TIME energy

Oil Council: Shale Won’t Last, Arctic Drilling Needed Now

Arctic Oil Drilling
Al Grillo—AP In this 2007 file photo, an oil transit pipeline runs across the tundra to flow station at the Prudhoe Bay oil field on Alaska's North Slope.

A new study from the Energy Department advisory council says the U.S. should begin Arctic drilling

(WASHINGTON) — The U.S. should immediately begin a push to exploit its enormous trove of oil in the Arctic waters off of Alaska, or risk a renewed reliance on imported oil in the future, an Energy Department advisory council says in a study to be released Friday.

The U.S. has drastically cut imports and transformed itself into the world’s biggest producer of oil and natural gas by tapping huge reserves in shale rock formations. But the government predicts that the shale boom won’t last much beyond the next decade.

In order for the U.S. to keep domestic production high and imports low, oil companies should start probing the Artic now because it takes 10 to 30 years of preparation and drilling to bring oil to market, according to a draft of the study’s executive summary obtained by the Associated Press.

“To remain globally competitive and to be positioned to provide global leadership and influence in the Arctic, the U.S. should facilitate exploration in the offshore Alaskan Arctic now,” the study’s authors wrote.

The study, produced by the National Petroleum Council at the request of Energy Secretary Ernest Moniz, comes at a time when many argue the world needs less oil, not more. U.S. oil storage facilities are filling up, the price of oil has collapsed from over $100 a barrel to around $50, and prices are expected to stay relatively low for years to come. At the same time, scientists say the world needs to drastically reduce the amount of fossil fuels it is burning in order to avoid catastrophic changes to the earth’s climate.

The push to make the Arctic waters off of Alaska more accessible to drillers comes just as Royal Dutch Shell is poised to restart its troubled drilling program there. The company has little to show after spending years and more than $5 billion preparing for work, waiting for regulatory approval, and early-stage drilling. After assuring regulators it was prepared for the harsh conditions, one of its drill ships ran aground in heavy seas near Kodiak Island in 2012. Its drilling contractor, Noble Drilling, was convicted of violating environmental and safety rules.

Environmental advocates say the Arctic ecosystem is too fragile to risk a spill, and cleanup would be difficult or perhaps even impossible because of weather and ice.

“If there’s a worse place to look for oil, I don’t know what it is,” says Niel Lawrence, Alaska director for the Natural Resources Defense Council. “There aren’t any proven effective ways of cleaning up an oil spill in the Arctic.”

But global demand for oil, which affects prices of gasoline, diesel and other fuels everywhere, is expected to rise steadily in the coming decades — even as alternative energy use blossoms — because hundreds of millions of people are rising from poverty in developing regions and buying more cars, shipping more goods, and flying in airplanes more often.

In order to meet that demand and keep prices from soaring, new sources of oil must be developed, the council argues. The Arctic is among the biggest such sources in the world and in the U.S.

The Arctic holds about a quarter of the world’s undiscovered conventional oil and gas deposits, geologists estimate. While the Russian Arctic has the biggest share of oil and gas together, the U.S. and Russia are thought to have about the same amount of crude oil — 35 billion barrels. That’s about 5 years’ worth of U.S. consumption and 15 years of U.S. imports.

The council’s study acknowledges a host of special challenges to drilling in the Arctic, including the sensitive environment, the need to respect the customs and traditions of indigenous peoples living there, harsh weather and sea ice.

But the council, which is made up of energy company executives, government officials, analysis firms and nonprofit organizations, says the technology and techniques needed to operate in the region are available now, and the industry can safely operate there. The report contends the industry has developed improved equipment and procedures to prevent a spill and clean up quickly if one occurs.

The council makes a number of suggestions designed to make U.S. Arctic development more feasible. They include holding regular sales of drilling rights, extending the amount of time drillers are allowed to work each year, and doing more scientific studies of the wildlife in the region to ensure it is disturbed as little as possible.

“It’s important to have good information to make these decisions,” says Jason Bordoff, director of Columbia University’s Global Energy Policy. “We need to make sure we’re doing this in the right way.”

TIME energy

Oil Markets Blow Yemen Crisis Out of Proportion

Shiite rebels, known as Houthis, gather to protest against Saudi-led airstrikes in Sanaa, Yemen, on March 26, 2015.
Hani Mohammed—AP Shiite rebels, known as Houthis, gather to protest against Saudi-led airstrikes in Sanaa, Yemen, on March 26, 2015.

There's no need for markets to overreact as Yemen is not a significant player in the oil industry

Saudi Arabia launched airstrikes in Yemen, causing oil prices to jump on fears over Middle East instability.

The markets clearly reacted with concern over the rising violence in the Arabian Peninsula, which pits Saudi Arabia against Iran in a proxy war. Saudi Arabia is targeting Shia rebels seeking to topple the Saudi-backed Yemeni government. Reuters reports that Saudi bombs targeted an airport and airbase held by the Houthis, which seized Yemen’s capital of Sanaa last September.

“We will do whatever it takes in order to protect the legitimate government of Yemen from falling,” Adel al-Jubeir, the Saudi ambassador to the United States, said in Washington DC. A Saudi official told Reuters that a “land offensive might be needed to restore order.”

The conflict involves a convoluted set of regional rivalries. The U.S. is supporting Saudi Arabia with “logistical and intelligence support.” Iran has denounced Saudi Arabia’s attack. The United Arab Emirates has denounced Iranian influence in the region. Meanwhile the U.S. and Iran find themselves on the same side with their attacks on ISIS in Iraq, although their campaigns are not coordinated.

Read more: Forget Rig Counts And OPEC, Media Bias Is Driving Oil Down

The overnight surprise attack by Saudi Arabia caused oil prices to spike. WTI has surged over $50 for the first time in several weeks. Oil prices are now up 13 percent in the last week alone. The surge comes amid growing concerns of oil overflowing storage tanks in the U.S. and around the world, which threaten a new round of weakness in oil prices.

But oil markets have a tendency of becoming swept up by unforeseen geopolitical events. Oil traders are apparently concerned about Yemen’s instability sucking in one of the world’s largest oil producers.

However, the markets are overreacting. Yemen is a negligent oil producer, and any disruption to its output would hardly be noticed on the global market. Not only does Yemen produce very little oil, but its production has been declining for much of the last 15 years. Yemen is now producing less than 150,000 barrels of oil per day, or around one-twentieth of what the state of Texas produces each day.

Not only that, but Yemen has been rife with conflict for quite some time. There were somewhere between 10 and 24 major attacks on oil and natural gas pipelines in Yemen in 2013. The Houthis seized control of much of Sanaa months ago in what has been labeled a “half-coup.” Violence at the bottom of the Arabian Peninsula is not new.

Read more: Wall Street Losing Millions From Bad Energy Loans

Perhaps the markets are concerned over Yemen’s strategic location? Yemen is a neighbor to the most important oil producer in the world, and is also located along the oil trading chokepoint of Bab el Mandeb, a sliver of water that connects the Red Sea to the Gulf of Aden. In other words, it connects oil tankers from the Mediterranean to the Indian Ocean. An estimated 3.8 million barrels of oil travel through these narrow straits each day.

Read more: Natural Gas Prices To Crash Unless Rig Count Falls Fast

While, in theory, violence could lead to a supply disruption at the 18-mile wide strait, that is highly unlikely to happen. After all, the U.S. Navy routinely patrols the region. Moreover, Houthi rebels do not exactly have a strong maritime presence. The violence will likely remain onshore.

That means that after the initial shock of Saudi Arabia’s attack wears off, oil prices will likely pare back their gains as traders focus on the fundamentals that have kept them up at night in recent weeks. Crude oil storage at Cushing is three-quarters full. China’s strategic petroleum reserve is nearly full. U.S. refineries are temporarily closing for Spring maintenance. All of these things will push the price of oil back down. That has to be weighed against falling rig counts and perhaps the beginning of oil production declines in several key shale areas in the United States.

The violence in Yemen is very much a serious geopolitical and humanitarian concern, but unless the conflict between Saudi Arabia and Iran transforms from a proxy war into a broader and more direct military clash, there is little justification for oil markets to be so rattled.

This article originally appeared on Oilprice.com.

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Airlines Keep Fuel Savings for Themselves

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As long as flights are full, there’s no incentive for airlines to cut prices

On Dec. 14, Oilprice.com looked at how the drop in the price of crude was affecting air fares. While motorists were enjoying low pump prices, we found, air travelers were paying the same for a ticket as they were before the oil slump.

That was attributed to airlines’ practice of buying backlogs of jet fuel at older, higher prices long before the price of oil started falling, as well as their efforts to reinvest in themselves to improve operations.
The conclusion was that for 2015, the price of a barrel of oil would rebound to around $80 per barrel, and that fares would drop once the airlines used up all they oil they bought back when crude cost more than $110 per barrel.

That report also mentioned consolidation – mergers – which have a tendency to reduce competition and so allow airlines to set prices with a reduced fear of being undersold. And that turns out to be where air fares stand nearly three months into 2015. In the United States, for example, there remain only four major airlines: American-US Airways, Delta, Southwest and United.

Read more: T. Boone Pickens Points The Finger At U.S Shale

This is not a recipe for fierce competition. In fact, Vinay Bhaskara, an industry analyst, writes in Airways News, “We are unquestionably living with an air travel oligopoly.”

As before, the fuel savings are going into reinvestment in the airlines and, understandably, rewarding investors who have spent years earning little from airline stocks when fuel prices were high. But the people who actually pay the fares are still being left out.

“In the short-term, the answer is: There really is no benefit for the consumer,” Jeff Klee, CEO of CheapAir.com, an California-based online travel agency, told The Guardian. “[A]irlines don’t price their flights based on their cost. In the short term, they price it based on demand.

Read more: Beyond Iran And Pakistan: 7 Nuclear Wannabes

“Unless demand changes, just because [airlines are] paying less [for fuel], they’re not going to pass that savings on unless they have to,” Klee said. “And they don’t right now. People are traveling and the flights are full.”

That view isn’t universal, though. For example, the International Air Transport Association (IATA), a global airline representative, says air fares are likely to drop by 5.1 percent in 2015 from the previous year. And that’s backed up by Orbitz.com, the Chicago-based travel website. So far this year, it says, air travel prices globally have dropped by 3 percent compared with the same period in 2014.

But none of the savings comes from the four major American airlines left standing. And that has consumer groups demanding that lower fuel costs be passed on to customers.

Read more: Natural Gas Prices To Crash Unless Rig Count Falls Fast

“We have seen six months of steadily dropping [fuel] costs,” said Paul Hudson, president of FlyersRights.com, in a letter calling for lower fares. “By any measure, the money saved by airlines should be reflected in lower airfares.”

Bijan Vasigh, Professor of Economics and Finance at Embry-Riddle Aeronautical University in Daytona Beach, Fla., says it’s too soon to forecast the direction of air fares for this year, but adds, “I’m not really optimistic.”

The key, Vasigh says, is competition, something that is supposed to be at the very core of a free market. But as long as flights are full, at least on U.S. airlines, he says, there’s no incentive for them to cut prices, regardless of the price of fuel.

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The Most Challenging Oil and Gas Projects in the World

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As easy oil runs out, drillers are forced to look in difficult places for new sources of oil

The fifth anniversary of the Deepwater Horizon disaster is approaching, but in the intervening years since the well blowout deep offshore, oil and gas drillers have pushed even deeper and even farther afield.

Oil exploration companies are hitting the pause button in 2015 due to the bust in prices and the supply glut, and may not take on massive new projects. But over the long-term, in order to boost flagging production, the oil majors’ directive is pretty clear. A lot of the “giant” oil fields are mature and declining while fewer and fewer are being discovered each year to replace depleting output. As easy oil runs out, drillers are forced to look in difficult places for new sources of oil.

Read more: Three Triggers That Will Send Oil Crashing Again

Here’s a look at several of the most challenging oil projects currently underway around the world.

Kearl Oil Sands

One of the largest and most expensive oil sands projects, Kearl has been a logistical challenge to say the least. It holds an estimated 4.6 billion barrels of oil. The open-pit mining operation is supposed to produce 345,000 barrels per day, but has experienced equipment malfunctions and setbacks, and production has run well low of what Imperial Oil, the project’s lead operator, had planned. The facility had to be temporarily shut down in late 2014 because of failed equipment. To build the operation, equipment had to be shipped from Asia to the United States, and then broken up so that they could be transported on highways through Montana and Idaho. The equipment then had to be broken up into even smaller loads because of public opposition to the convoys of trucks moving through those states. Delays and cost overruns have bedeviled Imperial, but it is pushing on with an expansion of Kearl, despite low oil prices. The project has now cost more than $20 billion.

Read more: The $6.8 Billion Great Wall Of Japan: Fukushima Cleanup Takes On Epic Proportion

Ichthys

Located 220 kilometers off of Western Australia, Ichthys is “effectively three mega-projects rolled into one,” says Inpex, the Japanese oil company heading up the project. It involves offshore drilling for natural gas, processing onboard ships located at the sea surface, and liquefaction onshore for LNG export. The project will cost $34 billion and involves the longest natural gas export pipeline in the southern hemisphere. Scheduled to begin in 2016, the Ichthys will allow for the export of 8.4 million tons of LNG each year, which could account for nearly 15 percent of Australia’s LNG export capacity.

Stones

Royal Dutch Shell is in the midst of developing the deepest offshore oil field in the world, not too far away from the Macondo well in the Gulf of Mexico. Located 9,500 feet below the sea surface – or around twice as deep as the Macondo well – Shell’s “Stones” project will target the lower tertiary, one of the last frontiers in oil exploration. The lower tertiary is a geological formation that is ultra-deep, and its oil reservoirs tend to be mixed with sand and located beneath thick layers of salt. Shell will build subsea production facilities that tie back to a floating production, storage, and offloading (FPSO) vessel, Shell’s first in the Gulf of Mexico.

Read more: Low Prices Help Arctic Avoid A ‘Gold Rush’ Scenario

Kashagan

The massive oil and gas field in the Caspian Sea has become the most expensive oil project in the world and is perhaps the most technically daunting. Originally discovered in 2000, the project was billed as the largest oil discovery in decades. It is the fifth largest field in the world by reserves, and the largest outside of the Middle East. Despite the alluring bounty, the project has turned into a nightmare for the consortium of companies involved, which includes Eni, ExxonMobil, Royal Dutch Shell, Total, and the Kazakh government-owned oil company. Dubbed by The Economist as “cash all gone,” Kashagan has been plagued with delays, cost overruns, and engineering difficulties. The consortium has had to build artificial islands, work through winter ice conditions, and drill at great depths and pressure. An official with the consortium has called Kashagan “one of the largest and most complex industrial projects currently being developed anywhere in the world.”

But perhaps the most challenging is the “sourness” of the gas the companies are pulling out of the seabed. Production finally began in 2013, after an eight-year delay. However, just a few weeks later, operations were quickly shut down because the pipelines suffered from leaks. The problem is toxic hydrogen sulfide gas, which is corroding the pipelines. Fixing the pipes could tack on an additional $3.6 billion (or more) to the project, with production not set to resume until 2017. All told, the project will cost well north of $50 billion, with some estimates pegging the cost at nearly double that amount.

This article originally appeared on Oilprice.com.

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The National Power Grid Is Under Almost Continuous Attack, Report Says

Detroit
Jim Richardson—Getty

Perpetrators are rarely apprehended

The U.S. national power grid faces physical or online attacks approximately “once every four days,” according to a new investigation by USA Today, threatening to plunge parts of the country into darkness.

For its report, USA Today scrutinized public records, national energy data and records from 50 electric utilities.

It found that from 2011 to 2014, the U.S. Department of Energy received 362 reports from electric utilities of physical or cyber attacks that interrupted power services. In 2013, a Department of Homeland Security branch recorded 161 cyber attacks on the energy sector, compared to just 31 in 2011.

Worryingly, most of the nation’s power infrastructure has poor defenses — sometimes only a security camera and fence. In April 2013, PG&E Corp’s Metcalf Transmission Substation in California reported that over 100 ammunition rounds were fired into its transformers, causing over $15 million worth of damage. The gunmen were never apprehended — neither have the perpetrators of over 300 physical attacks on electricity infrastructure since 2011.

Read more at USA Today.

TIME energy

Low Oil Prices Help Arctic Avoid a ‘Gold Rush’ Scenario

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The Arctic remains a "vulnerable area" with strong environmental rules

The plunging price of oil over the past nine months has forced many if not most energy companies to cut back drastically on spending, especially on projects in Arctic waters, where exploration and drilling are more difficult and expensive. But the Norwegian government says such delays could pay off in the long run.

The list of companies paring back their plans is long, and exploration in the Arctic Ocean north of Western Europe will decline by half in 2015.

One company is Lundin Petroleum of Sweden, which cites the plunge in oil prices for its plans to drill no more than four exploratory wells in the Barents Sea in 2015. Three other European companies – Vienna-based OMV, Germany’s Wintershall AG and Italy’s Eni – are committed to only one exploratory well each this year. In 2014 these companies together drilled 13 such wells, a record.

Read more: Is Rosneft The Best Buy On The Global Markets?

Meanwhile, Russia’s state-owned Rosneft and Norway’s state-owned Statoil are also drastically reducing plans for immediate investment in Arctic waters. In fact, Statoil has once again postponed any commitment to develop its Johan Castberg oil field in the Barents Sea because the high cost of the project at a time of low oil revenues.

The field is believed to hold between 400 million and 600 million barrels of oil, but would cost an estimated $15 billion to set up new facilities on Norway’s northern coast to develop it. Statoil says a decision on when to begin work on Johan Castberg won’t come any earlier than 2016, maybe 2017.

“We have made significant progress in reducing costs for Johan Castberg,” said Ivar Aasheim, the Statoil executive responsible for sanctioning projects in Norwegian waters. “However, current challenges in relation to costs and oil prices require us to spend more time to ensure that we extract the full benefit of the implemented measures.”

Read more: Big Changes Needed For Big Oil To Survive

As grim as the news may seem, Norwegian Foreign Minister Boerge Brende says these delays eventually may benefit Arctic oil exploitation by preventing a melee of exploration in an environmentally fragile region.

Brende told an Arctic conference in Oslo on March 12 that the region is heating up faster than most other areas of the Earth because of climate change, and that part of that heating can be attributed to the burning of gas, which emits fully half as much heat-trapping carbon dioxide as coal.

There have been expectations that the Arctic Ocean would soon be open to increased mining, energy exploitation and shipping, Brende said, but they turned out to be too optimistic. “We should be very happy that there was not a‘gold rush,’ ” he told reporters after his address to the Oslo conference. “A‘gold rush’ is not positive, it’s throwing oneself at resources at breakneck speed.

Read more: The Easy Oil Is Gone So Where Do We Look Now?

“The Arctic is a very vulnerable area where we have to go step by step,” he said, being careful to apply strong environmental rules.

Nevertheless, Brende said, “It is safe to assume that Arctic gas will have its day,” because oil and gas will continue to supply the majority of the world’s energy for the foreseeable future and that the Arctic will continue to be a key source of these fossil fuels.

This article originally appeared on Oilprice.com.

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No Country for King Coal — the Changing U.S. Energy Mix

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Coal’s decline contrasts strong growth among non-hydro renewables like wind and solar

As of late last year coal formed the backbone of U.S. electric generation capacity. At a share of roughly 39 percent, it still does. However, the U.S. energy mix is rapidly changing and coal is past its peak.

In 2015, the U.S. is expected to retire nearly 13 gigawatts (GW) of coal-fired generation – three times more than last year. An additional 5.2 GW will be retired in 2016. The Environmental Protection Agency’s Mercury and Air Toxics Standards (MATS) are the primary cause of this year’s large-scale retirements. MATS are slated to enter into force by year’s end, and the retrofits necessary to meet the increased emissions standards are largely, and by design, cost-prohibitive.

Most of the closings, more than 8 GW, are centered in the Appalachian region. Hardest hit is Ohio – and some of its largest utilities, AEP and FirstEnergy – where approximately 2.4 GW is leaving the fold. Indiana and Kentucky round out the top three with closings of more than 2 GW and 1 GW respectively. Outside of Appalachia, the U.S.’ largest carbon dioxide emitter Southern Company will convert its 1.4 GW Yates plant to natural gas.

Read more: A “Wave of Bankruptcies” About To Hit Coal Industry

Coal’s current woes are well documented, but the industry – while dying – is far from dead. Simply put, you cannot replace almost 1.5 trillion kilowatthours of annual electricity generation overnight. For big coal, the looming retirements represent the lowest hanging – and lowest capacity – fruit. By 2040, coal is expected to account for approximately 21 percent, or 254.1 gigawatts, of electricity generating capacity – second only to natural gas.

Coal’s decline contrasts strong growth elsewhere – namely, among non-hydro renewables like wind and solar. Utilities expect to add over 20 GW of utility-scale generating capacity to the grid in 2015. Of that total, wind, solar, and natural gas additions will account for 91 percent.

Read more: Is China Exporting Its Pollution?

Since 2000, wind has been one of the fastest growing sources of new electricity supply and that trend will continue toward 2020. The industry expects to expand by more than 11 percent, or 9.8 GW, this year. Additions are planned across the nation, but the Plains states – from the Canadian border down to the Gulf – will see the bulk of new capacity. Per tradition, Texas will do it bigger. IKEA’s Cameron Wind project and Capital Dynamics’ Green Pastures development are just a fraction of the reported 7.5 GW of wind capacity currently under construction in Texas – already the nation’s largest producer of wind power.

Solar installations are largely limited to California, where new additions – 1.2 GW – are expected to account for more than 50 percent of the nationwide total for 2015. In fact, First Solar’s Desert Sunlight solar farm in the Mojave Desert – online as of February –will supply a quarter of this year’s new capacity. However, the real solar surprise comes out of North Carolina. The state, which has renewable portfolio standard policies in place, plans to add 0.4 GW to its approximately 1 GW of existing installed capacity. Leading the charge is Duke Energy, the state’s – and nation’s – largest electric power holding company. Duke recently announced investments of up to $225 million into commercial solar projects, which follows its $500 million commitment to North Carolina solar of late last year.

Read more: Renewables Poised For Massive Growth In The Middle East

The projected wind and solar capacity additions provide sufficient evidence that cheap oil – and cheap coal – won’t significantly alter steady renewables growth. Still, far lower utilization rates mean natural gas will replace much of the coal-fired losses in terms of pure generation. In all, natural gas will add 6.3 GW of generating capacity this year.

For now, gas is the bridge, but the jury is not out on its ultimate effectiveness. It’s actually quite dirty over its entire lifecycle and recent research suggests that a heavy blend of wind and coal may actually result in lower emissions than the current natural gas-based transition. That won’t work however, without steady congressional support for the production tax credit.

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The $6.8 Billion Great Wall of Japan: Fukushima Cleanup Takes on Epic Proportion

Tanks of radiation-contaminated water are seen at Tokyo Electric Power Co. (TEPCO)'s Fukushima Daiichi nuclear power plant in Fukushima, Japan on March 11, 2015.
Kyodo—Reuters Tanks of radiation-contaminated water are seen at Tokyo Electric Power Co. (TEPCO)'s Fukushima Daiichi nuclear power plant in Fukushima, Japan on March 11, 2015.

'The Great Wall of Japan' may be able to prevent future disasters, but the cleanup could take another forty years before it's complete

More than four years after the catastrophic tsunami that crippled several nuclear reactors in Fukushima, the Japanese utility that owns the site is struggling to deal with a continuous flood of radioactive water.

The tsunami knocked off power at the nuclear plant, which led to the meltdown of three of the six reactors, with a fourth severely damaged. The ongoing release of radioactive material has prevented anyone from entering parts of the complex.

But getting a handle on the mess, let alone permanently cleaning up the site, has been extraordinarily difficult. The problem is the daily flood of rainwater that flows downhill towards the sea, rushing into the mangled radioactive site. An estimated 300 tons of water reaches the building each day, and then becomes contaminated. TEPCO, the utility that owns the site, has been furiously building above ground storage tanks for radioactive water. Storing the water prevents it from being discharged into the sea, but this Sisyphean task does nothing to ultimately solve the problem as the torrent of water never ends. TEPCO has already put more than 500,000 tons of radioactive water in storage tanks.

Read more: France’s Areva Lost $5.6 Billion In 2014 – Is This The End?

To reduce the 300 tons of newly created radioactive water each day, TEPCO must cut off the flow of groundwater into the nuclear complex. To do that, it plans on building an ice wall that will surround the four reactors. TEPCO plans on building an intricate array of coolant pipes underneath the reactors, freezing the soil into a hardened ice wall that will block the flow of water. The ice wall will stretch one and a half kilometers around the reactors.

Great plan, except that it has never been done before. TEPCO may be able to freeze the soil, but there is no telling if it can build an ice wall without any holes that could allow water to seep into the reactor building. Questions surrounding the viability of the ice wall, and with it the prospects for halting the flow of radioactive water, heightened after TEPCO announced in mid-March that it was postponing the project.

Read more: China Builds Nuclear Reactors in Earthquake-Prone Pakistan

In fact, much of what TEPCO has to do to clean up the disaster area is daunting. TEPCO actually has to dig up radioactive soil and remove it, putting it in an interim storage facility. The idea is to make Fukushima inhabitable again, rather than indefinitely leave it as a radioactive and toxic no-go zone like the immediate surroundings of Chernobyl. When or if that can happen is anybody’s guess. The removal of radioactive soil began recently.

Another unnerving challenge is TEPCO’s plan to remove radioactive elements from contaminated water and then discharge the water into the Pacific Ocean, a plan that is facing enormous pushback. That’s because TEPCO has lost the trust of the public. Not only has the utility responded poorly to the cleanup, but it also recently admitted to not having publicly disclosed that a leak was resulting in radioactive water flowing into the ocean. TEPCO knew about the leak for more than ten months, one of a long line of acts of obfuscation that has enraged the Japanese public. The Japanese Nuclear Regulatory Authority gave its stamp of approval for dumping cleansed water into the ocean, but the fishing industry is hoping to block the plan, as many fishermen do not trust that the water TEPCO plans on dumping is in fact clean of radioactivity.

Read more: Middle East Oil Addiction Could Spell Disaster

The Japanese government hopes to prevent future nuclear meltdowns by constructing “The Great Wall of Japan,” a controversial $6.8 billion campaign to build around 440 sea walls along the coast to fend off tsunamis.

That may be able to prevent future disasters, but in the meantime the cleanup and decommissioning of the Fukushima nuclear power plant continues. It could take another forty years before the work is complete.

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Forget About Keystone XL — Canadian Crude Is Coming

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Oil producers and energy traders need to build a robust capability that can handle all that risk data efficiently

While Congress and the White House continue to wrangle over the Keystone XL pipeline extension, the oil industry is taking matters into its own hands.

Markets are primed for an influx of Canadian crude oil, but with pipeline transport off the table for the foreseeable future, producers have built alternative modes to meet the demand. The problem is, recent disasters have soured legislators and environmentalists on road and rail for moving oil.

Alongside political uncertainties are other wild cards like extreme weather and the unknowns that arise from an emerging logistics infrastructure, which can all impact the flow of goods. That makes the proposition of a non-pipeline solution particularly thorny. How should supply chain decision makers position to connect with premium energy markets, manage the attendant risks, while also addressing the strong likelihood of an increased regulatory burden?

Read more: Recent “Bomb Trains” Expose Regulatory Failures

From the source of the commodity to the end consumer, the ability to track Canadian oil assets in real-time is set to become more important than ever.

Boom Times For Oil Producers

Production from Canada’s oil sands is on the rise, with output expected to nearly double by 2030 to 6.7 million barrels per day. That accounts for about 98% of the country’s oil reserves.

Primary market opportunities exist in both Canada and the US, where replacements for offshore imports are desired. Getting the oil to premium and secondary markets however is another matter.

Considering the gooey consistency of Canada’s pure bitumen, rail makes sense as the main pipeline alternative. Rail transport doesn’t require dilution prior to shipping, as it does in pipeline transport; so shipping bitumen in its pure form would require fewer barrels. That creates an incremental netback on rail transport of about $6 per barrel, compared to pipeline processing.

Read more: Mystery Of The Adviser Who Turned Obama Against Keystone XL

Recent train derailments, however, have attracted public outcry in both countries for tighter controls. That means more regulation is likely, with stiffer compliance for all parties participating in the oil supply chain.

Despite those concerns, the Keystone delay has spurred producers to start shipping Canadian crude by truck, rail and barge. TransCanada, a major energy company based in Calgary has plans to build rail terminals in Alberta and Oklahoma. Exxon Mobil is also planning a new Canadian rail terminal, set for operation this year at a cost of about $250 million. Its completion would accommodate shipments of nearly 100,000 barrels per day.

How The Industry Should Respond

With Canadian crude assets traversing a complex, closely regulated and shifting supply chain, the question of how to effectively manage the risks inevitably pops up. Any process based on spreadsheets won’t be up to the task. They can’t keep up with the moment-to-moment churn of data required to manage activity and make good decisions.

Read more: Obama Called Out On Keystone Lies

How much inventory is at risk, where energy assets stand at any given time and the associated capital commitments, all need to traceable down to the carload — this is literally where the rubber meets the road. Unless systems and processes embrace the real-time, buy-sell-trade environment in oil, you will be hard pressed to react quickly enough when the inherent risks of Canadian crude positions raise their head.

Oil producers and energy traders need to build a robust capability that can handle all that risk data efficiently. That means integration of all the necessary partner and reporting data points. Maps, schematics, and trending data need to be presented graphically, with quick summaries of all active positions, assets and related histories. Given the shift to mobile working and BYOD, all the better if information can be accessed across the full range of devices and operating systems we use to conduct business.

Even with the recent market unrest, America’s appetite for energy is not diminishing. As supply lines for Canadian crude stretch across modalities, borders, time zones, weather patterns, regulatory regimes and market conditions, the ability to monitor assets from the wellhead to the marketplace is critical. Successful oil supply chain risk management will help managers capture the details of every Canadian crude purchase down to the penny, from the front office to the back.

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A ‘Wave of Bankruptcies’ About to Hit Coal Industry

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Both domestic coal consumption and foreign markets are shrinking at a worrisome pace

The future for the coal industry is looking “increasingly bleak,” according to an investor’s note from Macquarie Research. The analysis firm also said that “a wave of bankruptcies” appear to be just over the horizon as coal mining companies deal with mounting debt and a shrinking market.

The coal markets have collapsed in spectacular fashion over the last few years due to a perfect storm of factors. U.S. coal producers first had to compete ferociously with shale gas in America’s electric power sector as fracking took off about a decade ago. That forced an array of coal plants to shut down as cheap gas washed over the country. Subsequently a regulatory crack down from the federal government – including forthcoming restrictions on greenhouse gases – further dimmed the growth prospects of coal.

But U.S. coal producers always had the international market, and exports stepped up in concert with falling domestic consumption. Now the foreign buyers are shrinking as well. China, the one country that the coal industry could count on for ceaseless growth in coal consumption, actually burned 2.9 percent less coal in 2014 than it did the year before.

Read more: Is China Exporting Its Pollution?

When China, which consumes about as much coal as the rest of the world combined, sees its level of coal burning stay flat or even fall, that raises red flags for the entire industry.

There are two other major factors contributing to the coal bust. First, a flood of new coal mines came online around the world in the last several years, creating a glut on the international market. Second, China has implemented protectionist measures to guard its domestic coal mining sector. As a result, it saw a 22 percent decline in coal imports at the end of 2014 from a year earlier. This has exacerbated the global glut. Still, even Chinese coal companies are struggling – an estimated 7 out of 10 are not profitable.

Read more: A New Season Brings Big Changes In Energy

U.S. coal producers had predicted that the pain would be temporary and that coal markets would rebound. But that does not appear to be the case. In fact, U.S. domestic coal prices are at six-year lows, having declined to $45 per short ton this year, a nearly 20 percent drop off from 2014. Coal markets are also getting battered by the oil bust and broader decline in commodity prices, as well as the strong dollar, which makes exports less competitive. U.S. coal production is at its lowest level since 1993 and may decline even further.

Macquarie Research downgraded its projection for coal prices by $5 per ton, and said that the only way to bring the market back into balance was for capacity to be shut in.

Read more: Climate Security Pits US Military Against Congress

Even worse, investors are starting to abandon the industry. Peabody Energy, one of the larger coal producers, had to pay a 10 percent interest rate on its latest bond offering. Worse off companies may struggle even to access financing, forcing them to close up shop. Arch Coal and Alpha Natural Resources, for example – once prominent and stable coal producers – have seen their share prices plummet into penny-stock territory. The clouds are darkening over U.S. coal.

In the face of such dim prospects, Robert Murray of Murray Energy is hoping to defy the odds. He agreed to pay $1.4 billion to take over rival Foresight Energy, an Illinois coal operator. The combined company will make Murray Energy the third largest coal producer in the United States. However, to finance the deal, Murray will have to take on new debt, a risky move in such a depressed climate.

As Macquarie Research noted, the industry is shrinking. High cost producers are going to be forced out of the market. Murray plans to consolidate and survive by cutting costs – which he has done by skirting labor and environmental standards for quite a long time. But unless coal prices rebound, and there is not a good reason to think they will, Murray Energy may too be in for a grim future.

This article originally appeared on Oilprice.com.

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