Germany’s economic policy is hurting Europe, the world, and itself Business Insider  / The Economist

FROM Washington to Athens, politicians and economists who often have little in common all agree that Germany under Chancellor Angela Merkel is largely wrong about economic policy.

Germany’s apparent economic strengths–the lowest unemployment in two decades; steady, if low, growth; a balanced federal budget–mask weaknesses and policy errors, they say.

A first mistake is to insist that troubled euro-zone countries such as Greece not only make structural reforms to their economies, but simultaneously cut spending and borrowing (depressing demand).

But a second is domestic. Given low interest rates, now would be a golden opportunity to borrow and invest more at home, boosting the economy and providing a Keynesian stimulus to the entire sluggish euro zone. Instead, Germany is investing less than in the past and less than most other countries (see chart).

Raising investment could also deal with another imbalance in the German economy: its current-account surplus, the largest in the world, which has just set another record in 2014 of EUR220 billion ($250 billion), over 7% of GDP. By definition, this surplus measures the excess of savings over investment. Invest more, and the surplus would shrink or even disappear.

Such thinking has fans even in Germany. Marcel Fratzscher at the German Institute for Economic Research in Berlin thinks that German strength is an “illusion” given its large “investment gap”. Public investment in Germany–shared by the federal, state and local governments–has fallen from 6% of GDP in 1970 (in the West) to 2% now. Roads, bridges, broadband internet and much else could do with more money.

The German Marshall Fund has said that 40% of bridges in Germany are in “critical condition”. The Cologne Institute for Economic Research, another think-tank, reckons that the capital stock of German machines has not risen in real terms since 2008. Markus Kerber, director of the German Federation of Industries, a trade association, says that a “long-term investment-offensive is needed” to sustain growth.

But other German economists are sceptical about claims of underinvestment. Christoph Schmidt, chairman of the German Council of Economic Experts, which advises the government, thinks published ratios of investment as a percentage of GDP can be misleading when compared both across time and between countries.

France, for example, has a lot of public housing. Germany does not, and this skews the numbers. Reunification in 1990 caused a one-off investment boom in both parts of the country. And whereas other countries had property crashes, Germany did not. In that case, at least, skimping on housebuilding was sensible.

Yet the trend of declining public and private investment remains clear. A recalculation to fit European Union norms lifts Germany’s investment ratio from 17% to 19%, by including companies’ research and development spending. But that is still low. Why is this?

Most investing is done by private firms. But German ones have for years preferred to invest abroad, not at home. Mr Fratzscher regrets this: he reckons that German investment abroad has yielded an annual return of 10% over 20 years whereas foreign investment in Germany has made more like 15%.

The main reason for low domestic investment, says Michael Hüther, the Cologne institute’s director, is uncertainty and nervousness over the future. Continuing anxiety over Greece and the euro has been especially damaging.

More recently worries about Russia, which is more commercially entangled with Germany than with other big Western economies, have unsettled the business climate. But the biggest problem for many businessmen may be benighted government policies.

These start with Germany’s “energy transition,” a plan to exit simultaneously from fossil fuels and nuclear energy. The main policy is a huge subsidy to solar and wind. The surcharge that many firms have to pay on a unit of energy is larger than the entire cost of electricity paid by firms in America. Half the firms polled by Mr Hüther’s institute claim that this makes any new investment unattractive.

Many also complain, in a country that has an ageing, shrinking population, about a shortage of skilled workers despite Germany’s admired apprenticeship system. Mrs Merkel’s government, under the influence of her Social Democratic coalition partners, has made things worse by letting some workers retire at 63, rather than at 67, as previously envisaged.

In the housing market, owners are put off investment by a cap on rents in many cities. A new federal minimum wage is yet another measure that will add costs for business.

The best way to boost investment is to fix these policy errors, argues Mr Schmidt. On energy, even if the government insists on sticking to its emissions targets, it could leave the choice of technology to the market.

The pension age could be raised again; the minimum wage should be lower. And public investment should be raised. Gustav Horn, head of the Macroeconomic Policy Institute, part of a foundation with links to the trade unions, reckons that a 1% increase in euro-zone public investment would boost GDP by 1.6%.

Yet Germany led resistance to calls for more public money to be put into the European Commission’s planned investment programme. At home it is constrained by the constitutional “debt brake”, adopted in 2009, which requires state governments to balance their budgets by 2020 and the federal one to do so by 2016.

Wolfgang Schäuble, the finance minister, has beaten the timetable, balancing the budget in 2014. He and Mrs Merkel are proud of the “black zero”, which demonstrates that Germans sticks by the rules, as others should. The books may balance, but Germany is a long way from rectifying its investment shortfall at home.

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Tesla Planning Battery for Emerging Home Energy-Storage Market By Dana Hull and Mark Chediak – Feb 11, 2015, 10:48:18 PM

Tesla Planning Battery for Emerging Home Energy-Storage Market
By Dana Hull and Mark Chediak – Feb 11, 2015, 10:48:18 PM

(Bloomberg) — Tesla Motors Inc., best known for making the all-electric Model S sedan, is using its lithium-ion battery technology to position itself as a frontrunner in the emerging energy-storage market that supplements and may ultimately threaten the traditional electric grid.

“We are going to unveil the Tesla home battery, the consumer battery that would be for use in people’s houses or businesses fairly soon,” Chief Executive Officer Elon Musk said during an earnings conference call with analysts Wednesday.

Combining solar panels with large, efficient batteries could allow some homeowners to avoid buying electricity from utilities. Morgan Stanley said last year that Tesla’s energy-storage product could be “disruptive” in the U.S. and in Europe as customers seek to avoid utility fees by going “off-grid.” Musk said the product unveiling would occur within the next month or two.

“We have the design done, and it should start going into production in about six months or so,” Musk said. “It’s really great.”

Tesla already offers residential energy-storage units to select customers through SolarCity Corp., the solar-power company that lists Musk as its chairman and biggest shareholder. Tesla’s Fremont, California, factory is also making larger stationary storage systems for businesses and utility clients. The Palo Alto, California-based automaker has installed a storage unit at its Tejon Ranch Supercharger station off Interstate 5 in Southern California and has several other commercial installations in the field.

Utility Clients

But the even larger market may be utility clients.

“A lot of utilities are working in this space and we are talking to almost all of them,” Chief Technology Officer JB Straubel said on the earnings call Wednesday. “This is a business that is gaining an increasing amount of our attention.”

California sees energy storage as a critical tool to better manage the electric grid, integrate a growing amount of solar and wind power, and reduce greenhouse gas emissions. Utilities like PG&E Corp. are now required to procure about 1.3 gigawatts of energy storage by 2020, enough to supply roughly 1 million homes.

To contact the reporters on this story: Dana Hull in San Francisco at; Mark Chediak in San Francisco at

To contact the editors responsible for this story: Jamie Butters at Terje Langeland

Grid-Scale Storage: Smooth Operators

Business Insider/Economist

Matching output to demand is hard with wind and solar power. The answer is to store surplus juice on the grid until it is needed

ON OCTOBER 28th a battery factory opened in Concord, North Carolina. That was good for an area which has seen dark economic times, but the event made few headlines. Perhaps it should have made more, though, for this factory’s owner, Alevo, a Swiss company, is not in the business of manufacturing cells for torches, mobile phones or even laptop computers. Rather, it is making batteries that can store serious amounts of electricity–megawatt-hours of it. And it plans to sell them to power-grid operators.

To start with, the new batteries will be used to smooth the consequences of irregular demand through the day by absorbing electricity during troughs and regurgitating it during peaks. If that pans out, it will eliminate the need for gas-powered “peaker” stations which fire up quickly when needed, but are expensive to run. It would also allow non-peaker stations to operate more efficiently. Alevo reckons that if a grid as big as America’s Western interconnection (which supplies the west of the United States and Canada) were to use 18GW-worth of its batteries the grid could save $12 billion a year. Though the company has no North American contract yet, it does have an agreement to deploy its batteries in Guangdong, China.

Smoothing the operation of existing grids, however, may be only the beginning. In the longer run, optimists believe, batteries like these, or some equivalent technology, are the key to dealing with the problem not just of irregular demand, but of irregular supply. As the unit cost of solar and wind energy drops ever closer to that of power from fossil fuels, the fact that the wind does not always blow and the sun does not always shine becomes more and more irksome. It is not just the great power-gap that is night which matters. As the chart below shows, even during the day–and even in deserts–the amount of sunlight can vary from minute to minute. And the wind, of course, is equally fickle.

Cheap grid-scale storage would overcome these irregularities. Renewables could then compete on cost alone. And there are many ideas for how to make this happen. Some, such as Alevo’s, are ready to be sold. Others work in laboratories but have yet to be scaled up for use in the real world. Others still are little more than twinkles of varying plausibility in their inventors’ eyes. But if even one of them is up to the task, then renewable energy may, at last, be able to stand on its own, rather than having to be subsidised and regulated into existence.

At the moment, grid-scale storage is dominated by pumped hydro. According to the Electric Power Research Institute, an American think-tank, 140GW-worth of this is installed around the world, with a capacity of 1.4TWhr. Pumped storage requires friendly geography. You need two reservoirs separated by a good gap of altitude. But it is then just a matter of linking them with pipes and using turbines that, if turned by falling water, generate electricity, but, when fed electricity, turn the other way to pump that water whence it came. Send it uphill when power is cheap, and let it flow down when there are spikes in demand, and you have a nice little business.

Not everywhere, though, has compliant hills and valleys. And pumped storage takes a long time, and a lot of money, to build. Technologies that start small, but can be scaled up as needed, are often a better answer.

Batteries now included

The immediate future of grid-scale storage, then, probably lies with real batteries rather than topographical ones. At least, Alevo thinks so. At full capacity, the firm’s factory in Concord should be able to turn out 16.2GWhr-worth of them a year. And Alevo is not alone. Tesla is building an even bigger factory near Reno, Nevada (see “Brain scan: Tesla’s electric man”) to make batteries for its electric cars and for local and grid storage.

Several stations that use batteries to regulate the output of wind farms have already been built, or are under construction. In Sendai, Japan, Toshiba is creating one based on lithium-ion batteries. This should open in 2015. It will have a maximum power of 40MW, and will be able to run at that rate for half an hour. The Notrees Battery Storage Project, which opened in Texas in 2013, uses lead-acid batteries–sophisticated versions of the type found in petrol and diesel cars. It has a maximum power of 36MW and could run for 40 minutes at full tilt. Another Japanese project, of 34MW, in Rokkasho, uses sodium-sulphur batteries. And one in Alaska, of 27MW, uses nickel-cadmium ones.

As that list suggests, many types of grid-scale battery technology are available. Alevo uses electrodes made of lithium iron phosphate and graphite. These are connected by an inorganic sulphur-based electrolyte, a combination, the firm claims, that is particularly propitious because cycling between charged and discharged states produces only a 1°C change in the battery’s temperature. This should eliminate the risk of overheating, to which some sorts of lithium-based cells are prone.

There are types of battery that actually require high temperatures to work. In sodium-sulphur cells of the sort deployed at Rokkasho both of those elements need to be liquid, meaning the battery has to be maintained at a temperature of 300-350°C. And an approach being developed by Donald Sadoway of the Massachusetts Institute of Technology would use two sorts of liquid metal, separated by a liquid electrolyte. The clever thing about this design is that, by picking a dense metal such as a mixture of antimony and lead, a light one such as lithium, and an electrolyte whose density falls between the two, the three substances will float as separate layers in a container, rather as oil separates from vinegar in a salad dressing.

Despite their superficial differences, one thing all these batteries have in common is that the energy they contain is stored chemically within their electrodes. This has a consequence, at least for those with solid electrodes. The constant change in the electrodes’ composition as they are charged and discharged gradually wears them out. This limited lifespan is one reason using batteries for grid-scale storage is still pricey. Indeed, Alevo’s claim that its batteries can undergo more than 40,000 cycles of charging and discharging without noticeable loss of function is an important part of its sales pitch.

An alternative approach, known as a flow battery, does not suffer from this difficulty. A flow battery’s energy is stored in its electrolytes (of which there are two, separated by a membrane), rather than its electrodes (see illustration 1). Not only does that stop the electrodes wearing out, it also means that there is no upper limit, based on the sizes of those electrodes, on how much energy such a battery can store. Its capacity depends instead on the size of the tanks used to hold the electrolytes.

Flow batteries are a much less developed technology than standard batteries, but they are beginning to become commercially available. Many of those on sale at the moment (by firms such as Gildemeister of Germany and UET of Washington state) use vanadium-based electrolytes. Vanadium is a good material because its multiple ionic states mean it can be used to store energy without having to involve other reagents, and thus complicate the design.

Unfortunately, vanadium is expensive. But systems that use cheaper materials are being developed. Several firms are trying zinc and bromine in electrolytes and others iron and chromium. Ideas still in the lab include flow batteries based on cheap organic compounds called anthraquinones. If these prove robust enough to commercialise, they will be strong competitors in the grid-scale storage market. But they will not be alone. For batteries are not the only route to the destination.

Pumped up

If the engineers at Gravity Power in Goleta, California, get their way, even pumped storage is in line for a makeover. Their approach, it should be said from the outset, is one of the most twinkly of the twinkling eyes in the field. Even if it ultimately fails it shows the originality of thought that is being brought to bear on the problem.

Instead of two large reservoirs at different altitudes on a hillside, Gravity Power proposes two water-filled cylindrical shafts–one wider than the other–dug into the ground (see illustration 2). The shafts will be linked top and bottom to form a circuit, with a combined pump-turbine, similar to the ones used in conventional pumped storage, in the upper link. The wider shaft will contain a huge cylinder, made either of the rock the shaft is cut through or of concrete, to act as a piston.

When the pump-turbine is opened, the piston sinks, driving water around the circuit and through the turbine, generating power. Spin the device the other way using electricity, and the reversed water flow pushes the piston up again.

How much energy this arrangement can store depends on how deep the shafts go. And that is where it gets tricky, for some serious civil engineering will be needed if the idea is to work. Gravity Power proposes the shafts descend hundreds of metres. This will require large thicknesses of suitable rock–in practice this will probably be limestone, which is soft enough to cut into–so deployment will be limited not so much by geography as geology. And making a good seal between piston and shaft will hardly be trivial. So it will be expensive. A unit 700 metres deep, with a main shaft 26 metres across and a return shaft (or penstock) of about a tenth of that, would cost $170m. It would, though, be able to store about 200MWhr of energy, with an output of 50MW. Building one that size is years away, but the firm hopes to start work in 2015 on a demonstration plant near Penzberg, in Germany, with a depth of 140 metres, a capacity of 500 kWhr and an output of 1MW.

Nor is Gravity Power’s approach the only one to rely on underground spaces and friendly geology. Another is to fill a subterranean cavern with compressed air. For that, the cavern needs to be hermetically sealed and this means using an underground salt dome that has been hollowed out by solution mining (ie, the salt has been extracted with hot water).

Given such a cavern, compressed-air storage is a bit like classical pumped storage, except with a gas, rather than a liquid. Air is pumped into the cavern, increasing its pressure, and then let out to drive a turbine. But there is a catch: gases heat up when compressed and cool when they expand. For compressed-air storage to work, therefore, the air released from the cavern has to be heated (usually by burning natural gas), otherwise it would freeze the turbine. That makes compressed-air storage inefficient–one reason there are only two grid-scale examples of it in the world (one in Germany, the other in Alabama).

This would change if the heat of compression could be captured, stored and recycled. And that is the goal of LightSail Energy, a firm based in Berkeley, California. LightSail has developed a small, but still grid-scale, compressed-air system that sprays water into the compression chamber, to cool the air as its volume shrinks. The air is then stored in a set of tanks with a total volume of 42,000 litres, and the water, with its heat load, is put into two tanks that have, in total, about a quarter of the volume of the air tanks.

At the moment, this device can store 700kWhr of energy, but that should rise to 1.1MWhr when (as is the plan) it is pressurised to 300 atmospheres instead of the current 200. That is a fraction more than one of Alevo’s battery packs, which store 1MWhr. For comparison, the Alabama salt dome can store 2.9GWhr.

If heat is to be stored at scale some inventors would prefer to simplify the process, get rid of the compressed air, and concentrate on sequestering the heat itself. Isentropic, a company in Fareham, Britain, plans to employ the compression and expansion of a gas (in this case, argon) to create heat and cold respectively in two large containers of gravel–one of the cheapest solid heat-storage media imaginable. Once again, a pump-turbine is involved. It does the compression and expansion when electricity is abundant, and when it is scarce the gas flow, and thus the heat flow and therefore the whole process, is reversed.

Nor are these ideas the end of the list. Several firms, from giants such as ABB of Zurich, to minnows such as Berkeley Energy Sciences, a neighbour of LightSail, are pushing giant flywheels as at least part of the answer. Another suggestion–for filling in the shortest irregularities in supply, those lasting a few seconds or minutes such as are caused by the passage of a cloud in front of the sun–is to use supercapacitors, which store electricity as an actual electric charge, rather than converting it into chemical or physical potential energy of a non-electric form. At the other end of the scale as far as the size of the gap in supply is concerned, namely the nocturnal hours when solar energy cannot operate, several research groups are trying to use molten salts (usually sodium and potassium nitrates) to store heat gathered during the day and then, at night, raise steam for generators with it.

And there is one further idea around that, though it relies on new storage technology being developed, does not rely on that technology being developed specifically for grid-scale storage. This is to use the fleet of electric cars that its proposers hope will take over from ones driven by internal-combustion engines over the course of the next couple of decades.

In the imaginations of such people, the batteries of these cars (which would, when idle, be attached to the grid in order to charge them), could be employed as a giant storage network, to be plundered with the car owners’ permission at times of peak demand. It is an intriguing thought–but the overlap between those times and the times cars are most likely to be on the road might scupper it in practice. As might the answer to the question about how ubiquitous electric cars will actually become. For that will depend on the future success and affordability of batteries.

The path from startup to success is littered with corpses, and an awful lot of business models depend for their putative profit on what is, according to your point of view, either a subsidy or a factoring in of the economic externalities (in the form of climate change) imposed by fossil fuels. In particular, Germany’s Energiewende and California’s Renewable Energy Programme have, by requiring a large fraction of those jurisdictions’ electricity to be renewable, helped fuel the boom.

Your bill, sir

The world would no doubt be a better place if the externalities imposed by fossil fuels were properly accounted for in the price of electricity. But that is a hard sell, not least because of disagreements about those externalities’ true size. In the meantime, it is better if grid-scale storage can be rolled out without taxpayer support.

That is the main reason for watching the example of Alevo. It says it can make money even in unsubsidised grids, because it has been ruthless about reducing manufacturing costs and simplifying the technology as far as possible.

This is a businesslike approach. If it works, and others prove able to mimic it, then the cost of running a grid, and thus the price of electricity, will fall. That alone will be a good thing. But success will change the very nature of such a grid, enabling it to absorb more wind and solar power even if this is a consequence unintended by the grid owners. How much more is yet unknown, for fossil fuels (particularly natural gas) are getting cheaper too. But renewables will no longer be fighting the battle with one hand tied behind their back.

The world would no doubt be a better place if the externalities imposed by fossil fuels were properly accounted for in the price of electricity.

Original Article:

Solar and Wind Energy Start to Win on Price vs. Conventional Fuels NOVEMBER 23, 2014 AT 7:57 PM NYT > Business Day / By DIANE CARDWELL

For the solar and wind industries in the United States, it has been a long-held dream: to produce energy at a cost equal to conventional sources like coal and natural gas.

That day appears to be dawning.

The cost of providing electricity from wind and solar power plants has plummeted over the last five years, so much so that in some markets renewable generation is now cheaper than coal or natural gas.

Utility executives say the trend has accelerated this year, with several companies signing contracts, known as power purchase agreements, for solar or wind at prices below that of natural gas, especially in the Great Plains and Southwest, where wind and sunlight are abundant.

Those prices were made possible by generous subsidies that could soon diminish or expire, but recent analyses show that even without those subsidies, alternative energies can often compete with traditional sources.

In Texas, Austin Energy signed a deal this spring for 20 years of output from a solar farm at less than 5 cents a kilowatt-hour. In September, the Grand River Dam Authority in Oklahoma announced its approval of a new agreement to buy power from a new wind farm expected to be completed next year. Grand River estimated the deal would save its customers roughly $50 million from the project.

And, also in Oklahoma, American Electric Power ended up tripling the amount of wind power it had originally sought after seeing how low the bids came in last year.

“Wind was on sale — it was a Blue Light Special,” said Jay Godfrey, managing director of renewable energy for the company. He noted that Oklahoma, unlike many states, did not require utilities to buy power from renewable sources.

“We were doing it because it made sense for our ratepayers,” he said.

According to a study by the investment banking firm Lazard, the cost of utility-scale solar energy is as low as 5.6 cents a kilowatt-hour, and wind is as low as 1.4 cents. In comparison, natural gas comes at 6.1 cents a kilowatt-hour on the low end and coal at 6.6 cents. Without subsidies, the firm’s analysis shows, solar costs about 7.2 cents a kilowatt-hour at the low end, with wind at 3.7 cents.

“It is really quite notable, when compared to where we were just five years ago, to see the decline in the cost of these technologies,” said Jonathan Mir, a managing director at Lazard, which has been comparing the economics of power generation technologies since 2008.

Mr. Mir noted there were hidden costs that needed to be taken into account for both renewable energy and fossil fuels. Solar and wind farms, for example, produce power intermittently — when the sun is shining or the wind is blowing — and that requires utilities to have power available on call from other sources that can respond to fluctuations in demand. Alternately, conventional power sources produce pollution, like carbon emissions, which face increasing restrictions and costs.

But in a straight comparison of the costs of generating power, Mr. Mir said that the amount solar and wind developers needed to earn from each kilowatt-hour they sell from new projects was often “essentially competitive with what would otherwise be had from newly constructed conventional generation.”

Experts and executives caution that the low prices do not mean wind and solar farms can replace conventional power plants anytime soon.

“You can’t dispatch it when you want to,” said Khalil Shalabi, vice president for energy market operations and resource planning at Austin Energy, which is why the utility, like others, still sees value in combined-cycle gas plants, even though they may cost more. Nonetheless, he said, executives were surprised to see how far solar prices had fallen. “Renewables had two issues: One, they were too expensive, and they weren’t dispatchable. They’re not too expensive anymore.”

According to the Solar Energy Industries Association, the main trade group, the price of electricity sold to utilities under long-term contracts from large-scale solar projects has fallen by more than 70 percent since 2008, especially in the Southwest.

The average upfront price to install standard utility-scale projects dropped by more than a third since 2009, with higher levels of production.

The price drop extends to homeowners and small businesses as well; last year, the prices for residential and commercial projects fell by roughly 12 to 15 percent from the year before.

The wind industry largely tells the same story, with prices dropping by more than half in recent years. Emily Williams, manager of industry data and analytics at the American Wind Energy Association, a trade group, said that in 2013 utilities signed “a record number of power purchase agreements and what ended up being historically low prices.”

Especially in the interior region of the country, from North Dakota down to Texas, where wind energy is particularly robust, utilities were able to lock in long contracts at 2.1 cents a kilowatt-hour, on average, she said. That is down from prices closer to 5 cents five years ago.

“We’re finding that in certain regions with certain wind projects that these are competing or coming in below the cost of even existing generation sources,” she said.

Both industries have managed to bring down costs through a combination of new technologies and approaches to financing and operations. Still, the industries are not ready to give up on their government supports just yet.

Already, solar executives are looking to extend a 30 percent federal tax credit that is set to fall to 10 percent at the end of 2016. Wind professionals are seeking renewal of a production tax credit that Congress has allowed to lapse and then reinstated several times over the last few decades.

Senator Ron Wyden, the Oregon Democrat, who for now leads the Finance Committee, held a hearing in September over the issue, hoping to push a process to make the tax treatment of all energy forms more consistent.

“Congress has developed a familiar pattern of passing temporary extensions of those incentives, shaking hands and heading home,” he said at the hearing. “But short-term extensions cannot put renewables on the same footing as the other energy sources in America’s competitive marketplace.”

Where that effort will go now is anybody’s guess, though, with Republicans in control of both houses starting in January.

Two Big Trends Will Fuel The Renewable Energy Boom For Years

This is the big picture.

Carlos Barria/Reuters
The renewable energy revolution is happening faster than many expected.
According to recent report from Citi Research, renewables will continue their market share grabs from coal and gas forSome of this can be explained by the need for cleaner energy.

“Environmental pressures on coal consumption are rising not only in Europe and North America, but also in China and other emerging markets,” according to the Citi analyst’s note. “The most significant change has been in China, where increasing regulations and the establishment of carbon markets should limit the attractiveness of coal power. Moreover, the country is aggressively pursuing an ‘everything but coal’ development plan for the power sector, with rapid growth in capacity for alternative energy sources.”

Coal power plants are increasingly being pushed into “retirement.”

Most people have been expecting natural gas to be coal’s major substitute. However, Citi’s forecast suggests that growth in natgas demand is going to be way less than previously anticipated.

Renewables should take ever-increasing amounts of market share in an environment like this, according to the report.

In the figure above, you can see that coal’s utilized capacity (measured in GW) is projected drop from 198 GW in 2011 down to 181 GW by 2020. Natural gas slightly increases from 115 GW in 2011 to 132 GW by 2020, although that number is less than previously expected (and you can see there’s a dip from 2012 to 2014). Nuclear sees no major change in either direction, starting at 90 GW and ending at 92 GW.

On the flip side, renewables in 2011 were at 50 GW and are expected to rise to 68 GW by 2020.

two reasons.

First, renewables are rapidly becoming cost-effective, and second, environmental restrictions are becoming an increasingly high hurdle.

Renewables Are Getting Cheaper

Thanks to tech advances, the cost of renewables is finally dropping to affordable levels, which is allowing them to proliferate, according to Citi.

“Costs for solar and wind energy are falling rapidly, with learning rates of around 30% for solar and 7.4% for wind,” the report states.

Wind power has already achieved cost parity with the most expensive coal power plants in Europe (slightly above $80/MWh), and by the end of the decade it’s expected to reach cost parity with the majority of plants (around $70/MWh).

Solar is still the most expensive major electricity source at the moment (around $160/MWh), but Citi is projecting that by 2020 solar will drop to wind’s current prices (slightly above $80/MWh).

“Natural gas has already eroded coal’s cost competitiveness in the US, with decreasing costs for wind, solar and ex-US natural gas to follow,” according to Citi.

Below is the global electricity cost curve.

Citi Research
Environmental Restrictions Favor Renewables

Historically there has been a correlation between economic growth and electricity demand growth. But right now we’re seeing the opposite: during a period of economic growth, electricity demand growth has been relatively flat or declined for some regions.

Some of this can be explained by the need for cleaner energy.

“Environmental pressures on coal consumption are rising not only in Europe and North America, but also in China and other emerging markets,” according to the Citi analyst’s note. “The most significant change has been in China, where increasing regulations and the establishment of carbon markets should limit the attractiveness of coal power. Moreover, the country is aggressively pursuing an ‘everything but coal’ development plan for the power sector, with rapid growth in capacity for alternative energy sources.”

Coal power plants are increasingly being pushed into “retirement.”

Most people have been expecting natural gas to be coal’s major substitute. However, Citi’s forecast suggests that growth in natgas demand is going to be way less than previously anticipated.

Renewables should take ever-increasing amounts of market share in an environment like this, according to the report.

In the figure above, you can see that coal’s utilized capacity (measured in GW) is projected drop from 198 GW in 2011 down to 181 GW by 2020. Natural gas slightly increases from 115 GW in 2011 to 132 GW by 2020, although that number is less than previously expected (and you can see there’s a dip from 2012 to 2014). Nuclear sees no major change in either direction, starting at 90 GW and ending at 92 GW.

On the flip side, renewables in 2011 were at 50 GW and are expected to rise to 68 GW by 2020.

Current Events Energy

Energy Journal: Big Oil’s Size Problem
By Ben Winkley
Here’s your morning jolt of news, insight and analysis on the global energy business. Send us tips, suggestions and complaints: and

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This week’s round of Big Oil earnings showed that some of the world’s dominant energy companies are struggling to make money from massive bets on the shale boom in North America. The Wall Street Journal explains that this is because the deposits of oil and gas found there are proving abundant, but not always profitable.

Exxon Mobil’s earnings, reported here by the Journal’s Tom Fowler, show the company is still feeling the effects of its plunge into natural gas in 2010, which left it exposed to low prices.

Royal Dutch Shell, meanwhile, took a write-down of more than $2 billion on the value of its North American acreage, the Journal’s Selina Williams reports. Although the U.K.-based company didn’t identify which shale formation was responsible for the write-down, the Journal’s James Herron says it likely just failed to get lucky. That’s a big hit for bad luck.

Big Oil is running to stand still, says the Journal’s Liam Denning. Big Oil’s big dilemma, he says, is that every barrel pumped out of the ground has to be replaced with new reserves, unless companies want to shrink to nothing. If they want to increase production, they need to discover more than one barrel for every one pumped.

It’s a treadmill, and investors aren’t buying into scale these days. Growth rates at a company like Apache, which this week reported a significant profit increase, are increasingly attractive.

Sometimes less really is more, the Journal’s Spencer Jakab says. Welcome to Medium Oil.


Some 200 wind turbines will be installed in the Rhode Island Sound, on the U.S. East Coast, as the country’s first ever offshore wind-energy auction concluded this week.

A milestone moment, said U.S. Interior Secretary Sally Jewell. An enormous step forward, said the winning bidder, Deepwater Wind.

It could invest $6 billion building turbines and transmission lines, having snapped up some 165,000 acres of federal waters for just $3.8 million, plus $500,000 a year rent until a wind farm is operational.

Next under the hammer are 113,000 acres offshore Virginia, to be followed by blocks off the coasts of Maryland, Massachusetts and New Jersey.

It has taken a long time to get to this point, and there can be no doubt that a number of factors are behind the U.S. lagging, say, Europe in this sector.

But a revolution could be beginning.


TransCanada, the company behind the controversy-plagued, long-delayed Keystone XL pipeline, is planning another route out of Alberta for all that heavy oil.

It plans to spend $12 billion building a pipeline all the way from Alberta and Saskatchewan to Canaport in Saint John, New Brunswick, the Journal reports. From there, Canadian crude will be able to access the world once a deepwater port is built (and have the knock-on effect of displacing imports from Africa, the Middle East and Venezuela).

What does this mean for Keystone? President Barack Obama has twice been openly critical of the proposed pipeline, Bloomberg reports. New Energy Secretary Ernest Moniz won’t even have a say in whether Keystone will be built.

Opposition to the Alberta-Gulf Coast pipeline is mostly on environmental grounds. This New Scientist report on out-of-control oil leaks in Alberta will add fuel to the debate.


Crude oil futures were slightly lower Friday as traders took profits after a slew of positive economic news from the U.S., Europe and China pushed the contracts to recent highs. Read the Journal’s latest market report here.

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