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Resource Documents: Economics (195 items)

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Documents presented here are not the product of nor are they necessarily endorsed by National Wind Watch. These resource documents are provided to assist anyone wishing to research the issue of industrial wind power and the impacts of its development. The information should be evaluated by each reader to come to their own conclusions about the many areas of debate.


Date added:  August 4, 2018
California, Economics, TechnologyPrint storyE-mail story

$2.5 trillion reason we can’t rely on batteries to clean up the grid

Author:  Temple, James

A pair of 500-foot smokestacks rise from a natural-gas power plant on the harbor of Moss Landing, California, casting an industrial pall over the pretty seaside town.

If state regulators sign off, however, it could be the site of the world’s largest lithium-ion battery project by late 2020, helping to balance fluctuating wind and solar energy on the California grid.

The 300-megawatt facility is one of four giant lithium-ion storage projects that Pacific Gas and Electric, California’s largest utility, asked the California Public Utilities Commission to approve in late June. Collectively, they would add enough storage capacity to the grid to supply about 2,700 homes for a month (or to store about 0.0009 percent of the electricity the state uses each year).

The California projects are among a growing number of efforts around the world, including Tesla’s 100-megawatt battery array in South Australia, to build ever larger lithium-ion storage systems as prices decline and renewable generation increases. They’re fueling growing optimism that these giant batteries will allow wind and solar power to displace a growing share of fossil-fuel plants.

But there’s a problem with this rosy scenario. These batteries are far too expensive and don’t last nearly long enough, limiting the role they can play on the grid, experts say. If we plan to rely on them for massive amounts of storage as more renewables come online—rather than turning to a broader mix of low-carbon sources like nuclear and natural gas with carbon capture technology—we could be headed down a dangerously unaffordable path.

Small doses

Today’s battery storage technology works best in a limited role, as a substitute for “peaking” power plants, according to a 2016 analysis by researchers at MIT and Argonne National Lab. These are smaller facilities, frequently fueled by natural gas today, that can afford to operate infrequently, firing up quickly when prices and demand are high.

Lithium-ion batteries could compete economically with these natural-gas peakers within the next five years, says Marco Ferrara, a cofounder of Form Energy, an MIT spinout developing grid storage batteries.

“The gas peaker business is pretty close to ending, and lithium-ion is a great replacement,” he says.

This peaker role is precisely the one that most of the new and forthcoming lithium-ion battery projects are designed to fill. Indeed, the California storage projects could eventually replace three natural-gas facilities in the region, two of which are peaker plants.

But much beyond this role, batteries run into real problems. The authors of the 2016 study found steeply diminishing returns when a lot of battery storage is added to the grid. They concluded that coupling battery storage with renewable plants is a “weak substitute” for large, flexible coal or natural-gas combined-cycle plants, the type that can be tapped at any time, run continuously, and vary output levels to meet shifting demand throughout the day.

Not only is lithium-ion technology too expensive for this role, but limited battery life means it’s not well suited to filling gaps during the days, weeks, and even months when wind and solar generation flags.

This problem is particularly acute in California, where both wind and solar fall off precipitously during the fall and winter months. Here’s what the seasonal pattern looks like:

If renewables provided 80 percent of California electricity – half wind, half solar – generation would fall precipitously beginning in the late summer. Clean Air Task Force analysis of CAISO data

This leads to a critical problem: when renewables reach high levels on the grid, you need far, far more wind and solar plants to crank out enough excess power during peak times to keep the grid operating through those long seasonal dips, says Jesse Jenkins, a coauthor of the study and an energy systems researcher. That, in turn, requires banks upon banks of batteries that can store it all away until it’s needed.

And that ends up being astronomically expensive.

California dreaming

There are issues California can’t afford to ignore for long. The state is already on track to get 50 percent of its electricity from clean sources by 2020, and the legislature is once again considering a bill that would require it to reach 100 percent by 2045. To complicate things, regulators voted in January to close the state’s last nuclear plant, a carbon-free source that provides 24 percent of PG&E’s energy. That will leave California heavily reliant on renewable sources to meet its goals.

The Clean Air Task Force, a Boston-based energy policy think tank, recently found that reaching the 80 percent mark for renewables in California would mean massive amounts of surplus generation during the summer months, requiring 9.6 million megawatt-hours of energy storage. Achieving 100 percent would require 36.3 million.

The state currently has 150,000 megawatt-hours of energy storage in total. (That’s mainly pumped hydroelectric storage, with a small share of batteries.)

If renewables supplied 80 percent of California electricity, more than eight million megawatt-hours of surplus energy would be generated during summer peaks. Clean Air Task Force analysis of CAISO data.

Building the level of renewable generation and storage necessary to reach the state’s goals would drive up costs exponentially, from $49 per megawatt-hour of generation at 50 percent to $1,612 at 100 percent.

And that’s assuming lithium-ion batteries will cost roughly a third what they do now.

California’s power system costs rise exponentially if renewables generate the bulk of electricity. Clean Air Task Force analysis of CAISO data.

“The system becomes completely dominated by the cost of storage,” says Steve Brick, a senior advisor for the Clean Air Task Force. “You build this enormous storage machine that you fill up by midyear and then just dissipate it. It’s a massive capital investment that gets utilized very little.”

These forces would dramatically increase electricity costs for consumers.

“You have to pause and ask yourself: ‘Is there any way the public would stand for that?’” Brick says.

Similarly, a study earlier this year in Energy & Environmental Science found that meeting 80 percent of US electricity demand with wind and solar would require either a nationwide high-speed transmission system, which can balance renewable generation over hundreds of miles, or 12 hours of electricity storage for the whole system (see “Relying on renewables alone significantly inflates the cost of overhauling energy”).

At current prices, a battery storage system of that size would cost more than $2.5 trillion.

A scary price tag

Of course, cheaper and better grid storage is possible, and researchers and startups are exploring various possibilities. Form Energy, which recently secured funding from Bill Gates’s Breakthrough Energy Ventures, is trying to develop aqueous sulfur flow batteries with far longer duration, at a fifth the cost where lithium-ion batteries are likely to land.

Ferrara’s modeling has found that such a battery could make it possible for renewables to provide 90 percent of electricity needs for most grids, for just marginally higher costs than today’s.

But it’s dangerous to bank on those kinds of battery breakthroughs—and even if Form Energy or some other company does pull it off, costs would still rise exponentially beyond the 90 percent threshold, Ferrara says.

“The risk,” Jenkins says, “is we drive up the cost of deep decarbonization in the power sector to the point where the public decides it’s simply unaffordable to continue toward zero carbon.”

James Temple, Senior Editor, Energy

MIT Technology Review, July 27, 2018

I am the senior editor for energy at MIT Technology Review. I’m focused on renewable energy and the use of technology to combat climate change. Previously, I was a senior director at the Verge, deputy managing editor at Recode, and columnist at the San Francisco Chronicle. When I’m not writing about energy and climate change, I’m often hiking with my dog or shooting video of California landscapes.

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Date added:  July 14, 2018
Economics, Europe, Germany, GridPrint storyE-mail story

Wind energy in Germany and Europe – Status, potentials and challenges for baseload application – Developments in Germany since 2010

Author:  Linneman, Thomas; and Vallana, Guido

In Germany the installed nominal capacity of all wind turbines has increased eightfold over the last 16 years to 50,000 megawatts today. In the 18 most important European countries using wind energy today, the nominal capacity rose by twelve times to more than 150,000 megawatts. One essential physical property of wind energy is its large spatiotemporal variation due to wind speed fluctuations. From a meteorological point of view, the electrical power output of wind turbines is determined by weather conditions with typical correlation lengths of several hundred kilometres. As a result, the total wind fleet output of 18 European countries extending over several thousand kilometres in north-south and east-west direction is highly volatile and exhibits a strong intermittent character. An intuitively expectable significant smoothing of this wind fleet output to an amount which would allow a reduction of backup power plant capacity, however, does not occur. [emphasis added] In contrast, a highly intermittent wind fleet power output showing significant peaks and minima is observed not only for a single country, but also for the whole of the 18 European countries. Wind energy therefore requires a practically 100% backup. As the (also combined) capacities of all known storage technologies are (and increasingly will be) insignificant in comparison to the required demand, backup must be provided by conventional power plants, with their business cases fundamentally being impaired in the absence of capacity markets.

Windenergie in Deutschland und Europa – Status quo, Potenziale und Herausfor­ derungen in der Grundversorgung mit Elektrizität – Entwicklungen in Deutschlandseit 2010:  Die installierte Nennleistung sämtlicher Windenergieanlagen in Deutschland hat sich in den letzten 16 Jahren, von Anfang 2001 bis Ende 2016, auf 50.000 Megawatt (MW) verachtfacht. In 18 betrachteten europäischen Ländern, die Windenergie heute nutzen, erhöhte sich die Nennleistung im gleichen Zeitraum um das Zwölffache auf mehr als 150.000 MW. Eine wesentliche physikalische Eigenschaft der Windenergie ist ihre starke raumzeitliche Variation aufgrund der Fluktuationen der Windgeschwindigkeit. Meteorologisch betrachtet wird die aus Windenergieanlagen eingespeiste elektrische Leistung durch Wetterlagen mit typischen Korrelationslängen von mehreren hundert Kilometern bestimmt. Im Ergebnis ist die aufsummierte eingespeiste Leistung der europaweit über mehrere tausend Kilometer sowohl in Nord-Süd- als auch Ost-West-Richtung verteilten Windenergieanlagen hoch volatil, gekennzeichnet durch ein breites Leistungsspektrum. Die intuitive Erwartung einer deutlichen Glättung der Gesamtleistung in einem Maße, das einen Verzicht auf Backup-Kraftwerksleistung ermöglichen würde, tritt allerdings nicht ein. Das Gegenteil ist der Fall, nicht nur für ein einzelnes Land, sondern auch für die große Leistungsspitzen und -minima zeigende Summenzeitreihe der Windstromproduktion 18 europäischer Länder. Für das Jahr 2016 weist die entsprechende Zeitreihe (Stundenwerte) bei idealisiert verlustfreier Betrach tung einen Mittelwert von 33.000 MW und ein Minimum von weniger als 6.500 MW auf. Dies entspricht trotz der europaweit verteilten Windparkstandorte gerade einmal 4 % der in den betrachteten 18 Ländern insgesamt installierten Nennleistung. Windenergie trägt damit praktisch nicht zur Versorgungssicherheit bei und erfordert 100% planbare Backup-Systeme nach heutigem Stand der Technik. Da das benötigte Speichervolumen aller heute bekannten Speichertechnologien im Vergleich zur Elektrizitätsnachfrage gering ist (auch in Kombination und mit steigender Tendenz bei weiterem Ausbau volatiler, vom Dargebot abhängiger erneuerbarer Energien), müssen konventionelle Kraftwerke diese Backup-Funktion übernehmen. Deren Rentabilität steht ohne Kapazitätsmärkte schon heute in Frage.

Thomas Linnemann and Guido S. Vallana
VGB PowerTech, Essen, Deutschland

June 2017

Download original document in English: “Wind energy in Germany and Europe: Status, potentials and challenges for baseload application
Auf Deutsch: “Windenergie in Deutschland und Europa: Status quo, Potenziale und Herausfor­ derungen in der Grundversorgung mit Elektrizität
Präsentation: VGB-Windstudie 2017

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Date added:  April 30, 2018
Economics, EuropePrint storyE-mail story

Market value of variable renewables: The effect of solar and wind power variability on their relative price

Author:  Hirth, Lion

Abstract – This paper provides a comprehensive discussion of the market value of variable renewable energy (VRE). The inherent variability of wind speeds and solar radiation affects the price that VRE generators receive on the market (market value). During wind and sunny times the additional electricity supply reduces the prices. Because the drop is larger with more installed capacity, the market value of VRE falls with higher penetration rate. This study aims to develop a better understanding how the market value with penetration, and how policies and prices affect the market value. Quantitative evidence is derived from a review of published studies, regression analysis of market data, and the calibrated model of the European electricity market EMMA. We find the value of wind power to fall from 110 percent of the average power price to 50-80 percent as wind penetration increases from zero to 30 percent of total electricity consumption. For solar power, similarly low values levels are reached already at 15 percent penetration. Hence, competitive large-scale renewables deployment will be more difficult to accomplish than many anticipate.

Lion Hirth, Vattenfall and Potsdam-Institute for Climate Impact Research

Energy Policy 2013; 38: 218–236. doi: 10.1016/j.eneco.2013.02.004

Download original document: “The market value of variable renewables: The effect of solar and wind power variability on their relative price

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Date added:  January 8, 2018
Economics, EmissionsPrint storyE-mail story

Wind and solar are much less efficient decarbonizers than combined-cycle gas turbines

Author:  Plummer, James; Frank, Charles; and Michaels, Robert

ABSTRACT

We compare three technologies that produce electricity in the United States: wind, solar, and combined-cycle gas turbines (CCGT). We use the 2016 electric utility database compiled by the U.S. Energy Information Administration (EIA). That database has the advantage of being based on a census of U.S. power plants rather than sampling, as well as excluding any subsidies received by the power plants.

We show the cost savings achieved when there is a shift between coal-fired generation and generation by wind, solar, or CCGTs, where costs include both capital and operating costs. The net cost reduction per tonne of CO₂ reduction is $4,340 for a shift from coal to wind, −$98,826 (a cost increase rather than a cost decrease) for a shift from coal to solar, and a $251,920 decrease for a shift from coal to CCGT.

When the net emissions from switching away from coal are considered, the net cost savings for each tonne of emissions avoided is $1.27 for a switch from coal to wind, −$44.11 (a net cost increase) for a switch from coal to solar, and a savings of $50.72 for a switch from coal to CCGT. The differentials between the savings from a switch to wind or solar and a switch to CCGT is a measure of the “dead weight economic loss involved in switching from coal to either form of “renewables” instead of switching from coal to CCGT.

This research concludes that CCGT is the only “economic” choice from the perspective of benefit-cost analysis.

BASIC ASSUMPTIONS

OTHER BASIC ASSUMPTIONS

THE CONCEPT OF “DECARBONIZATION EFFICIENCY”

Decarbonization cost is the differential cost of producing a MW year of electricity via coal plants and three other technologies – wind, solar, and CCGTs – divided by the differential CO₂ emissions (measured in tonnes per year).

Total net cost savings in 2016 of switching from coal to …

Tonnes of CO₂ emissions per MW-year avoided by switching from coal to …

Net cost savings per tonne of emissions avoided

DEAD WEIGHT ECONOMIC LOSS …

Of a decision to switch from coal to wind instead of to CCGT:

Of a decision to switch from coal to solar instead of to CCGT:

Conclusion: Switching to either wind or solar instead of to CCGT involves a dead weight economic loss. However, the dead weight economic loss is twice as great for a switch to solar instead of a switch to wind.

A SCENARIO OF DECARBONIZATION

In recent years, U.S. CO₂ emissions have been about 5.8 billion tonnes per year.

Suppose a goal of reducing those emissions by 10% or about 580 million tonnes.

As shown before, substitution of wind for coal results in a cost savings of $1.27 per tonne of CO₂ reduction, or $0.74 billion in this decarbonization scenario.

As shown before, substitution of solar for coal results in extra costs of $44.11 per tonne of CO₂ reduction, or $25.58 billion if all the investment was in solar.

However, if all the investment were done in CCGT, then the total cost savings would be $29.42 billion. So, the cost savings are larger when all the investment is in CCGT. The differences in cost savings are the amount of “dead weight economic loss” from investing in wind or solar instead of CCGTs.

These equations could be turned around to calculate, for a given fixed outlay of costs, what would be the “foregone CO₂ emissions opportunity” from investing in wind or solar instead of CCGT.

OTHER ALLEGED “SIDE BENEFITS OR COSTS” OF RENEWABLES

Job creation. Many of the jobs created by renewables are at the installation or capital goods production stages. The inherent capital intensivity of renewables limit their job creation potential.

Infant industry learning. This was a label invented by Argentine economist Raul Prebisch to argue for tariff protection of industry in less developed countries. However, those tariffs often led to “soft industries” that became dependent on the tariffs and did not focus on increased efficiency. A higher gain results from investing in specialized R&D activity.

Siting issues. Renewables progress over time from more favorable wind and solar sites to sites that involve higher cost per kWh produced, a classic example of “diminishing economic returns.” CCGTs are smaller physical plants, which can be sited close to natural gas supply or end-use electricity customers.

BROADER ISSUES OF RENEWABLES VS. CCGTs

Should CCGT be eligible to receive federal tax credits analogous to the current federal tax subsidies to wind and solar? No. This would be doubling down on a bad federal policy. CCGT does not need subsidies. They can out compete wind and solar on their own.

The states mainly follow a policy of “renewables mandates” placed on regulated utilities. The utilities don’t resist these mandates very hard because the system of a fixed return on “utility rate base” largely eliminates the incentives to lower costs via investment in CCGTs. This pattern is a classic example of political “confusion of ends and means.” If the goal of electricity policy at the state level is reducing CO₂ emissions, then the state should not intervene to put CCGTs at a disadvantage.

James L. Plummer, President, Climate Economics Foundation
Charles R. Frank, Senior Non-resident Fellow, Brookings Institution
Robert R. Michaels, California State University Fullerton

[presented at the 35th United States Association for Energy Economics/International Association for Energy Economics Conference, November 12–15, 2017, Houston]

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