within two months or three suddenly down to Brent by $6 per barrel … Certainly the two ought to be within a dollar or two,” he complained.

“Right here I see just if this correction is made and if the market realizes where we really are in America, I think there is a 20 percent adjustment (in prices) due right now.”

Hamm reiterated his view that prices below $50 are not sustainable and producers would need prices closer to $60 to meet rapidly growing global demand.

WTI-Brent Discount

So is Hamm right to blame EIA for the decline in WTI prices and the big discount to Brent which emerged in the third quarter of 2017?

The relationship between front-month WTI and Brent prices was fairly stable between January and June, with WTI trading at a discount of around $2. As recently as June 30, WTI was trading at a discount of just $1.88.

Since then, however, the discount has widened consistently to reach $6.80. On Sept. 25, U.S. producers were receiving just $52.22 for benchmark crude while their counterparts in the North Sea were realising $59.

The gap hurts for U.S. shale firms, many of which are under intense pressure from shareholders to improve their profitability.

But it is not obvious that the market has reacted to EIA forecasts or that the agency should be blamed for the weakness of WTI.

There has been little change in EIA forecasts since June. In fact, EIA has recently trimmed its predictions for output in both 2017 and 2018.

Onshore Output

Hamm’s critique relates changes in drilling and completion rates to the whole of U.S. crude output, which he predicts will reach no more than 9.35 million bpd by the end of 2017 from 9.24 million bpd in July.

But drilling rates really only affect the onshore component of production rather than the more specialised and technically complex production from Alaska and offshore.

EIA forecasts production from the Lower 48 states excluding the Gulf of Mexico will average 7.08 million bpd in 2017.

The agency predicts Lower 48 output will reach 7.45 million bpd in December, which does not seem unreasonable given output was 7.05 million in July and had already climbed from 6.5 million at end-2016.

The rest of U.S. output comes from Alaska and the federal waters in the Gulf of Mexico, which produced 423,000 bpd and 1.8 million bpd in July respectively.

Both areas experienced production outages during the second quarter, which lowered output by 63,000 bpd and 123,000 bpd respectively between March and June.

But EIA is predicting both will boost output by December by 40,000 bpd and 100,000 bpd, which should ensure total U.S. output continues rising through the end of the year.

Drilling Slowdown

Hamm blames the agency for being slow to react to the slowdown in drilling and well completions that started in the second quarter.

“We knew that production is not growing like the EIA is saying. It was coming down. Rig count was turning over and so were well completions,” Hamm told Argus.

DEPA surveyed all the publicly reporting oil and gas companies that reported in the second quarter and found that capital expenditure and production forecasts had been cut.

But the rig count and well completions declined precisely because of the drop in oil prices from late February onwards.

If WTI prices had not fallen from their peak in late February, it is likely that drilling rates would have continued climbing.

The fall in WTI prices was a necessary signal to ensure domestic oil producers changed their drilling and production plans.

Experience shows drilling and completions typically respond to a fall in WTI prices with a delay of around 16-20 weeks.

In response to the decline in prices after February, the frenzied drilling boom began to moderate during the second quarter.

But the rig count did not actually flatten out and begin falling until late July or early August, according to oilfield services firm Baker Hughes.

Production tends to follow changes in drilling with a lag of up to six months, so the rise in drilling until June is likely to continue increasing output through the end of 2017.

Based on the rising rig count during the first six months of the year, it is not unreasonable for EIA to predict U.S. oil production will continue growing through year-end.

Well Completions

There has been a notable slowdown in onshore well completions, as Hamm noted, which does seem to be moderating production despite the earlier drilling boom.

The phenomenon is most pronounced in the Permian Basin, where the number of wells drilled per month increased from 373 in January to 488 in August, but completions were up from just 242 to 353.

The result is a lengthening backlog of drilled but uncompleted wells (DUCs), which has grown from 1,500 in January to almost 2,300 in August, according to EIA.

Some completions have been deferred by companies hoping for an increase in oil prices while others are waiting because of a shortage of fracking crews and equipment.

If the slowdown in completions is sustained, it will moderate the increase in onshore oil production in the remainder of 2017.

But the slowdown in completions is itself mostly a response to the decline in WTI prices during the second and third quarters.

EIA should not be blamed for price declines which was a necessary market signal to tame the drilling and completion boom and adjust U.S. oil production to a more sustainable course.

 

News Source: Rigzone

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Rigzone/2 October 2017

BAGHDAD, Oct 2 (Reuters) – Islamic State militants set fire to three oil wells near Hawija, west of the oil city of Kirkuk, one of two areas of Iraq still under their control, military and oil officials said on Monday.

Iraqi security forces were using bulldozers to control the fires started by the militants in the early hours of Saturday to slow the advance of U.S.-backed Iraqi forces and Shi’ite militia groups toward Hawija town, military officials said.

The Allas oilfield, 35 km (20 miles) south of Hawija, was one of the main sources of revenue for Islamic State, which in 2014 declared a caliphate in parts of Syria and Iraq.

“Terrorists are trying to use the rising smoke to avert air strikes while retreating from the area towards Hawija,” said army Colonel Mohammed al-Jabouri.

Military officials said the fire had been brought under control at one of the wells, while the other two were still burning. They said it would take about three days to put out the fires.

Oil officials from the state-run North Oil Company said it was still too risky to send its crews in to assess damage at the wells as militants may have left bombs and landmines.

Iraq launched an offensive on Sept. 21 to dislodge Islamic State from Hawija.

Islamic State, the ultra-hardline Sunni Muslim group, has lost control of all the oilfields it once controlled in the north of Iraq.

 

News Source: Rigzone

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Rigzone/2 October 2017

(Bloomberg) — BHP Billiton Ltd. is getting closer to drilling its first oil wells in Mexico’s deep waters.

The Australian mining giant, which last year won rights to partner with state-owned Pemex in the Gulf of Mexico’s Trion field, hopes to have a drilling rig contracted this year and to spud two wells in the second half of 2018, Steve Pastor, BHP’s petroleum president, said Monday in an interview in Mexico City. Trion, which Pemex estimates to hold the equivalent of 485 million barrels of crude, could become one of the Gulf’s largest oil-producing areas, he said.

“There are four locations that we’ve identified already as having exploration potential,” Pastor said. “It’s a big block that has a number of follow-on exploration opportunities across the rest of the block. Big fields tend to get bigger with time.”

BHP is in talks with several international and Mexican contractors about providing the drilling rig and expects to announce a winner before the end of this year, he said.

The company has also qualified to bid in Mexico’s Jan. 31 crude auction for 29 deep-water areas and a joint venture with Pemex at its Nobilis-Maximino field. BHP is looking “very closely” at the geologic formations in Nobilis-Maximino, Pastor said.

BHP also sees development opportunities in Mexico in the “minerals and mining sectors, particularly in terms of copper,” Pastor said, adding that talks “are not all that advanced” at this stage.

The country is keeping an eye on Mexico’s 2018 presidential race and feels the country’s energy overhaul will proceed regardless of who is elected next June, Pastor said.

“The direction that Mexico is taking has been tremendously positive, and I hope it will continue,” he said. “I firmly believe that whoever wins will support the progression of the reform.”

 

News Source: Rigzone

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Rigzone/2 October 2017

SINGAPORE, Oct 2 (Reuters) – Noble Group Ltd (NGL) expects to sell its oil liquids business by the end of December as part of a plan to slim down drastically and focus on its core Asian coal trading business after a crisis-wracked two years.

“NGL continues to progress the sale of its Global Oil Liquids business. NGL currently expects the sale of the Global Oil Liquids business to complete by 31 December 2017,” the Singapore-listed company said in a statement on Monday.

In September, Chairman Paul Brough told shareholders that the company had received second round bids for the business and expected to announce a deal before the end of the month.

The company did not give any reason for the delay in the sale.

Once Asia’s biggest commodities trading house, Hong Kong-based NGL is slashing jobs and selling assets to shrink debt.

NGL flagged the sale of the capital intensive oil liquids business in July after agreeing to sell its North American gas and power business to rival Mercuria Group. On Monday, it said it had completed the sale of the gas and power business.

Reuters had reported that Mercuria Group, Vitol Group, U.S.-based Castleton Commodities International and Freepoint Commodities were among the interested parties for Noble’s oil business.

NGL previously said North American lenders to the company had extended the deadline for a $2 billion credit facility by three months to Jan. 15.

 

News Source: Rigzone

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Rigzone/2 October 2017

SAN JUAN, Puerto Rico, Oct 2 (Reuters) – Puerto Rico Governor Ricardo Rossello reported progress in getting fuel supplies to the island’s 3.4 million inhabitants on Monday as they faced a 13th day largely without power after the U.S. territory was devastated by Hurricane Maria.

“We’ve been increasing the number of gas stations that are open,” Rossello said at a news briefing, with more than 720 gas stations now up and running.

Puerto Rico relies on fuel supplies shipped from the mainland United States and distribution has been disrupted by the bad state of roads.

“We will be receiving more fuel supplies in the coming days,” said Rossello, who is expecting some 300,000 barrels of diesel on Wednesday and 100,000 barrels of gasoline. Within the next couple of days, he expects 500,000 barrels of diesel and close to 1 million of gasoline to arrive on the island.

“The flow is coming, gasoline is getting here,” he said. “We have been able to reduce the time that it takes to get gasoline and diesel at different stations.”

Food and drinking water still are in short supply and power remains down for most of Puerto Rico’s inhabitants nearly two weeks after the fiercest hurricane to hit the island in 90 years.

Some islanders got their cell phone service back on Sunday while others gathered at bars for drinking and dancing after the dry law was lifted this weekend.

Rossello said 8,800 people now were housed in 140 shelters. There were as many as 500 shelters in operation 10 days ago.

He said 47 percent of water and sewer service is up but there is variation across the island.

Federal and local authorities were working together to keep 50 hospitals operational and Rossello added that the U.S. Navy hospital ship Comfort would arrive in Puerto Rico between Tuesday and Wednesday.

U.S. President Donald Trump, who plans to go to Puerto Rico on Tuesday, defended his administration’s handling of the disaster on Sunday.

“We have done a great job with the almost impossible situation in Puerto Rico,” he posted on Twitter. “Outside of the Fake News or politically motivated ingrates people are now starting to recognize the amazing work that has been done by FEMA and our great Military.”

Earlier, Trump attacked San Juan Mayor Carmen Yulin Cruz on Twitter after she criticized the administrations response to Maria.

Insurers and reinsurers continued to count the cost of hurricanes this season. Lloyd’s of London underwriter Hiscox Ltd estimated on Monday that it would face net claims of about $225 million from hurricanes Harvey and Irma.

The Lloyd’s of London insurance market has forecast that it expects net losses for the market of $4.5 billion from the two hurricanes.

Maria alone could ultimately cause $15 billion to $30 billion in insured losses, including business interruption, according to risk modeling firm RMS. AIR Worldwide put the number at $40 billion to $85 billion.

With another two months of the Atlantic hurricane season to go, 2017 could end up as the most expensive year ever for insurers and reinsurers, if the final tally exceeds the $143 billion in losses from 2011, the year a massive earthquake and tsunami hit Japan.

 

News Source: Rigzone

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