Minnesotans For Sustainability©
Sustainable Society: A society that balances the environment, other life forms, and human interactions over an indefinite time period.
The role of renewable energy sources in utility portfolio risk: Assessing the impact of a national policy requiring increased use of Wind Power in the nation's energy mixture on utility portfolio risk
Click here for Discussion
The U.S. Energy Information Administration states that about 85 percent of the energy consumed in the United States in 2000 was generated from coal, oil and natural gas, while the energy consumed from renewable energy forms during that same period amounted to 7 percent. (Silverstein, IssueAlert,). Wind and solar sources account for just 2 percent of the nation's total electricity market. Wind is a form of solar energy, because Uneven solar heating of the atmosphere, the irregularities of the Earth’s surface, and rotation of the Earth are the factors that create wind. Therefore, winds are strongly subjective to and modified by local terrain, bodies of water, weather patterns, vegetative cover, and other factors. This wind flow, or motion energy, when “harvested” by wind turbines, can be used to generate electricity.
Since wind power accounts for 2% of the nation’s portfolio, we can deduce that 14% of the renewable energy forms were derived from wind power in 2000, nationally. In the Pacific Northwest, we are fortunate in that a significant amount of the resource used to serve base load energy demand is supplied through the use of hydroelectric power, which is renewable. From a sustainability perspective, it would be ideal, if we could serve the nation’s entire demand with renewable resources. Unfortunately, the nation’s energy portfolio does not currently reflect this ideal. Our development of wind energy in the US is far behind our European counterparts.
In the US, we have the resource available (it is a function of weather patterns), but we have not made it a priority, at the national level, to direct significant resources toward developing wind generation facilities. Instead, we have focused our priorities on enhancing existing infrastructure. Our primary energy source continues to be coal power, currently contributing 55 percent of the nation’s resource mix. While coal is relatively cost-effective and quantifiable, sourcing that much of our nation’s resource generation from coal is shortsighted when analyzed in the context of the long-term environmental impact of prolonged reliance on coal to meet the nation’s energy needs. Granted, Wind power is not as reliable as coal, but it could be used when the resource is available as a means by which to decrease the reliance on coal, which has obvious environmental costs.
Currently, wind power is used as a peak-demand resource and there is undeveloped land with huge potential for wind power generation in Wyoming, Montana, North Dakota, and the Aleutian Islands, to name a few. If wind power facilities were to be developed in these areas, the energy industry could better manage its obligation to serve the more rural areas that are characteristic of the population densities in these states, while decreasing transmission costs; a type of distributed renewable generation model. The fact is that on the national level, we have not made it a priority to capitalize on this untapped and renewable resource. There is a significant landmass that can be developed into wind farms to capitalize on this surplus capacity.
There has been a failure at the policy level to address the increasing harm that our energy policy inflicts on the environment. This is partly due to the fact that it is hard to quantify the externalities associated with prolonged use of hydrocarbons on the environment. We are not directing resources toward developing our renewable power generation infrastructure, because the benefit of doing so (avoided social cost of coal reliance) has not been quantified.
The private sector takes its leadership from government direction and as such the initiative needs to come from the top-down. We need a national policy that encourages the private sector to develop more wind-generating capacity. If the US were to craft a policy that aimed at increasing the wind power component to our nation’s energy portfolio to 20%, then the effect would be a massive restructuring of power generation infrastructure; decisions about how to allocate resource would change drastically and we would witness a massive investment in wind generation facilities, which would in turn reduce the environmental impact of our energy consumption.
A problem that utilities face, when deciding how to allocate resource to meet their load-requirements is that they may not own the rights to the entire load needed to serve a given market on a given day. The utility may expect demand to be 10 Megawatts (MW) tomorrow, but may only have 5 MW in their portfolio, today. In this case, the utility is said to be “short” 5 MW and there is no limit on the risk to which they are exposed of price volatility. They are obligated to serve the load and obviously being “short” on load is a situation that utility would strive to avoid in order to mitigate market risk.
The price per MWh could vary significantly over the course of a day, depending on changes in market dynamics. The 5 MW load, which the utility must serve, could become very costly in the presence of price volatility. In contrast, the utility is said to be “long”, if it owns the rights to more resource than it needs to serve a given expected load over a given time period (usually the next day). The utility does not aim to lose value associated with load. As a hedge against this exposure, the utility has the ability to sell the load on the open market to recuperate the expense associated with generating the load, plus some premium. Due to their cost-minimizing nature, utilities will attempt to equilibrate their resources against the loads that they expect to serve.
When the utility makes decisions regarding how to allocate resource, it generally uses a cost-benefit methodology, because they need to be able to quantify the factors that might affect the outcome of the decision. However, there are factors that might affect the outcome of the decision that are difficult to quantify, such as risk. The risk that a utility confronts can be characterized by the exposure to price volatility in response to changing market conditions over a given time-period between which the utility forecasts the load requirement and the time at which that utility must serve the load. Naturally, it would be valuable to be able to quantify risk, as it could be more easily factored into the analysis of how to optimize resource allocation.
Risk is quantified by the variance from an expectation, as represented by the mean in a probability distribution; in this case, price per MWh. To deal with the problem of risk-quantification, the energy industry has borrowed an analytical concept from financial markets called Value-at-Risk (VaR). In the context of the utility, VaR measures the risk of an instrument in a portfolio deviating from its existing marked-to-market value within a defined certainty based on a statistical measure of volatility, over a given time-period. The basic calculation for VaR is “cash * volatility * confidence factor”. It is a measure of market price risk and represents the value that is subject to loss over a specified period of time, due to market price volatility. Utilities use the VaR metric to assess their net revenue price risk exposure. In other words, the risk that VaR measures is the net revenue (retail sales less operating and purchase costs) impact of changes in wholesale energy prices (electricity and natural gas mostly), over time. Thus, unless there is a sort of national pooling of revenue risk, it makes very little sense to analyze the VaR of the national portfolio; it is a utility level analytical tool, used for risk management purposes.
From the utility’s perspective, managing portfolio risk is of strategic importance, because of their obligation to serve and cost-minimizing nature. The role of renewable energy resources in utility portfolio risk reduction has been cited to support the claim that the fixed cost nature of renewable energy resources, as opposed to fuel or variable cost, should earn these projects a premium over traditional resources such as natural gas fired power plants. In order to install a renewable generation power plant, the power generator must outlay a significant capital expenditure in the short-term to launch the facility; the fixed costs are front-loaded and constitute a significant capital outlay in the current period. In the longer term, however, the cost to maintain the facility is considerably less than the amount that it would cost to maintain a more traditional hydrocarbon facility. The power generator must only concern themselves with the operations and maintenance of the facility, because the fuel is “free”; at least, if one ignores environmental and social costs, which are still less than those of hydrocarbons. In order for the argument that renewable energy sources mitigate utility portfolio risk to be effective, it is necessary to analyze portfolio risk from the utility’s perspective.
The degree to which price volatility is significant in utility resource planning decisions depends on the individual utility’s reliance on the open market to meet load; risk sensitivity to price volatility for a given utility, depends on their individual generation infrastructure in relation to the load profile of the region that they are obligated to serve. For a utility that purchases its entire portfolio from the wholesale market, it is true that adding fixed cost resources, which are not subject to wholesale price volatility, would reduce their net revenue risk exposure. However, for a utility that is heavily weighted in fixed cost resources such as the BPA with significant hydro and nuclear resources, adding fixed cost resources actually increases net revenue volatility and hence portfolio VaR.
As an example, from the standpoint of a vertically integrated utility such as PacifiCorp, which has a resource mix of 80% coal, 15% hydro, and a rising gas portfolio, this position can become quite complex. In the PacifiCorp case, the positive effect of added Wind resource is not evident. In the wholesale price rally of 2000, PacifiCorp purchased power off of the wholesale power generation market to meet peak loads during the day at very high prices, while at night they sold higher quantities of surplus coal generation at lower, but still above-average prices, which had the effect of PacifiCorp’s off-peak surplus serving as a hedge against their on-peak short.
The extent to which a national policy that would require increasing the nation’s energy mix to 20% would impact utility portfolio risk would depend on the utility’s unique resource mix. The current relative high cost of wind power generation, is a function of its relative scarcity among portfolio alternatives and its intermittence; these factors have driven the cost of generating wind power to a level where the utility only finds it useful to employ in serving peak loads. If wind power’s scarcity were to be reduced by a policy-level commitment of resources to developing wind power infrastructure, wholesale power generators and utilities alike would invest resources into developing wind-generation facilities, in strategically appropriate regions so as to best capitalize on weather patterns and load commitments. This would then decrease the cost of supplying the renewable resource and it would serve to motivate utilities and power generators to invest in more wind power generating facilities.
(1) Silverstein, Ken,
IssueAlert, Nov 18, 2004, UtiliPoint.
Sean Reilly is a self-employed Grad Student/Business Analyst.
Edward A. Reid, Jr., 5.13.05
Utility gross revenues, net revenues, gross margins, net margins, return on rate base and return on equity are not guaranteed. Utilities regulators set an "allowable rate of return", which may or may not be achieved (or achievable) depending on weather and the level of economic activity in the utility's service territory. If a utility under-recovers its costs, tough. However, if a utility over-recovers as a result of abnormal weather or a surging economy, it is excoriated in the public press and may be forced to refund most or all of the excessive revenue to customers.
Utilities which own generation have varying degrees of capacity reserve margin, depending on regulator approval and rate of growth of energy demand. It is this conventional capacity reserve margin, plus power purchases in the wholesale market, that allows the utilities to meet demand during periods when intermittent renewable sources of generation are not available. This works well as long as the conventional capacity reserve margin exceeds the intermittent generation capacity. The system begins to break down as the intermittent generation fraction approaches the conventional capacity reserve margin.
Wind generation is currently treated as a "source of opportunity", used when it is available and replaced with conventional generation when it is not. Current wind generators have availability factors approaching 38%. However, according to AWEA, a transition of wind generation from a "source of opportunity" to a reliable source requires the installation of 8-10 wind generators of the required capacity located at different, carefully selected locations. While these 8-10 generators will produce more energy than the rated output of any one single generator under almost all conditions, and this power can be used to serve other loads, utility level reliability demands the installation of the multiple, distributed generators. Therefore, provision of 1 mW of reliable wind generated power requires the installation of 8-10 mW of wind generation capacity. Therefore, while the energy cost of reliable wind energy approaches zero, the capital cost far exceeds the cost / mW typically quoted for wind generation.
California will likely find itself on the "bleeding edge" of this issue, as the result of its renewable portfolio standard and its very low capacity reserve margin, particularly if it doesn't start raining or snowing again soon.
Sean Reilly, 5.15.05
Utilities are guaranteed an allowable rate of return as set by the regulatory body that oversees their operations. The point of the regulatory compact is that the utility does not lose money and does not use its market power, characteristic of a monopoly, to gauge customers and set their own rate of return.
If policy creates an investment environment that motivates power producers to install additional wind capacity, then the intermittency issue would diminish and the cost of supplying the resource would become more efficient, as installed capacity would increase. Power producers would invest in more capacity and utilities would not need to keep as much reserve margin convenient to meet load (there is also risk associate with the lost revenue of unused resource). This increased installed capacity would provide more resource and the price volatility of power would come down, which would in turn reduce utility portfolio risk.
Furthermore, let us not forget that some of the greatest wind development opportunities exist in rural locations, which presents increased costs to the utility in the form of energy transmission ($1 mn per mile). Who pays for that? The rate payers in more centralized urban areas subsidize the service to these rural ratepayers.
You are right; from a reliability standpoint wind is not the resource on which to rely to meet the utility’s entire load profile. A utility portfolio is a system of generation resources that serve various reasons. Wind is not used for its reliability value. If opportunities are capitalized on by power producers and more capacity is installed, then wind would become more reliable.
Utilities are cost-minimizing, per regulatory mandate. Thus, when comparing the costs between renewable resources and hydrocarbons, the utility should not ignore the non-quantifiable costs to society of generating power from hydrocarbon resource. The costs to society of using hydrocarbons to generate power are difficult to quantify. The net social cost (i.e. externality) of generating the power is not “priced in” to the existing hydrocarbon power generation infrastructure. As a result, resource is not being allocated efficiently; price does not reflect all costs to society. Externalities, or social costs, are not reflected in the price of the load, because of the difficulty quantifying the negative environmental impact related to producing the power with hydrocarbons.
This in ability to quantify the societal costs of energy production is referred to as the "missing market phenomenon". As an example of negative environmental impacts resulting from too much reliance on hydrocarbon resource, both Ohio and Wyoming serve as nodes from which coal is sourced and processed for generation (Wyo. has huge wind potential, by the way). The energy is then transmitted elsewhere, depending on the demands of the grid, while the environmental costs associated with the energy production are borne by the people living in the region where the power was produced.
To measure these externalities, one might analyze the incidence of something like asthma in a given region and compare it to a control group, such as the rest of the country, in order to estimate the statistical significance of any variance or noted local average increase in asthma cases with respect to the control group. There have been studies that have shown a link between increased asthma cases in the Northeast and the heavy concentration of coal generation in Ohio. These external costs are borne by society as a whole; this power generation market is not very efficient as price is not efficiently allocating resource. What is the cost to society of such externalities?
In addition, if one compares the Average Revenue Requirement (ARR) between renewable resources, such as wind, against those of their hydrocarbon counterparts, one will see that the ARR of these renewable resources are less than their hydrocarbons over the long haul . This is due to the fixed cost nature of the wind turbines. Utilities avoid fuel price volatility risk exposure and only pay operations and maintenance (O&M) costs on the facilities (no fuel cost). Fuel cost is a variable cost and the utilities employing hydrocarbon facilities face significant price risk exposure in the long-term. If one weighs the two options, given that the utility is bound to be cost-minimizing, renewable generation resources are attractive in the long term.
Reliability is mission-critical to the utility, but wind is typically not used for its reliability value (yet). Instead, it is currently included in a utility's portfolio to meet peak load demands. I am not advocating that we re-invent the wheel; there is still a place for hydrocarbons in the nation's energy mix. I am just calling attention to the value of increasing the portion of the portfolio that is renewable.
Edward A. Reid, Jr., 5.15.05
"Utilities are guaranteed an allowable rate of return as set by the regulatory body that oversees their operations."
You are correct that the regulatory body sets an ARR, usually based on anticipated unit energy sales assuming normal weather and business activity. Rates are then set for each customer class which would result in the utility being able to earn the ARR under normal conditions. However, if the economy slows or weather is abnormally mild and the utility does not sell the anticipated quantity of energy on which the ARR is based, the utility underearns the ARR. There is no "true up" to the ARR. However, if the reverse occurs and the utility overearns the ARR significantly, there may well be a "true down" through a refund mandated by the regulatory body.
Earnings variations occur because utilities' monthly service charges (fixed charges) do not cover 100% of the utilities' fixed costs, but more typically 25-35% of fixed costs. Therefore, the bulk of the utilities' fixed costs are recovered in the variable portion of the utilities' rates. Theoretically, utilities' variable costs vary directly with energy sales and are thus always fully recovered in rates. Practically speaking, fuel cost adjustment clauses make this almost true. However, there is no sales volume adjustment clause which assures full fixed cost recovery. Therefore, while there is a "guarantee" in the "utility compact" that the regulatory body will set an ARR, there is no guarantee that the utility will be able to earn the ARR in any given year.
Utilities cannot practically take into account the environmental externalities costs of their powerplant emissions without the concurrence of the regulatory body which sets their rates. Commissions have frequently resisted major investments in emissions control equipment, even when those investments were required to achieve compliance with environmental laws. The likelihood, for example, that the Public Utility Commission of Ohio would approve the installation of BACT-level SOx and NOx controls on all coal plants in Ohio AND ALLOW RATE RECOVERY OF THE INVESTMENT to reduce the incidence of asthma in New England approaches zero asymptotically, absent a federal mandate to do so. New England has been trying to get the feds to issue such a mandate for decades. The PUCO has so far not volunteered to have the Ohio utilities proceed with the control equipment installations absent the federal mandate.
I am not arguing that there is no role for wind generated energy in a utility's generation mix. I am arguing that the application of wind generators with 30-40% individual availability is very different if their output must be a "reliable source" in the utilities' portfolio, rather than a "source of opportunity". Too many discussions of the cost of wind-generated energy "gloss over" this very important distinction. [For example, if you were to calculate the number of identical, dispersed wind generators of 35% availability required to achieve the output of any one of those generators with utility level reliability (~ 99.99%) you would determine that ~20 wind turbines would be required. This number would decline with the installation of a storage buffer. This calculation would suggest that the investment in "reliable" wind energy is far higher than the investment in "opportunity" wind energy; and, that the unit energy costs are also substantially higher.]
It is also important to remember that the value of wind-generated energy for peaking service is very much a function of the timing of the availability of the power relative to the timing of the peak demand for the power. In the future, storage technologies may make it economically practical to deal with this timing issue, although at some incremental investment and continuing in & out energy losses.
I accuse utility regulators and state legislatures which adopt RPS requirements, without dealing with the reliability issue, of "beginning vast programs with half-vast ideas". California's contemplated combination of a ~7% capacity reserve margin and a 20% RPS is a disaster looking for a place to happen. It will be an interesting experiment, but it is being conducted on a very large scale.
Jack Ellis, 5.16.05
I happen to agree with many of the points Mr. Reid makes. Wind energy isn't reliable enough to cost-effectively provide the level of service customers have been conditioned to expect. It is highly doubtful that all the government support in the world, save actually paying the entire capital cost of the required number of wind machines, will change things.
However the intermittent nature of wind power is not it's only drawback. Most people don't like looking at wind machines, and many people are very concerned about the impact of hundreds of rotating blades on wildlife. It turns out that wind power, like almost every other source of energy, has environmental and aesthetic impacts that induce otherwise rational people to demand they be placed somewhere else.
One of the few places in the world where wind machines could be cost-effectively integrated with other electricity-producing resources to provide low cost, reliable electric service is the Pacific Northwest. Power system engineers have known for a long time that the combination of even modest amounts of hydro storage and wind combines the best attributes of both resource types and practically eliminates the worst ones. However it appears wind developers are encountering fierce resistance to their plans for wind farms in eastern Washington. That's a real tragedy.
I would submit that placing wind generators, or any other generating resources for that matter, hundreds or thousands of miles from urban load centers is a waste of resources. Remote generation can be made to work, but it isn't as reliable or as cost-effective or as secure as having generation close to where it's consumed.
Edward A. Reid, Jr., 5.17.05
1) Hydropower consists of a "reliable source" component and a "source of opportunity" component. BPA has recently had to reevaluate the percentage of its generation capacity which is reliable, as the result of a protracted drought. On the other hand, they crashed the western grid twice in 1996 when they delivered excess opportunity power to the grid. The intermittency of hydropower has a very long cycle time, especially compared to windpower. Therefore, hydropower support for windpower must be based solely on the reliable component of the hydropower.
2) The contribution of hydropower-supported windpower will be limited by the availability of new reliable hydropower sources, since all available reliable hydropower is already committed. The resistance to the construction of new hydropower dams is, if anything, more visceral than the resistance to the construction of new wind turbines.
Meeting the population-driven growing energy needs of the US economy will be tough enough without the "help" of NIMBY and BANANA.
Christopher Pflaum, 5.17.05
Reminds me of the undergraduate term papers that I used to read in an earlier life.
Sean Reilly, 5.17.05
Reliability becomes less of an issue when a demand side management program in place; treating demands as a resource mitigates the strains on the system. Wind is currently used for peak clipping, but in a system with less demand (i.e. those with DSM programs), the reliability imperative is easier to achieve, which means that renewables such as wind are able take a more prominent role; the intermittency issue has less of an impact on reliability.
Edward A. Reid, Jr., 5.18.05
Sean, If you are interested in "peak clipping", try real time pricing.
Prices in excess of $1,500 / mWh will clip peaks like nothing else known to man.
Rolled-in costs at the same level (the DSM approach) have far less real impact.
Please send mail to
firstname.lastname@example.org with questions or comments about this web site. Minnesotans For Sustainability
(MFS) is not
affiliated with any government body, private, or corporate entity.
Copyright © 2002, 2003, 2004
Minnesotans For Sustainability