In the context of energy markets, utilities constantly manage resources to meet their obligation to serve their customer base, while minimizing their costs, in exchange for a service-monopoly with a guaranteed return on investment. The electricity market is changing. In the days of the vertically integrated utility, when generation, transmission, and distribution were managed by a single entity (i.e. the utility), this commission was considerably simpler than it is in the modern era of deregulated wholesale power generation markets. Many utilities meet their obligation to serve through a combination of maintaining proprietary generation facilities and relying on the wholesale power market to respond to peak demand periods.

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.

References

(1) Silverstein, Ken, IssueAlert, Nov 18, 2004, UtiliPoint
(2) http://www.utilitywarehouse.com/info/fortworth.htm, accessed on 11/29/2004
(3) http://www.eia.doe.gov/cneaf/solar.renewables/page/wind/wind.pdf, accessed on 11/29/2004
(4)http://www.nwppa.org/web/presentations/3%20BWalshe_Expanding_Role_of_Renewables.pdf, accessed on 11/28/04
(5) www.ispe.arizona.edu/research/swassess/companion/greenhouse.pdf, accessed on 11/29/2004
(6)http://www.wtltrading.com/definitions.htm, accessed on 11/28/2004