Chapter 2 identifies and compares Western's power marketing commitment-level alternatives, including the no-action alternative, and describes the hydropower operational scenarios evaluated in this EIS for Glen Canyon Dam, Flaming Gorge Dam, and the Aspinall Unit. The bases for selecting the commitment-level alternatives are discussed in Section 2.2.1, and the alternatives selected are described in Section 2.2.2. The potential environmental impacts of these alternatives are summarized in a comparative format in Section 2.2.3.
The hydropower operational scenarios are addressed in Section 2.2. Section 2.2.1 describes the relationships between commitment-level alternatives and the operation of hydropower facilities. Section 2.2.2 discusses hydropower operations, purchases, and exchanges; Section 2.2.3 describes the hydropower operational scenarios selected for analysis for each facility. The impacts of these scenarios are compared in Section 2.2.4.
Western needs to establish the level of its commitment for sales of long-term firm electrical capacity and energy generated by the SLCA/IP. As indicated in Chapter 1, these commitments are included in contracts establishing the terms for how capacity and energy are to be sold by Western.
Capacity is equivalent to the instantaneous output of a generator, usually stated in units of megawatts (MW)1 or kilowatts (kW).2 Generators are rated for their maximum capacity under specific conditions; this capacity is usually referred to as "nameplate generating capacity." Energy is the amount of power generated over a period of time and is stated in megawatt-hours (MWh)3 or gigawatt-hours (GWh).4 A level of commitment for sales specifies amounts of long-term firm capacity and energy.
The commitment-level alternatives, including the no-action alternative, evaluated in this EIS are defined on the basis of a specified level of both capacity and energy. This level of capacity and energy comes from two sources: hydroelectric power generated by SLCA/IP facilities and purchases from other sources. Western may purchase capacity and energy from any entity offering them for sale. The commitment-level alternatives cover a broad range of capacity and energy levels that Western could make available to its customers. The following section describes how these possible commitment levels were selected for evaluation in this EIS.
The selection of commitment-level alternatives was based on the combinations of capacity and energy that would feasibly and reasonably fulfill Western's firm power marketing responsibilities and statutory obligations. The generation capability of the SLCA/IP is only one part of the basis for determining the amount of power available for long-term firm contracts. The other part consists of energy purchases and interchanges. Interchanges are agreements that Western has with other utilities to trade generation resources from different locales to increase total system efficiency or avoid transmission limits that would occur without such agreements. Purchases and interchange are key elements in Western's power marketing activities. Without purchases and interchange, Western might have to reduce its long-term firm commitments to about one-third of historical levels. Western would have to market on the basis of highly variable hydrological conditions and could not make long-term firm commitments to power deliveries in excess of that available under worst possible, highly improbable, drought conditions. In fact, it would be impractical for Western to make any long-term firm commitments that maximize the value of the hydropower resource without purchase flexibility.
The amount of SLCA/IP capacity and energy available for Western to market is determined after other needs are met, including the dam and power plant operators' station service requirements and dedicated uses for Bureau of Reclamation projects such as irrigation, maintenance requirements, and Western's reserves and system losses. The amount of marketable capacity and energy that can be generated by SLCA/IP power plants varies from year to year, depending on hydrological conditions (e.g., water flows), reservoir storage requirements, and downstream flow requirements.
Variations in hydrological conditions and other factors result in a risk that the SLCA/IP power plants would not be able to generate sufficient capacity and energy to meet Western's long-term firm commitments. For this reason, the amount of marketable long-term firm capacity and energy committed under each alternative is directly related to the level of risk Western assumes on behalf of its customers over the life of the contract. The risk Western assumes is essentially one of not having sufficient hydroelectric generation to meet contract commitments. However, Western's extensive transmission system allows it to make purchases over a wide region, and contracts ensure that purchase costs will be paid by the customers.
The amount of SLCA/IP capacity and energy that Western offers as long-term firm commitments is influenced by such factors as (1) the amount of installed hydroelectric capacity in the system; (2) restrictions on minimum and maximum water releases by each facility; (3) limitations on operations to protect or enhance natural, cultural, and recreational resources; (4) anticipated water conditions and water depletions; (5) resultant reservoir operations; (6) the amount of power needed by facility operators, such as Reclamation; (7) dedicated project uses; and (8) the electrical energy market and the availability of regional electrical resources. Because many of these factors are uncertain and highly variable over time, Western, with assistance from Reclamation, forecasts probable future conditions for a given period and sets its level of long-term firm capacity and energy commitments according to these predictions and sound business principles. These forecasts include both upper and lower limits of capacity and energy.
Limits to Power Production: As a starting point to establish the boundaries of reasonable levels of projected power considered in this EIS, Western assumed that the maximum installed capacity for the SLCA/IP would be approximately 1,800 MW. Installed capacity might change over the life of hydropower facilities because unit modifications can be made as technology advances. Installed capacity is greater than marketable capacity because water is available to operate at the maximum limit (installed capacity) only for limited periods.
Prior to 1977, before Western was established as a power marketing agency, Reclamation had based its long-term firm power commitments on a conservative adverse risk assumption; that is, the minimum level of power that could be expected to be available in some future period, even in the poorest water years. Western continued this practice until the development of the Post-1989 Criteria, when Western modified this historical risk assumption by considering a "10% risk" assumption as reasonable. This means that in approximately 1 year out of 10, the water levels behind the system dams would not be sufficient to produce the capacity needed to support the Post-1989 commitment level. This 10% risk approach was applied to a projection of future available power for the SLCA/IP for the period 1989 through 1999. That projection was based on an assumption of maximum flexibility in daily releases. In other words, within the minimum and maximum flows set by Reclamation (the dam operator) before 1989, no restriction would be set on daily fluctuations at each hydropower facility. This assumption of 10% risk coupled with full operational flexibility resulted in the upper boundary of marketable firm capacity of 1,450 MW.
To determine a lower limit of power operations, Western considered restricted release rates potentially affecting the Glen Canyon Dam, the principal hydropower resource of the SLCA/IP. Future additional constraints that may be placed on operations at the Flaming Gorge and Aspinall Unit facilities were also considered. Under assumptions of (1) future constant (nonfluctuating) releases at all SLCA/IP facilities and (2) continued worst-year water conditions for future years, the maximum level of marketable capacity after all adjustments would be approximately 550 MW. This value was identified as the assumed lower boundary of marketable firm capacity for the purpose of selecting commitment-level alternatives. This level provides minimum flexibility and essentially no risk.
Limits to Energy Production: Before 1977, Reclamation based long-term firm energy commitments on annual average energy generated by its facilities. To identify the upper boundary of long-term firm energy commitments for selection of alternatives for this EIS, Western assumed a 54% risk (average energy plus 400 GWh). This level of risk would equate to about 6,200 GWh annually (adjusted for losses and project uses), which corresponds to the limit on available transmission system capacity. For the lower boundary, assumptions of no risk and no purchases would result in a minimum energy commitment of approximately 3,300 GWh for the worst hydrologic year.
Figure 2.1 schematically illustrates the upper and lower boundaries of capacity and energy. The left side of the diagram indicates the lower, no risk, low flexibility boundary of marketable firm capacity (550 MW). The right side of the diagram is the upper, 10% risk, high flexibility boundary of marketable firm capacity (1,450 MW). The bottom of the diagram is the lower boundary of marketable firm energy (3,300 GWh), and the top is the upper boundary of marketable firm energy (6,200 GWh). Any point within the diagram represents a combination of marketable long-term firm capacity and long-term firm energy. Western could choose to market any combination of capacity and energy within the diagram.
Figure 2.1 also explains the desirability of the different commitment-level alternatives to Western's customers. The ratio of energy to capacity is called the load factor. The higher the amount of energy per unit of capacity, the higher is the load factor. Each of the diagonal lines in Figure 2.1 represents combinations of capacity and energy that yield the same load factor. Moving from the lower right corner to the upper left corner of the
diagram, the load factor increases from 25% to 100%. When the load factor is low, the customer has more flexibility regarding when it takes delivery of the amount of energy it has committed to purchase. Thus, with a low load factor, energy can be used just to serve the additional load that arises during peak demand periods. In addition, the customer has more flexibility over the decision of whether to substitute less expensive energy for energy that could be produced by more expensive technologies. As the load factor increases, the customer must take energy on a more regular basis to ensure it takes the total amount of energy that it has committed to purchase (and Western has committed to deliver). Because the customer has less control over when it takes delivery of this energy, the usefulness of the energy declines. In this case, a customer may find itself in the position of having to purchase energy from Western in periods (e.g., off-peak) when that energy really is not needed or economical.
The area within Figure 2.1 defines all reasonable amounts of marketable firm commitments for capacity and energy. Points within this diagram represent combinations of either high or low capacity with either high or low energy. (These points represent alternatives, which are described below.) The values at the four corners of this diagram were selected as commitment-level alternatives. These values represent the reasonable bounds of capacity and energy given current resources. Alternatives 1, 2, 4, and 5 represent high capacity and high energy, high capacity and low energy, low capacity and low energy, and low capacity and high energy, respectively. Two moderate capacity and moderate energy alternatives (3 and 6) are also shown in Figure 2.1 These six alternatives (commitment levels 1-6) and the no-action alternative (the 1978 commitment level) have been carried forward for analysis in this EIS.
A minimum schedule requirement is also a component of each alternative. The minimum schedule requirement is the minimum quantity of capacity that a contract customer must accept on an hourly basis. This is an important component of each alternative and changes with each combination of capacity and energy. A high minimum schedule requirement (e.g., 35%) would negate the flexibility of the low load factor alternatives by requiring that so much energy be used around the clock that very little energy is left to schedule when it is needed. Therefore, alternatives with low load factors also have low minimum schedule requirements.
This section describes the commitment-level alternatives assessed in this EIS, including the no-action alternative. The features of these alternatives are summarized in Table 2.1.
| Alternative | Capacity Commitment (MW) |
Energy Commitment (GWh) |
Load Factor (%) |
Minimum Schedule Requirement (%) |
Description |
| No action | 1,291 | 5,700 | 50 | 35 | Moderate capacity and high energy (the 1978 marketing program commitment level) |
| 1 (preferred alternative) | 1,449 | 6,156 | 48.5a | 35 | High capacity and high energy (the Post-1989 commitment level) |
| 2 | 1,450 | 3,300 | 26 | 10 | High capacity and low energy |
| 3 | 1,225 | 4,000 | 37 | 15 | Moderate capacity and moderate energy |
| 4 | 550 | 3,300 | 68 | 52 | Low capacity and low energy |
| 5 | 625 | 5,475 | 100 | 100 | Low capacity and high energy |
| 6 | 1,000 | 4,750 | 54 | 33 | Moderate capacity and moderate energy |
a This load factor differs slightly from that published in the Post-1989 Marketing Criteria (50.2%) because of a difference between calculating this number annually versus seasonally.
If Western were to take no action to change the level of its long-term firm capacity and energy sales, commitments would remain at the 1978 power marketing program levels for the CRSP, Collbran, and Rio Grande projects. The 1978 program contains commitments for 1,291 MW of long-term firm capacity and 5,700 GWh of long-term firm energy (Figure 2.1). This alternative has a load factor of 50% and a minimum schedule requirement of 35%.5
Commitment-level alternative 1, or the Post-1989 commitment level, is associated with the proposed 1989 marketing plan and is the preferred alternative. This commitment level is for 1,449 MW of long-term firm capacity and 6,156 GWh of long-term firm energy. The energy offered under this alternative represents the highest energy commitment among all alternatives (about 8% higher than the no-action alternative). This commitment level has a load factor of nearly 50%. In addition, it imposes a minimum schedule requirement of 35% on long-term firm customers.
Commitment-level alternative 2 is a commitment to a high level of long-term firm capacity (1,450 MW) but a low level of long-term firm energy (3,300 GWh). This commitment level has the lowest load factor (26%) and lowest minimum schedule requirement (10%) of all the alternatives. This type of commitment would enable customers to take the highest percentage of their commitment during the on-peak hours, when power is most valuable. Although customers would gain value by purchasing a low load-factor resource, the value of this alternative would be diminished by the low energy commitment.
Commitment-level alternative 3 is a commitment to a moderate level of long-term firm capacity (1,225 MW) and a moderate level of long-term firm energy (4,000 GWh), as shown in Figure 2.1. This commitment results in a load factor of 37% and a minimum schedule requirement of 15%, the second lowest load factor and minimum schedule requirement of all the alternatives.
Commitment-level alternative 6 also is a commitment to a moderate level of long-term firm capacity (1,000 MW) and a moderate level of long-term firm energy (4,750 GWh). This alternative represents the midpoint of the ranges of capacity and energy, as illustrated in Figure 2.1. This commitment level has a load factor of 54%, which is mid-range between a high-load and a low-load resource, and a minimum schedule requirement of 33%.
Commitment-level alternative 4 is the lowest commitment for long-term firm capacity (550 MW) and long-term firm energy (3,300 MWh), as shown in Figure 2.1. It is based on an assumption of continued adverse water conditions. This commitment level has a load factor of 68%, the third highest of all alternatives. The minimum schedule requirement of 52% is the second highest of all alternatives. Commitment-level alternative 4 offers the lowest long-term firm commitment of capacity and energy at a high load factor.
Commitment-level alternative 5 is characterized by a low level for long-term firm capacity (625 MW) and a high level for long-term firm energy (5,475 MWh). The load factor and minimum schedule requirement for this alternative are both 100%, indicative of a base-loaded resource. Under this alternative, the customer would have to take energy at the stated capacity at all times in order to meet its purchase commitment. This situation would not allow the customer flexibility to vary the energy it takes to meet varying load requirements throughout the day or over the period of a week or a month.
A number of elements would be common to all commitment-level alternatives and would occur to minimize the impact of any commitment-level alternative. These common elements include:
The analyses conducted for this EIS indicate that for each environmental resource or attribute, the impact of each commitment-level alternative is related to the hydropower operational scenarios implemented.6 This situation is especially true for impacts to water, ecological, cultural, and visual resources, land use, and recreation; impacts to these resources would be almost exclusively a result of the hydropower operations employed. Impacts of hydropower operational scenarios are presented in Section 2.2.4.
The impact of commitment-level alternatives on socioeconomics would depend on the specific mix of hydroelectric generation, purchases, and exchanges that constitutes the power marketed by Western. Therefore, to evaluate the impacts of commitment-level alternatives, three different supply options were defined that specified hydropower operational scenarios at Glen Canyon Dam, Flaming Gorge Dam, and the Aspinall Unit and the purchases that would be needed to meet the commitments of long-term firm power specific to each alternative. These supply options were chosen because they cover the full range of dam operations possible at the three facilities and represent the maximum, median, and minimum levels of impact to wholesale power costs. They were defined as follows:
The affected environment for socioeconomics is depicted in Figure 2.2 (information on the method used to define the affected area can be found in Section 3.1.1 and Appendix A). The results of the regional economic analysis suggest that the different commitment-level alternatives could have a slight impact on certain socioeconomic variables, in each of the nine subregions and in the two high-reliance counties included in the analysis. However, the range of predicted impacts on regional economic variables across the various commitment-level alternatives is extremely small. As indicated in Table 2.2, the estimated impacts on each of these variables are slight for any of the alternatives considered. Impacts on agricultural production, as measured by changes in net income of the agricultural sector in each of the affected states, and on conservation and renewable energy programs, measured in terms of impacts on consumption efficiency and load management, would also be slight.
| Commitment-Level Alternative | Financial Viability | Retail Rates | Regional Impacts/ Agricultural Production |
Air Resources | Water, Ecological, Cultural, Recreation, Land Use, and Visual Resources |
| No action (1978 Marketing Criteria) | No impact under supply option A; slight adverse impact under supply option B; moderate adverse impact under supply option C. | No impact under supply option A; slight adverse impact under supply option B; moderate adverse impact under supply option C. | No impacts in any of the nine subregions or in the two high- reliance counties; no impacts on agri cultural production. | No impact on air quality under supply option A; slight benefit under supply options B and C from decreases in SO2 and TSP emissions. No impact on noise. | Impacts dependent on hydropower operations (see Tables 2.6, 2.7, and 2.8). |
| Commitment-level alternative 1 (preferred alternative) | No impact under any supply option. | Slight adverse impact under all supply options. | No impacts in any of the nine subregions; slight impacts in the two high-reliance counties; slight adverse impact on agricultural production. | Similar to above. | Same as above. |
| Commitment-level alternative 2 | Slight adverse impact under supply options A and B; moderate adverse impact under supply option C. | Slight adverse impact under supply options A and B; moderate adverse impact under supply option C. | Same as above. | Slight benefit to air quality under all supply options from decreases in SO2 and TSP emissions. No impact on noise. | Same as above. |
| Commitment-level alternative 3 | Same as above. | Slight adverse impact under supply options A and B; moderate adverse impact under supply option C. | Same as above. | Similar to above. | Same as above. |
| Commitment-level alternative 4 | Moderate adverse impact under all supply options. | Moderate adverse impact under all supply options. | Same as above. | Similar to above. | Same as above. |
| Commitment-level alternative 5 | Same as above. | Same as above. | Same as above. | Slight adverse impact to air quality under supply option A from increases in SO2 and TSP emissions; slight benefit under supply options B and C from decreases in these emissions. No impact on noise. | Same as above. |
| Commitment-level alternative 6 | Slight adverse impact under supply options A and B; moderate adverse impact under supply option C. | Slight adverse impact under supply options A and B; moderate adverse impact under supply option C. | Same as above. | Similar to above. | Same as above. |
a The terms slight, moderate, and large are used to convey the importance of the impact. These relative terms were determined after the analysis of the impacts was completed and are based on professional judgment. For further descriptions of impacts, see Section 4.1.
The alternatives were also analyzed with respect to possible impacts on the financialcondition and retail rates of each of the utilities that receives an allocation of firm capacity and energy from Western's SLCA/IP (Table 2.2). In this case, it was determined that certain utilities could experience adverse impacts as a result of a change in Western's commitment levels. Under each of the commitment-level alternatives, the number of utilities with a coverage ratio (which measures the ratio of cash flow to interest expense or debt) of less than 2.0 would remain unchanged, but the number of utilities with a ratio of less than 1.1 could increase.7 With respect to retail rates, the different commitment-level alternatives would result in slight to moderate impacts. Impacts would be largest under commitment-level alternative 4.
Under the worst case, the commitment-level alternatives would result in only slight adverse impacts to regional or local air quality or noise levels. Impacts to other resources, including water, ecological, cultural, recreation, land use, and visual resources, would be dependent on hydropower operations (Section 2.2.4).
Commitment-level alternative 1 — the Post-1989 commitment level — was developed and chosen as Western's preferred alternative during an extended public process involving SLCA/IP customers and other interested parties. This alternative was also identified as the environmentally preferred alternative based on the results of the analyses in this EIS. The results of the impact assessments presented in Chapter 4 and summarized in Sections 2.1.3 and 2.2.4 indicate that most impacts to natural and cultural resources would result from hydropower operations rather than from commitments levels. This is because commitment levels are only weakly linked to hydropower operations (see Section 2.2.1). Furthermore, under this alternative, socioeconomic impacts, including financial viability, retail rates, and regional and agricultural economies, would be minimized.
To meet the resource requirements for each commitment-level alternative, Western would use either the hydropower generated at each SLCA/IP facility or a combination of hydrogeneration and capacity and energy purchases and exchanges from outside sources. The statement of scope for this EIS (Western 1991) indicated that Western ". . . would analyze the effects of alternatives on the operation of the applicable hydro facilities."
A study was recently completed examining the influence of Western's power marketing program on the operation of these facilities. That study indicated that hydropower operations are weakly linked to long-term firm commitments for capacity and energy (Veselka et al. 1995b). However, in this EIS, Western makes no presumption regarding what effects the commitment-level alternatives have on the operation of the SLCA/IP hydropower facilities. Instead, in order to assess the complete range of potential impacts associated with hydropower generation, the full range of possible operations within the scope of Western's control is analyzed at each SLCA/IP facility.
Under all conditions, Western obtains a finite amount of energy from the operation of SLCA/IP facilities. The amounts of energy produced by these facilities basically depend on the amounts of water released from the dams, and the bounds of these releases are not set by Western. Monthly water volumes released through the CRSP facilities are established by Reclamation in consultation with the Colorado River Basin states according to legal require ments governing downstream water deliveries and the hydrological conditions of the river basin.8 Within these monthly constraints and limitations on the daily operations of the facilities, water releases can be made in different ways. Water can be released as fast as possible for a short period of time or slowly over a long period of time. Because the value of energy is greatest when it is needed most, more water is released during the day to meet peak loads, and less water is released at night.
Western, in conjunction with Reclamation, has studied the operations of each of the SLCA/IP dams that generate hydropower to determine the amount of influence that Western exercises on each facility for hydroelectric generation. Certain facilities are operated for specific project purposes (usually irrigation) with no consideration of hydropower generation, other than as a by-product of the release of irrigation water. Neither Western nor its marketing programs influence the operation of these particular facilities: Provo River, Collbran, Fontenelle, Rio Grande, and the power plant at Crystal Dam (Figure 1.1). These facilities, which are operated for water services (such as irrigation) or other nonpower purposes, are not included in the hydropower operational scenarios described in this section. However, the capacity and energy available from these facilities were included in the commitment-level alternatives because they contribute to the total amount of capacity and energy available to fulfill Western's power marketing responsibilities.
For the remaining facilities of the CRSP (Glen Canyon, Flaming Gorge, Morrow Point, and Blue Mesa dams), Western has direct influence over their second-by-second, hourly, and daily operations within the minimum and maximum release rates, up- and down-ramp rates, and monthly release volumes set by Reclamation. Hydropower operational scenarios were developed for these facilities and are analyzed in this EIS to determine the full range of impacts associated with commitment-level alternatives. These hydropower operational scenarios, however, are not alternatives themselves.
Simply stated, hydrogeneration plus purchases and exchanges must equal firm sales plus nonfirm sales. Western makes purchases and exchanges both in response to shortfalls in hydrogeneration and other operational constraints, such as transmission limitations, and in response to variations in the value of energy. This procedure is consistent with standard operating practices of electrical utilities.
Western's purchases and exchanges of capacity and energy vary with market conditions and changes in Reclamation's water release schedules and operational parameters of the dams. When Reclamation's monthly water releases are not sufficient to provide the capacity and energy needed for Western to meet its firm sales commitments, Western must purchase or exchange capacity and energy sufficient to meet its contractual obligations.
Purchases made by Western are usually short-term and may be made from any utility offering capacity and energy for sale. With Western's extensive transmission network across the Western states, purchases can be made from any number of generators. As market conditions change and regional weather patterns create unusual load demands, Western can compensate for reductions in the availability or value of the hydroelectric resource by buying or selling power around the system to capture the benefit of purchasing from others with surplus generation and selling to customers with deficit generation. Because these purchases are made on the open market, it is impossible to project from day-to-day or month-to-month which generation units would be dispatched to meet Western's firm loads and nonfirm sales commitments.
In addition to purchases, Western has entered into an agreement with the Salt River Project (SRP), referred to as the SRP Exchange Agreement, to (1) make efficient use of Western's existing transmission system, (2) provide a mutual benefit through generation exchange, and (3) match regional loads with proximate resources and thus conserve energy by reducing line losses. Most (72%) of Western's SLCA/IP generating resources are located at Glen Canyon Dam in northern Arizona, while many of Western's loads are located in Utah, Colorado, and New Mexico. The Glen Canyon-Kayenta-Shiprock transmission line, used to link Glen Canyon with these major areas of load, has a capacity of only 400 MW. During times of peak loads, limits on the Glen Canyon-Kayenta-Shiprock line may restrict operating levels at many or all SLCA/IP hydroelectric dams. Western and SRP have an "exchange" arrangement in which generating capacity owned by SRP in Craig and Hayden, Colorado, and the Four Corners unit in New Mexico is exchanged for surplus generating capacity at Glen Canyon Dam under certain conditions. The power exchanges with SRP have enabled Western to service its loads northeast of Glen Canyon at times of peak loads on the Glen Canyon-Kayenta-Shiprock line.
Purchases and exchanges allow Western to diversify its generation risk, capitalize on short-term market differentials in supply and demand, and maximize the value of SLCA/IP resources. The overall effect of these purchases and exchanges is to provide Western flexibility over commitment levels given specific hydropower operational scenarios. This flexibility is illustrated by the effects of recent Reclamation interim flow restrictions at Glen Canyon Dam. This facility represents nearly 75% of SLCA/IP generation. Although operations have been severely restricted, Western has met its firm commitments with little interruption in supply by making purchases and exchanges.
Because of this flexibility, Western can meet load in excess of hydrogeneration. However, some commitment levels, when combined with certain hydropower operational scenarios, may not be desirable. For example, low commitment levels with hydropower operation scenarios that have high fluctuations may not be desirable because such a combination would have an economic cost without providing any environmental benefit. Western decisions regarding both commitment levels and hydropower operational scenarios will be based on all of the purposes stated for the EIS, in light of the environmental impacts. Ultimately, Western must determine both a commitment level and a means of supplying the commitment level, including operational scenarios at the hydropower facilities, within constraints and release volumes set by Reclamation.
Only Glen Canyon Dam, Flaming Gorge Dam, and the Aspinall Unit require the development of operational scenarios for analysis in this EIS. For all facilities where operations are dictated by irrigation demands, municipal and industrial uses, flood control, or other nonpower purposes, operations are not described, and site-specific environmental analyses are not included because, although Western markets this power, Western does not affect dam operations or hydropower generation at those facilities.
For this EIS, Western developed hydropower operational scenarios for Flaming Gorge Dam and the Aspinall Unit but used the alternatives presented in the Glen Canyon Dam EIS as the operational scenarios for that facility. Since Reclamation, not Western, establishes operational limits (e.g., minimum and maximum releases, ramp rates) and monthly water release volumes for each facility, the EIS does not evaluate changes in these operational characteristics, and all operational scenarios for Flaming Gorge Dam and the Aspinall Unit are within power plant capacity. Within the constraints set by Reclamation, Western has the ability to determine hydropower generation by controlling the timing and magnitude of releases and, thus, the degree of flow fluctuation downstream. It is this degree of fluctuation in releases that is the focus of the evaluation of hydropower operational scenarios presented in the EIS. Specifically excluded from the analysis is an examination of changes in operations that are outside of Western's control, such as changes in monthly release volumes and modification of the dam structure. Also excluded is an evaluation of nonhydropower dam effects, such as the trapping of sediment and inundation of upstream environments. Thus, the focus of this EIS (power marketing) is not comparable to that of the Glen Canyon Dam EIS (dam operations). Although outside of the scope of this Power Marketing EIS, Western supports the evaluation of a wider range of releases (e.g., above power plant capacity releases such as habitat maintenance flows) and other aspects of dam operations in any future NEPA documents prepared by Reclamation on the operations of Flaming Gorge Dam or the Aspinall Unit.
Nine modes of operation, which represent unique hydropower operational scenarios for Western's power marketing programs, have been identified in the Glen Canyon EIS (Reclamation 1995). These scenarios, which were evaluated as alternatives in the Glen Canyon Dam EIS, are described in Table 2.3; the modified low fluctuating flow alternative was identified by Reclamation as their preferred alternative in the EIS. When the Glen Canyon Dam EIS Record of Decision is issued, Western will have to maintain hydropower operations within the constraints specified by the alternative selected. These constraints will include such parameters as minimum flows, maximum flows, ramp rates, and allowable daily changes. The range of operations span maximum power plant capacity flows; (1,000 cubic feet per second [cfs] minimum flow to 33,200 cfs maximum flow); to year-round steady flows based on yearly prorated volumes with an allowable daily change of 2,000 cfs every 24 hours. Included within this range is continuation of historical9 operations. A detailed explanation of the hydrology studies and release patterns derived from the EIS alternatives is provided in the Glen Canyon Dam EIS (Reclamation 1995). The release patterns and environmental impacts associated with those releases are based on results of the Glen Canyon Environmental Studies, the supporting literature, and related documentation found in the public record.
The Glen Canyon Dam EIS (Reclamation 1995) included elements common to all of the restricted fluctuation and steady flow operational scenarios. These actions are intended to reduce the impacts of dam operations and would be implemented by Reclamation as part of establishing future operations at that facility. Common elements included: (1) adaptive management of the facility to allow flexibility in changing future operations based on future monitoring and research findings and changes in resource conditions; (2) monitoring and protecting cultural resources within the Colorado River corridor of Glen and Grand canyons; (3) implementation of actions to reduce the frequency of unplanned floods below Glen Canyon Dam; (4) implementation of beach/habitat building flows to rebuild high elevation sand bars, deposit nutrients, restore backwater channels, and provide some of the dynamics of a natural system; (5) establishment of a new population of humpback chub within Grand Canyon; and (6) further study of a selective withdrawal structure to provide warmer release waters.
|
|
|
Restricted Fluctuating Flows | Steady Flows | ||||||
| Continuation of Historical | Maximum Power Plant | High | Moderate | Modified Lowa | Interim Low | Existing Monthly Volume |
Seasonally Adjusted | Year- Round | |
| Minimum releasesb (cfs) | 1,000 Labor Day-Easter
3,000 Easter- Labor Dayc |
1,000 Labor Day-Easter
3,000 Easter- Labor Dayc |
3,000, 5,000, 8,000, depending on monthly volume, firm load, and market conditions | 5,000 | 8,000 between 7 a.m. and 7 p.m. 5,000 at night | 8,000 between 7 a.m. and 7 p.m. 5,000 at night | 8,000 | 8,000 Oct-Novd
8,500 Dec 11,000 Jan-Mar 12,500 Apr 18,000 May-Jun 12,500 Jul 9,000 Aug-Sep |
Yearly volume proratede |
| Maximum releasesf (cfs) | 31,500 | 33,200 | 31,500 | 31,500g | 25,000g | 20,000 | Monthly volumes prorated | 18,000g | Yearly volume proratede |
| Allowable daily change in flow (cfs/24 hours) | 30,500 Labor Day-Easter 28,500 Easter- Labor Day | 32,200 Labor Day-Easter 30,200 Easter- Labor Day | 15,000 to 22,000 | ±45% of mean flow for the month not to exceed ±6,000 | 5,000,h 6,000, or 8,000 | 5,000,h 6,000, or 8,000 | ±1,000i | ±1,000i | ±1,000i |
| Allowable scheduled ramping (cfs/h) | Unrestricted | Unrestricted | Unrestricted up 5,000 or 4,000 down | 4,000 up 2,500 down | 4,000 up 1,500 down | 2,500 up 1,500 down | 2,000 cfs/d between months | 2,000 cfs/d between months | 2,000 cfs/d between months |
| Elements common to restricted fluctuating and steady flow alternatives | None | None | Adaptive management including long-term monitoring and research, monitoring and protection of cultural resources, flood frequency reduction measures, beach/habitat-building flows, new population of humpback chub, further study of selective withdrawal, emergency exception criteria | ||||||
a Identified by Reclamation as their preferred
alternative (Reclamation 1995).
b In high volume release months,
the allowable daily change would require higher minimum flows.
c
Releases each weekday during recreation season (Easter to Labor Day) would
average not less than 8,000 cfs for the period from 8 a.m. to midnight.
d
Based on an 8.23 million acre-feet year; in higher release years, additional
water would be added equally to each month, subject to an 18,000 cfs maximum.
e
For an 8.23-million acre-feet year, steady flow would be about 11,400 cfs.
f
Maximums represent normal or routine limits and may necessarily be exceeded
during high-water years.
g May be exceeded during
habitat-maintenance flows.
h Daily fluctuation limit of 5,000
cfs for monthly release volumes less than 600,000 acre-feet; 6,000 cfs for
monthly release volumes of 600,000 to 800,000 acre-feet and 8,000-cfs for
monthly volumes over 800,000 acre-feet.
i Adjustments would
allow for small power system load changes.
Source: Adapted from Reclamation (1995).
Four operational scenarios for Flaming Gorge Dam were developed for this EIS (Table 2.4). All scenarios would feature releases within power plant capacity. Any releases above power plant capacity are outside of the scope of Western's control of operations. As described below, three of the scenarios comply with the Biological Opinion issued by the USFWS (1992b). Compliance with the opinion is described as follows:
Release patterns were developed for wet, moderate, and dry years (1983, 1987, and 1989, respectively) (see Section 3.3). Conditions in 1983 and 1989 represent extreme, worst- case conditions rather than typical wet and dry years. Release patterns for the four hydropower operational scenarios are presented in Appendix C. The principal difference in the hydropower operational scenarios is the hourly fluctuation characteristics of the release rate, as summarized below.
Scenario 1 — Year-Round High Fluctuating Flows: The ramping rates, maximum fluctuations, and maximum and minimum releases used to derive the representative release patterns are detailed in Appendix C. The minimum release is 800 cfs; the maximum release was assumed to be 4,700 cfs 10 with no limit on maximum daily fluctuations. Ramp-rate restrictions are 3,900 cfs/h (minimum flow to maximum generator capacity). This operational scenario would not comply with the Biological Opinion. It is representative of maximum power plant operations using monthly release volumes historically set by Reclamation and is considered here for comparative purposes. Consideration of this operational scenario enabled a determination of the environmental consequences of the seasonal and daily adjustment of releases required by the opinion.
| Parameter | Year-Round High Fluctuating Flows |
Seasonally Adjusted Flowsb | ||
| High
Fluctuating |
Moderate
Fluctuating |
Steady | ||
| Minimum releases (cfs) | 800 | 800 Oct-Jan
2,380 Feb-Mar 800 Apr-May 4,700 Jun 1-21 800 Jun 22-Jul 9 890 Jul 10-31 990 Aug 1,070 Sep |
800 Oct 2,220 Nov-Jan 2,380 Feb-Mar 2,440 Apr 2,740 May 4,700 Jun 1-21 2,770 Jun 22-30 1,860 Jul 1-Jul 9 976 Jul 10-31 1,080 Aug 1,160 Sep |
800 Oct 2,380 Nov-Mar 2,600 Apr 3,390 May 4,700 Jun 1-21 3,740 Jun 22-30 2,020 Jul 1-9 1,060 Jul 10-31 1,160 Aug 1,240 Sep |
| Maximum releases (cfs) | 4,700 | 800 Oct 4,700 Nov-Jan 2,380 Feb-Mar 4,700 Apr-Jul 9 2,900 Jul 10-31 3,000 Aug 3,100 Sep |
800 Oct 4,170 Nov-Jan 2,380 Feb-Mar 4,390 Apr 4,700 May-Jun 3,810 Jul 1-9 1,980 Jul 10-31 2,080 Aug 2,160 Sep |
Same as minimum releases |
| Allowable daily change in flow (cfs/24 hours) | 3,900 | 0 Oct
3,900 Nov-Jan 0 Feb-Mar 3,900 Apr-May 0 Jun 1-21 3,900 Jun 22-Jul 9 2,010 Jul 10-Aug 2,030 Sep |
0 Oct
1,950 Nov-Jan 0 Feb-Mar 1,950 Apr-May 0 Jun 1-21 1,950 Jun 22-Jul 9 1,000 Jul 10-Sep |
0 |
| Allowable schedule dramping (cfs/h) | 3,900 | 3,900 | 1,950 | 0 |
a For a moderate hydrological year.
b
All seasonally adjusted hydropower operational scenarios comply with the
Biological Opinion for operation of Flaming Gorge Dam (USFWS 1992b).
Scenario 2 — Seasonally Adjusted High Fluctuating Flows: Hourly releases would reach the maximum fluctuation feasible as limited by the Biological Opinion, water available for release, minimum release requirement, and power plant capacity. Volumes would be adjusted seasonally to meet requirements of the Biological Opinion.
Scenario 3 — Seasonally Adjusted Moderate Fluctuating Flows: Hourly releases would have fluctuations limited to 50% of the flow change identified under Scenario 2. Volumes would be adjusted seasonally to meet requirements of the Biological Opinion.
Scenario 4 — Seasonally Adjusted Steady Flows: Hourly releases would be constant during the day. Volumes would be adjusted seasonally to meet requirements of the Biological Opinion.
There is some uncertainty with regard to potential future operations at Flaming Gorge Dam and the operational scenarios were defined to capture the full range of likely future operations. Operations at Flaming Gorge Dam are currently being studied to determine the effects of different flow regimes on downstream resources. These studies are being funded, in part, by Western and are conceptually similar to the adaptive management proposed by Reclamation for Glen Canyon Dam. Operations could be modified in the future to reduce impacts on the basis of these studies or to restore flexibility at the Flaming Gorge hydropower facility where such changes would not significantly affect the environment. In addition, Western is a participant in the Recovery Implementation Program for Endangered Fishes in the Upper Colorado River Basin. The goal of this program is to fully recover endangered fish species in the basin. Western will continue to participate in this program and would modify operations accordingly to protect these species.
The operations of the Aspinall Unit dams are being evaluated by Reclamation. Any NEPA documentation that is prepared will not be available for reference in this Electric Power Marketing EIS; however, Western has developed two operational scenarios for the Aspinall Unit (Table 2.5).
Scenario 1 — Seasonally Adjusted High Fluctuating Flows: This scenario would permit seasonally adjusted high fluctuating flows with daily fluctuations at Blue Mesa and Morrow Point dams, but only steady flows out of Crystal Dam.
Scenario 2 — Seasonally Adjusted Steady Flows: This scenario would provide for a steady water release through Blue Mesa, Morrow Point, and Crystal dams. The steady pattern would change monthly, depending on the monthly volume set by Reclamation.
| Parameter | Seasonally Adjusted High Fluctuating Flows | Seasonally Adjusted Steady Flows | ||||
| Blue Mesa | Morrow Point | Crystal | Blue Mesa | Morrow Point | Crystal | |
| Minimum release (cfs) | 1,750 Jun
0 Others |
0 Oct-Mar
557 Apr 1,830 May 2,440 Jun 1,070 Jul 0 Aug-Sep |
1,920 Oct
1,430 Nov 1,280 Dec 680 Jan-Mar 2,250 Apr 3,580 May 3,830 Jun 2,640 Jul 1,920 Aug-Sep |
1,570 Oct
1,200 Nov 1,050 Dec 500 Jan-Mar 1,600 Apr 2,370 May 3,050 Jun 2,350 Jul 1,750 Aug-Sep |
1,700 Oct
1,280 Nov 1,100 Dec 570 Jan-Mar 1,970 Apr 2,890 May 3,320 Jun 2,480 Jul 1,770 Aug 1,820 Sep |
1,920 Oct
1,430 Nov 1,280 Dec 680 Jan-Mar 2,250 Apr 3,580 May 3,830 Jun 2,640 Jul 1,920 Aug-Sep |
| Maximum release (cfs) | 3,700 | 5,300 Oct-Mar
2,680 Apr 3,420 May 3,770 Jun 3,190 Jul 5,300 Aug-Sep |
Same as minimum releases | Same as minimum releases | Same as minimum releases | Same as minimum releases |
| Allowable daily change in flow (cfs/24 hours) | 3,700 Oct-May
1,950 Jun 3,700 Jul-Sep |
5,300 Oct-Mar
2,120 Apr 1,590 May 1,330 Jun 2,120 Jul 5,300 Aug-Sep |
0 | 0 | 0 | 0 |
| Allowable scheduled ramping (cfs/h) | 3,700 | 5,300 | 0 | 0 | 0 | 0 |
a For a moderate hydrological year.
These scenarios are likely to bound any future operations established by Reclamation. It is possible, however, that the results of studies could result in some modification of releases from the Aspinall Unit. Only a seasonal shift in releases from the Unit different from the shift considered here would be outside the bounds of the scenarios considered here, since a full range of operational releases was considered and Western assumed no control of releases from Crystal Dam which regulates flows from the entire Aspinall Unit.
This section summarizes impacts on natural and cultural resources from hydropower operational scenarios for Glen Canyon Dam, Flaming Gorge Dam, and the Aspinall Unit. The location of the affected environments of these operational scenarios are depicted in Figure 2.3. These impacts are discussed in detail in Section 4.2. The natural and cultural resource impacts associated with Western's power marketing programs are direct results of hydroelectric operations rather than of the commitments of capacity and energy (i.e., commitment-level alternatives) specified in Western's contracts. These hydroelectric operations can be established independently of the level of commitment and are, thus, treated separately from the commitment-level alternatives in this EIS.
The operational scenarios examined for Glen Canyon and Flaming Gorge dams included scenarios that are similar to historical operations (e.g., continuation of historical operations and year-round high fluctuations, respectively). The current conditions of most resources downstream of the facilities have resulted, at least in part, from such operations, and, therefore, these operational scenarios would have little additional impact to most resources. Other operational scenarios examined would result in reduced flow fluctuations below the dams, which could benefit many downstream resources. None of the operational scenarios considered would materially affect noise, land use, or visual resources. Therefore, these resources are not discussed further in this section. For reasons discussed in Chapter 4, impacts to air resources are considered as part of the commitment-level alternative analysis.
Table 2.6 summarizes impacts to water resources, ecological resources, cultural resources, and recreation in and along the Colorado River downstream of Glen Canyon Dam.11 Since hydropower operations have little effect on the surface level of Lake Powell upstream of the dam (because of the large reservoir capacity), resources in the reservoir are not considered.
| Operational Scenario | Water Resourcesb | Ecological Resourcesc | Cultural Resourcesd | Recreatione |
| Continuation of historical operations | No change from current conditions. | Slight adverse impact to humpback chub; adverse impact to Kanab ambersnail; no change from current conditions for other resources. | No change from current conditions; some sites continue to be affected by fluctuation-induced erosion. | No change from current conditions. |
| Maximum power plant capacity | Slight adverse impact from increase in flow fluctuations. | Slight adverse impact to humpback chub and southwestern willow flycatcher; adverse impact to Kanab ambersnail; no impact to other resources. | Same as above. | Slight adverse impact to angling. |
| Restricted high fluctuating flows | Slight benefit; slight increase in probability of net gain in riverbed sand. | Slight adverse impact to humpback chub; adverse impact to Kanab ambersnail; slight benefit to aquatic and terrestrial resources. | Same as above. | Slight benefit to angling and white-water boating. |
| Moderate fluctuating flows | Moderate benefit; moderate increase in probability of net gain in riverbed sand. | Slight adverse impact to humpback chub; adverse impact to Kanab ambersnail; slight benefit to bald eagle, peregrine falcon, and southwestern willow flycatcher; slight benefit to aquatic resources; no impact to terrestrial resources. | Benefit because of reduced erosion rates. | Slight benefit to angling; moderate benefit to white-water boating. |
| Modified low fluctuating flows | Same as above. | Slight benefit to humpback chub, bald eagle, peregrine falcon, and southwestern willow flycatcher; adverse impact to Kanab ambersnail; slight to moderate benefit to aquatic resources; no impact to terrestrial resources. | Same as above. | Moderate to large benefit to white-water boating; moderate benefit to angling. |
| Interim low fluctuating flows | Same as above. |
Same as above except moderate benefit to terrestrial resources. |
Same as above. | Same as above. |
| Existing monthly volume steady flows | Same as above. | Slight benefit to humpback chub, bald eagle, peregrine falcon, and southwestern willow flycatcher; adverse impact to Kanab ambersnail; moderate benefit to aquatic resources; large benefit to terrestrial resources. | Same as above. | Large benefit to angling and white-water boating. |
| Seasonally adjusted steady flows | Same as above. | Slight to moderate benefit to humpback chub; no impact to terrestrial resources; same as above for other resources. | Same as above. | Large benefit to white- water boating; moderate benefit to angling. |
| Year-round steady flows | Same as above. | Slight benefit to humpback chub, bald eagle, and peregrine falcon; moderate benefit to southwestern willow flycatcher; adverse impact to Kanab ambersnail; moderate benefit to aquatic resources; large benefit to terrestrial resources. | Same as above. | Large benefit to angling and white-water boating. |
a The impacts presented are relative to a
baseline of existing conditions that have formed since placement and operation
of the dam. No impacts to air resources, land use, or visual resources were
identified. The terms slight, moderate, and large benefits and
adverse impacts are used to convey the importance of the impact. These
relative terms were not included in the Glen Canyon Dam EIS but have been added
on the basis of a review of the findings presented in that EIS to provide
consistency in treatment among facilities. For further descriptions of impacts,
see Section 4.2.
b Effects of hydropower operational scenarios
on water resources were considered benefits if they resulted in a more natural
flow regime or sediment balance.
c
Expected benefits of reduced flow fluctuations to native and endangered
fishes may not occur if competing or predaceous non-native fishes increase in
response to more stable flows.
d Archaeological, historical, and
Native American resources.
e Angling and white-water boating.
Source: Adapted from Reclamation (1995).
The continuation of historical operations and maximum power plant capacity operational scenarios would have little additional impact on natural resources. These scenarios are similar to the operations that have occurred since the dam was completed in 1963, and existing water resources, ecological resources, and recreational activities have developed under these historical operations.
Because of their reduced fluctuations and maximum flows, all other operational scenarios would be beneficial for most resources relative to current conditions. Restricted high fluctuations would result in slight benefits to water resources, most ecological resources, and recreation; however, adverse impacts are expected to cultural resources. Moderate and low fluctuation operational scenarios would produce moderate benefits for water resources, cultural resources, and white-water boating. Steady flow scenarios would produce moderate to large benefits for these resources, as well as for aquatic ecology and angling. The seasonally adjusted steady flow scenario could benefit the humpback chub, but any benefit might require the proposed habitat-maintenance flows to flush accumulated sediments and encroaching vegetation from backwaters. All operational scenarios could have adverse impacts on the Kanab ambersnail.
Table 2.7 summarizes impacts to water resources, ecological resources, cultural resources, and recreation in and along the Green River downstream of Flaming Gorge Dam. Because hydropower operations have little effect on the surface level of Flaming Gorge Reservoir (because of the large reservoir capacity), resources in the reservoir are not considered.
The year-round high fluctuating flow operational scenario features slightly higher daily maximum flows and fluctuations than historical operations. This scenario could result in adverse impacts to native and endangered fish, trout, terrestrial resources, and cultural resources.
The seasonally adjusted operational scenarios feature shifts in monthly volumes to meet requirements of the USFWS Biological Opinion (USFWS 1992b). All of these scenarios exhibit a high sustained flow in May or June, reduced fluctuations and lower flows in summer and autumn, and steady flows when an ice cover is present on the river (February and March). These flow patterns are intended to protect endangered fish in the system and would benefit other resources as well. Some adverse impacts could result from seasonal adjustment, however. The spring peak flows would adversely affect anglers. In addition, the bald eagle and waterfowl could be adversely affected by steady flows in February and March. With steady flows, less open, ice-free water would be available for these species. Seasonal adjustment of flows could also result in reduced soil moisture in riparian areas during the summer and, in turn, produce slight to moderate adverse impacts to existing populations of the Ute ladies'-tresses. The more natural flow patterns of these scenarios, however, could result in the establishment of new populations of this species.
| Operational Scenario | Water Resourcesb | Ecological Resourcesc | Cultural Resourcesd | Recreatione |
| Year-round high fluctuating flows | Slight adverse impact; increase in erosion rate. | Slight to moderate adverse impacts to aquatic resources; slight adverse impacts to terrestrial resources. | Slight adverse impact because of increase in erosion rate. | Slight adverse impact to angling; conditions for white- water boating unchanged; no impact on day floating. |
| Seasonally adjusted high fluctuating flows | Same as above. | Slight to moderate benefits to native fish and endangered fish; slight to moderate adverse impacts to trout; slight adverse impact to existing Ute ladies'- tresses but slight potential for establishment of new individuals; slight adverse impact to terrestrial resources; slight adverse impact to bald eagle. | Same as above. | Slight adverse impact to angling; moderate benefit to white-water boating; no impact on day floating. |
| Seasonally adjusted moderate fluctuating flows | Slight benefit; decrease in erosion rate. | Slight to moderate benefit to native fish and endangered fish; slight benefit to trout; slight adverse impact to bald eagle; slight to moderate adverse impact to existing Ute ladies'-tresses but greater potential for establishment of new individuals; slight adverse impact to terrestrial resources. | Slight benefit because of reduced erosion rate. | Slight adverse impact to angling; moderate benefit to white-water boating; no impact on day floating. |
| Seasonally adjusted steady flows | Same as above. | Moderate to large benefit to native fish and endangered fish; moderate benefit to trout; slight benefit to terrestrial resources; slight adverse impact to bald eagle; moderate adverse impact to existing Ute ladies'-tresses but greatest potential of establishment of new individuals; slight benefit to peregrine falcon. | Same as above. | Slight benefit to angling; moderate benefit to white- water boating; no impact on day floating. |
a The impacts presented are relative to a
baseline of existing conditions that have formed since placement and operation
of the dam. No impacts to air resources, land use, or visual resources were
identified. The terms slight, moderate, and large are used to
convey the importance of the impact. These relative terms were determined after
the analysis of the impacts was completed and are based on professional
judgment. For further descriptions of impacts, see Section 4.2.
b
Effects of hydropower operational scenarios on water resources were considered
benefits if they resulted in a more natural flow regime or sediment balance.
c
Expected benefits of reduced flow fluctuations to native and endangered fishes
may not occur if competing or predaceous non-native fishes increase in response
to more stable flows.
d Archaeological, historical, and Native
American resources.
e Angling and white-water boating.
Seasonally adjusted high fluctuations would have slight to moderate benefits for native and endangered fish (e.g., humpback chub), but high fluctuations from November through January and in April and May could adversely affect trout. This scenario would produce large benefits for angling in mid-summer through autumn and moderate benefits for white-water boating during the spring peak. Slight adverse impacts to terrestrial ecology could occur because of the inundation of some riparian vegetation. Erosion rates would be similar to the year-round high fluctuation scenario, and thus cultural resources could be adversely affected.
Seasonally adjusted moderate fluctuations or steady flows could produce slight to large benefits for native and endangered fish, cultural resources, angling, and white-water boating. Only the steady flow scenario would benefit terrestrial resources, however, by allowing a moderate increase in riparian vegetation.
Table 2.8 summarizes impacts to water resources, ecological resources, cultural resources, and recreation associated with the Aspinall Unit. Only slight impacts to resources in and around the reservoirs would result from the two operational scenarios under consideration. No hydropower-induced impacts would occur in the Gunnison River below the unit because Crystal Dam reregulates flows from the unit. Thus, flows in the Gunnison River would not be affected by the hydropower operational scenarios, and little difference exists in the impacts of the scenarios for this facility.
| Operational Scenario | Water Resourcesb | Ecological Resources | Cultural Resourcesc | Recreationd |
| Seasonally adjusted high fluctuating flows | ||||
| Blue Mesa Reservoir | Slight benefit; daily fluctuations same as historical but monthly release volumes change. | No impact to any resources. | No impact. | No impact. |
| Morrow Point Reservoir | Same as above. | Same as above. | Same as above. | Slight adverse impact to boaters |
| Crystal Dam Reservoir | Same as above. | No impacts to aquatic resources; slight benefit to terrestrial resources. | Same as above. | Same as above. |
| Seasonally adjusted steady flow | ||||
| Blue Mesa Reservoir | Slight benefit; daily fluctuations eliminated and monthly release volumes change. | No impact to aquatic or terrestrial resources; slight adverse impact to bald eagle. | No impact. | No impact. |
| Morrow Point Reservoir | Moderate benefit; daily fluctuations eliminated and monthly release volumes change. | Same as above. | Same as above. | Same as above. |
| Crystal Reservoir | Large benefit; daily fluctuations eliminated and monthly release volumes change. | No impact to aquatic resources; slight benefit to terrestrial resources; slight adverse impact to bald eagle. | Same as above. | Same as above. |
a The impacts presented are relative to a baseline of existing
conditions that have formed since placement and operations of the dams. No
impacts to air resources, land use, or visual resources were identified. The
terms slight, moderate, and large are used to convey the
importance of the impact. These relative terms were determined after the
analysis of the impacts was completed and are based on professional judgment.
For further descriptions of impacts, see Section 4.2.
b Effects
of hydropower operational scenarios on water resources were considered benefits
if they resulted in a more natural flow regime or sediment balance.
c
Archaeological, historical, and Native American resources.
d
Angling and boating.
1One megawatt equals 1,000,000 watts.
2One kilowatt equals 1,000 watts.
3One megawatt-hour equals 1,000,000 watt-hours. A generator operating at a capacity of one megawatt for one hour would produce one megawatt-hour of energy. The same generator operating at a capacity of one megawatt for 10 hours would produce 10 megawatt-hours of energy.
4One gigawatt-hour equals 1,000 megawatt-hours.
5Minimum schedule requirements are associated with alternative combinations of capacity and energy to provide (1) sufficient load off-peak to match minimum release levels at all SLCA/IP facilities, (2) the ability for Western to purchase sufficient energy off-peak to satisfy energy commitments in an adverse water year, and (3) some remaining component of capacity and energy to be scheduled for the customer during on-peak periods. Unique minimum schedule requirements for each commitment-level alternative were determined through consistent application of this approach.
6These analyses assume that Western adjusts its firm power ratefor each commitment-level alternative so that required payments to the U.S. Treasury from theFederal projects are unaffected by choice of alternative.
7It is an industry-wide standard that the coverage ratio for utilities should be greater than 2.0.
8These legal requirements (sometimes collectively referred to as "the Law of the River") are stipulated in the following acts and compacts: the Colorado River Storage Project Act, the Colorado River Basin Project Act of 1968 (43 USC §§ 1501 et seq.), the Colorado River Compact (Dec. 21, 1928, Ch. 42, 45 Stat. 1057), Upper Colorado River Basin Compact Ch. 6, 1949, Ch. 48, 63 Stat. 31), the Boulder Canyon Project Act (43 USC §§ 617 et seq.) , the Boulder Canyon Project Adjustment Act (43 USC §§ 618 et seq.), as well as certain international boundary and water treaties.
9When used to describe flows or operational scenarios, the term historical refers to the period in time from construction of the dam to that time when operations recently were modified to protect downstream natural resources.
10The maximum possible release rate for Flaming Gorge Dam with uprated conditions could be in excess of 4,950 cfs for full reservoir conditions. However, such reservoir conditions would occur for limited periods.
11The assessment presented here for Glen Canyon Dam was based on the analysis presented in a separate EIS for that facility (Reclamation 1995). Relative levels of benefitor adverse impacts were added to provide consistency of treatment among facilities.
