Resource Documents: Economics (158 items)
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.
Author: Cullen, Joseph
Production subsidies for renewable energy, such as solar or wind power, are rationalized by their environmental benefits. Subsidizing these projects allows clean, renewable technologies to produce electricity that otherwise would have been produced by dirtier, fossil-fuel power plants. In this paper, I quantify the emissions offset by wind power for a large electricity grid in Texas using the randomness inherent in wind power availability. When accounting for dynamics in the production process, the results indicate that only for high estimates of the social costs of pollution does the value of emissions offset by wind power exceed cost of renewable energy subsidies.
American Economic Journal: Economic Policy 2013, 5(4): 107–133
Assistant Professor of Economics, Olin Business School, Washington University, St. Louis, Missouri
[T]he quantity of emissions offset by wind power will depend crucially on which generators reduce their output. This paper introduces an approach to empirically measure the environmental contribution of wind power resulting from these production offsets.
Utilizing information on production decisions in 15-minute intervals on the Texas electricity grid, I estimate the response of each generator to exogenous changes in wind power. Realizing that wind power production is not completely random, I control for factors that may drive the incentives for electricity production, which may also be correlated with wind power production. The resulting quasi-experimental residual variation is then used to identify a substitution coefficient for each generator on the grid. Importantly, I show that failing to control for impact that wind has on the dynamic process of electricity production overestimates the production offsets. These production offsets then translate directly into emission offsets using generator emission rates.
Estimated offsets can be valued by appealing to estimates from the literature on the marginal damage costs of emissions. This allows a direct comparison between the value of short run offset emissions with the cost of subsidies which drive investment in wind farms. …
Rather than using an engineering or marginal cost stack approach which calculates emission offsets given a set of parameters, I use an econometric approach to estimate the emissions offset by wind power from observed output decisions. This econometric model exploits random and exogenous changes in the output of wind farms to identify the generating substitutes of wind power from observed, rather than simulated, behavior in such a way that allows for a high degree of heterogeneity among generators. I use a flexible, reduced form model which respects the dynamic constraints of generators, incorporates firms’ reactions to uncertainty, and admits market power which may exist in certain states of the market. It does not require proprietary data on generators, but relies only on publicly available generator output and characteristics. …
The estimation approach used in this paper exploits the randomness and exogeneity of wind patterns to identify the average reduction in output for each generator on the grid due to wind power production. However, as previously highlighted, the diurnal and seasonal patterns of wind are not uncorrelated with other incentives for production by conventional generators. In this model, I will need to control for factors that affect a conventional producer’s decision to generate electricity, which may also be correlated with wind power production. In particular, one needs to account not only for static, but also for dynamic factors in the generators production decision. …
Since wind power is not produced near demand centers, it could be that the offsets are less than one-to-one due to transmission line losses. …
There is some concern that applying average emission rates to offset production estimates may not give an accurate estimate of offset emissions. A generator’s emission rate, although relatively constant for most technologies, can vary as a function of output level of the plant. Generators generally operate most efficiently when operating steadily near maximum capacity; operating at partial capacity may increase emission rates. Emission rates can also change during ramping. Periods when a generator is ramping up will have higher than average emission rates. Likewise, emission rates drop when a generator is ramping down, though the effect is not necessarily symmetric. This emission “bias” is documented in the engineering literature. Katzenstein and Apt (2009) measure the effect of the output level and ramping on emissions for two types of natural gas generators. From an engineering standpoint, they show that actual emission offsets from wind power may be 20–50 percent lower than those implied when using average emission rates. This bias is increasing in the level of penetration of wind power as hypothetical gas generators are forced to operate at lower and lower capacity levels and incur more ramping. …
[I]f a pollutant is already subject to optimal regulation, then offsets yield no additional value. In addition, for emissions regulated under a binding cap-and-trade program, offset emissions do not imply a reduction in total emissions regardless of the optimality of the regulation. Emissions offset at one facility result in pollution permits being freed up for use elsewhere. For this reason, pollutants regulated under cap-and-trade systems, such as SO₂ and NOx, offsets may not have environmental benefits. …
A large body of literature exists on the estimated damages of CO₂ emissions. Tol (2005) reviews the literature, which estimates the social costs of CO2, and concludes that the costs imposed by CO₂ are less than $50/ton and probably significantly lower than that. The median marginal damage costs of CO₂, as found in papers published in peer-reviewed journals, was $14/ton (Tol 2005).
More recently, the US government has compiled estimates on the social cost of carbon for use in regulatory analyses. The Interagency Working Group on Social Cost of Carbon compiled the report which estimates the monetized damages associated with an incremental increase in carbon emissions in a given year. The group selected four values which are based on a collection of integrated assessment models, at different discount rates. The values for the social cost of carbon produced by the report were $5, $21, and $35, per ton of CO₂ for the year of 2010, with $21 being the “central” value. …
[E]missions of SO₂ are regulated at every power plant. This, and the fact that there are negligible estimated offsets, implies that no benefits will accrue from SO₂ offsets in Texas.
For the value of offset NOx, … I use estimates from Muller and Mendelsohn (2011), which use an integrated assessment model to calculate spatially differentiated marginal damage costs. In Texas, the estimated costs are in the range of $100–$2,000/ton of NOx. …
[T]he value of emissions offset by wind power ranges from less than $3/MWh in the low value scenario to less than $10/MWh for middle-range estimates to a little more than $17/MWh for the higher end of marginal damage costs. …
[T]he emissions benefits of wind power fail to exceed the $20/MWh subsidy even for higher estimates of marginal damage costs. The social cost of carbon would have to be greater than $42 for the benefits of the subsidy to outweigh its costs based on carbon offsets alone. Note that even then this result does not imply that wind power would be the lowest cost method of reducing CO₂ emissions; it is almost certainly not.
Author: Holly, S. Michael
Many U.S. special interests are misrepresenting wind power costs, including the wind industry, environmental groups, utility monopolies, independent system operators, educational and research institutions, and even federal and state governments. On September 24, Bill Ritter, the current director of the Center for the New Energy Economy at Colorado State University and former Governor of Colorado, wrote in the Wall Street Journal that “Long-term contracts for wind energy are being signed by utilities in several states in the range of 3 cents per kWh over 20 years” (1). Xcel Energy, the nation’s leading wind-generating electric utility, declares “wind power is simply the cheapest resource” (2).
Before the overproduction of turbines led to recent dumping, developers were offering utilities (in the lowest-cost wind areas of the U.S.) bid prices of about four cents (3). But the price of electricity from windmills outside the U.S. has been about 10 cents (in the form of feed-in tariffs), with capital costs accounting for about 93 percent of total costs. The six cent difference in the U.S. can be explained by tax write-offs targeted to big companies and the rich that cover half to two-thirds of the capital costs of windmills, according to the wind developer web site Windustry (4). Michael Mendelsohn of the National Renewable Energy Laboratory explains that the federal production tax credit (PTC) and federal accelerated depreciation (MACRS) are worth about 30 percent and 20 to 25 percent of the capital costs of windmills, respectively.
The PTC is worth 2.2 cents after taxes or 3.7 cents before taxes at a 40 percent marginal tax rate (5). After compensating investors with a financing charge worth about 0.7 cents, the tax credit is worth about three cents to developers. A few years ago, wind developers were allowed to replace the PTC with an equivalent Investment Tax Credit (ITC) that directly reimbursed 30 percent of windmill costs over the first couple years. Many states also offer accelerated depreciation that mirrors MACRS. Since Bolinger found combined federal and state accelerated depreciation provided tax savings over six years comparable to the PTC for 10 years (6), accelerated depreciation can also be considered to be worth about three cents or 30 percent of windmill costs.
Even though wind power has been subsidized from 10 to three or four cents, electricity rates have been increasing significantly in regions with the highest wind penetration levels (five to 10 percent), due to extra transmission and integration costs (that have often not been accurately reported by utilities).
The Lawrence Berkeley National Laboratory has found capital costs for transmission lines are triple those of other generation sources due to the lower capacity factors of wind at about 30 percent compared to about 90 percent for base-load plants (7). Transmission costs are also driven higher by the need to locate windmills further from load centers. Typically, ratepayers must pay extra transmission costs of about two cents more for wind power (e.g., three cents compared to one cent or even less for base-load generation).
Moreover, states have misrepresented the extra indirect costs of integrating the intermittent output from wind into the grid. For example, the 2006 Minnesota Wind Integration Study, which has served as a basis for state policies mandating the addition of wind power to 25 percent of generation, claimed the costs of integration are only about 0.3 cents. But they made the false assumption that they would be the only state adding wind power into the entire market of the MISO, which is over 10 times as large as the Minnesota market, and thus actually determining the costs of integrating only 2 percent wind power.
At low levels of wind penetration, the variability can be regulated by reserve capacity already used for load fluctuations and allowance for failure of other generation. Wind can also be used to displace a few inefficient generators still on the system even if it is not an efficient long-term solution. The state’s new transmission and integration study for 40 percent wind and solar appears to be playing the same game.
Utility monopolies have violated state laws and rules by misrepresenting integration costs while petitioning regulators for their purchase of wind power. Their economic models can’t even calculate the costs of intermittent resources. Utilities should be using programs (like Promod) that can account for hourly variations of wind and report on hourly generation for each generator. Utilities are not reporting the mix of generation that is most economical for load following of wind (e.g. single cycle, combined cycle, etc.)
The Organization for Economic Co-operation and Development has estimated grid-level system costs are at least 1.6 and 1.9 cents for wind penetration levels of 10 and 30 percent respectively, compared to only 0.05 cents for natural gas generation (8). Grid-level system costs include the costs of various grid infrastructures, short-term balancing, intermittent electricity access, network congestion and instability. However, the study didn’t include plant-level costs imposed on base-load plants that are increasing with wind penetration levels, including idled capacity and even an inability to make debt payments.
A 2012 study by the National Energy Technology Laboratory (financed by the U.S. Department of Energy) reports utilities are also becoming aware that requiring base load power plants to ramp up and down and operate at sub-optimal levels (while following the load of the intermittent wind output) increases maintenance costs and reduces fuel efficiency (9). Another problem related to fuel efficiency has been wasted duplication of generation when base-load plants are unable to respond rapidly or drop output enough. An April 18 Reuters article reporting on the study claims that as wind is added “Relatively inefficient single cycle gas turbines are likely to be the only practical option for load-following on the grid” (10).
In the future, grid operators can be expected to reduce the excessive need for backup with single cycle gas turbines by curtailing the five to 10 percent of wind energy greater than 60 percent of peak output at a loss to ratepayers of about 0.5 cents to one cent (or 0.2 to 0.4 cents after tax write-offs). After curtailment, wind power can be expected to supply about half of base load generation (which is 80 percent of total generation). Since single cycle gas turbines also cost about 12 cents, wind backed by these peaking plants doubles total electricity costs compared to just using combined cycle turbines fueled by natural gas at about six cents for base load power (11). The extra six cents must be assigned to wind power as backup costs.
Even wind backed by peaking plants will have additional grid-level system costs. General Electric representatives explained the problem while trying to sell their single cycle system for balancing wind: “The variability of power generation from wind farms presents an operational challenge for power systems with significant penetration of wind generation …. integration of wind generation into a power system will require the ability to dispatch, or control, power output …. technology for fast, flexible, economic, modular deployment has been lacking” (12).
Moreover, wind backed by peaking (that is at most 30 percent efficient when trying to back up wind) uses as much natural gas and emits as much carbon dioxide and other pollutants as just using combined cycle at 60 percent efficiency (without wind power).
The industry is grasping for alternatives like new combined cycle natural gas base-load plants designed for fast-ramping (13), but integration costs would be even higher, largely due to a tripling of capital costs compared to conventional combined cycle (14). The country is also trying to develop storage and so-called smart grid technologies but costs are also high. The response has been the building of expensive transmission lines for export from high- to low-wind areas, but the potential is limited.
The U.S. has hidden from the public the additional costs to taxpayers for tax write-offs on windmills of about six cents, and to ratepayers for extra transmission of about two cents and backup of at least six cents, which drive total costs for wind power from bid prices of 4 cents to total costs over 18 cents. Despite the high costs and low environmental benefits, the U.S. has been mandating, subsidizing and misrepresenting an incredible $30 billion of windmills per year to meet 45 percent of U.S. capacity additions (with natural gas second at 40 percent).
Meanwhile, the U.S. is allowing utility monopolies to use misrepresentation (that they can get wind power at only three or four cents) to reject the purchase of other lower-cost renewable energies. The International Energy Agency has noted the “well-established competitiveness of hydropower, geothermal and bioenergy” (15). At the April 9, 2013 Biomass Conference in Minneapolis, the President of the U.S. Biomass Power Association Bob Cleaves mused that biomass couldn’t use the “wind” tax write-offs very well. The US is blocking hydropower, geothermal and cogeneration fueled by captive biomass wastes that could actually solve economic and environmental problems by reducing greenhouse gases at a cost of only six to eight cents without mandates or much (if any) subsidies.
By S. Michael Holly, Chairman of Sorgo Fuels & Chemicals, Inc. Sorgo has developed technology for the production of ethanol, electricity and protein from sweet sorghum. Mike was formerly an alternative energy engineer and business analyst with the Minnesota Department of Energy and Economic Development. He holds masters degrees in chemical engineering and business administration from the University of Minnesota.
(11) www.power-eng.com/articles/print/volume-113/issue-7/features/calculating-wind-powerrsquos-environmental -benefits.html
Author: Giberson, Michael
This study examines estimates of the cost of wind power capacity produced by the U.S. government and provides additional context in order to better guide policy decisions concerning wind power. The federal government has devoted substantial resources to estimate the costs of wind power capacity and the associated costs of integrating wind power into transmission grids, but the complexity of the power grid and the technical nature of most research studies make it difficult for policymakers and non-specialist interested citizens to understand just what these studies mean. Numerous reports produced by the National Renewable Energy Laboratory and the Lawrence Berkeley National Laboratory reveal a great deal about wind power costs. However, the most frequently cited numbers, concerning estimated Levelized Cost of Energy (LCOE) of wind power, do not capture all of the costs of wind power.
The federal government devotes substantially more financial resources to subsidize the production of wind power than it does to study wind power. The GAO counted over 80 separate federal programs offering economic support to wind power producers, though the largest program by a wide margin is the Production Tax Credit. State and local governments offer additional support. Government subsidies for wind power naturally raise questions concerning costs and benefits associated with the policy. Indeed, a complete policy analysis would assess both costs and benefits in a complete and consistent manner. Perhaps surprisingly given the extent of federal policy support for wind power, no systematic effort has been made to calculate the overall net benefit (or cost) of public policies supporting wind power. Given the importance of understanding the costs associated with wind power policies, this paper examines and assesses the most significant of the wind power cost estimates produced by the federal government.
In brief, the primary focus of the National Renewable Energy Laboratory report, the 2011 Cost of Wind Energy Review, is to provide an estimate of the cost to the developer of installing wind power capacity. The Lawrence Berkeley Laboratory’s Wind Technologies Market Report series seeks to provide an overview and details on trends affecting the wind power industry, including cost and performance trends. The Berkeley Lab report, like the NREL report, focuses primarily on the cost of wind power to the wind project developer. While expenses faced by wind project developers are an important element of the overall cost of wind power, addition of wind power to the power grid involves a number of other costs. If a more reasonable estimate of the installed cost of capital is $88 per MWh and operating costs are $21 per MWh, we can estimate a reasonable LCOE for wind power near $109 per MWh rather than NREL’s estimate of $72 — a more than 50 percent increase.
Such costs include the expense of transmission expansions needed to develop wind power, other grid integration expenses, and added grid reliability expenses. Both the costs to the developer and the other costs are examined in this study.
Select Committee on Wind Farm Developments in South Australia, The Legislative Council, Wednesday 17 July 2013.
ALLAN AUGHEY, Mayor, Clare and Gilbert Valleys Council
PETER MATTEY, Mayor, Regional Council of Goyder
MARY MORRIS and WANDA ALLOTT
JULIE QUAST and JOHN FAINT, Waterloo and District Concerned Citizens Group