Assessing the Short-Run Economic Cost of Environmental Constraints on Hydropower Operations at Glen Canyon Dam.(Statistical Data Included)

I. INTRODUCTION

Hydropower plants produce electricity without burning fossil fuels and producing air pollution and are sometimes thought of as environmentally benign. In fact, large hydropower facilities have blocked the spawning of anadromous and migratory aquatic species, eliminated the downstream transport of sediment, fundamentally altered the seasonal hydrograph, affected water chemistry, and, changed the downstream temperature regime (Collier, Webb, and Schmidt 1996). Furthermore, the daily operations of these units, particularly units used to produce peaking power, may have a number of adverse effects on aquatic and riparian communities (Nilsson, Jansson, and Zinko 1997).

The environmental externalities resulting from the construction and operation of a number of hydropower plants are now being re-examined. Nationwide, Federal Energy Regulatory Commission (FERC) licenses to operate 520 hydropower plants have, or will, expire between 1997 and 2010 (Hunt and Hunt 1997). In addition to relicensings, endangered species concerns have lead to the reassessment of a number of other facilities. Although dam removal is an option in some cases (Loomis 1996), the focus of many recent analyses is on identifying new operational regimes which will result in improved downstream environmental conditions. These new regimes may well create significant market and nonmarket benefits but the resultant constraints on hydropower operations inevitably lead to economic costs of varying magnitudes.

This paper introduces an hourly constrained optimization framework for analyzing the effects of environmental constraints on hydropower operations. The short-run economic cost of these impacts is determined using market-based prices. Glen Canyon Dam, located on the Colorado River in Arizona, is used as a case study.

II. BACKGROUND

Electricity cannot be efficiently stored on a large scale using currently available technology. It must be produced as needed. Consequently, when a change in demand occurs, such as when an irrigation pump is turned on, somewhere in the interconnected power system the production of electricity must be increased to satisfy this demand. In the language of the utility industry, the demand for electricity is known as "load." Load varies on a monthly, weekly, daily, and hourly basis. During the year, the aggregate demand for electricity is highest in the winter and summer when heating and cooling needs, respectively, are greatest. Load is less in the spring and fall which are known as "shoulder months." During a given week, the demand for electricity is typically higher on weekdays, with less demand on weekends, particularly holiday weekends. During a given day, the aggregate demand for electricity is relatively low from midnight through the early morning hours, rises sharply during working hours, and falls off during the late evening.

Electric energy is most valuable when it's most in demand - during the day when people are awake and when industry and businesses are operating. This period, when the demand is highest, is called the "on-peak period." In the West, the on-peak period is defined as the hours from 7:00 A.M. to 11:00 P.M., Monday through Saturday. All other hours are considered to be off-peak.

The maximum amount of electricity which can be produced by a powerplant is called its capacity. Capacity is often measured in megawatts (MW). The capacity of thermal powerplants is determined by their design and is essentially fixed. In the case of hydroelectric powerplants, capacity varies over time because it is a function of reservoir elevation, the amount of water available for release, and the design of the facility. The rate at which a powerplant can change from one generation level to another is called a "ramp rate." For hydropower plants, this is typically measured by the change in flow, measured in cubic feet per second (cfs), over a one hour period. Ramp rates vary widely depending on the type of powerplant, its design, and possible operational constraints.

Ignoring pumped storage facilities, there are two principle types of hydropower plants. These are run-of-river plants and peaking plants. Run-of-river plants typically have little water storage capability. Consequently, generation at run-of-river plants is proportional to water inflow and there is little variation in electrical output during the day. Peaking hydropower plants, such as the one at Glen Canyon, often have significant water storage capability and are designed to rapidly change output levels in order to satisfy changes in the demand for electricity. Peaking hydropower plants are particularly valuable because they can be used to generate power during on-peak periods avoiding the cost of operating more expensive thermal plants such as gas turbine units. Hydropower plants are also more reliable than thermal plants and do not generate emissions.

III. ECONOMIC VALUE OF HYDROELECTRICITY

The economic value of operating an existing hydropower plant is measured by the avoided cost of doing so. In this context, avoided cost is the difference between the cost of satisfying the demand for electricity, with and without operating the hydropower plant. Conceptually, avoided cost is the savings realized by supplying electricity from a low-cost hydropower source rather than a higher-cost thermal source. These savings arise because the variable cost of operating a hydropower plant is relatively low in comparison to thermal units. For example, the variable costs of operating an average hydropower plant in 1995 was $5.89 per megawatt hour (MWhr). In contrast, the variable cost of operating the average fossil-fuel steam plant was $21.11 per MWhr and the variable cost of operating the average gas turbine peaking unit was approximately $28.67 per MWhr (Energy Information Administration 1996b).

The economic value of operating an existing hydropower plant varies considerably with time of day. The variable cost of meeting demand varies on an hourly basis depending on the demand for electricity, the mix of plants being operated to meet demand, and their output levels. During off-peak periods, demand is typically satisfied with lower cost coal, run-of-river hydropower, and nuclear units. During on-peak periods, the …