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9 Power Economics INTRODUCTION Power resources occupied an important and somewhat unique position in the Glen Canyon Environmental Studies (GCES). Electrical output from Glen Canyon is proportional to water flow through the dam, and the value of that output varies daily, weekly, and seasonally. As a result, power econ- omics and water flows are closely related. Traditionally, Glen Canyon Dam has operated with relatively few con- straints so as to maximize the value of its electrical output (Chapter 4~. Thus, operational changes (such as those implemented under the interim flow regime and those that were under active consideration in the environmental impact statement (EIS) for Glen Canyon Dam) alter the scheduling and reduce thevalue of power production. This loss of power resources accounts for most, if not all, of the costs of altered dam operations. As can be seen from the previous chapters, operational changes at Glen Canyon Dam can have beneficial effects on native fishes, beaches, recreation, and archeological sites. Therefore, a principal focus of the decision making process concerning operation of the dam is the balance between the value of production of electricity and other resources. This has several important implications. First, since changes to dam operations reduce the value of power, it is those who benefit from this output who will tend to be affected most adversely and thus to be opposed to such changes. Interests related to power production are typically well defined, strongly organized, and quite aggressive in advocating their point of view. By contrast, those who might benefit from modified dam operations are more diverse and must be mo 165

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166 River Resource Management in the Grand Canyon tivated by somewhat more diffuse goals, involving environmental or cultural resources. Second, the contrasting position of the different interests is accentuated by the nature of the resources. Electrical output can be measured readily. Moreover, it is a good that is bought and sold and that can be assessed a specific monetary value. Other resources are generally harder to measure, and it can be difficult or impossible to assign them monetaryvalues (Chapter 7~. Thus, in the EIS for Glen Canyon Dam and elsewhere, the costs of changes to dam operations are reported in dollars, while most of the benefits are reported in other units (e.g., number of beaches). Third, the disjunction between electrical power and other resources is further accentuated by the contrasting levels of historical analysis. Power resources have been the subject of decades of analysis. The utilities potentially affected by changes in operations at Glen Canyon Dam are commonly viewed as having sufficient data and expertise to estimate the adverse effects on their interests. Prior to the GCES, natural resources were subject to much less study. Without the requisite data and expertise, it was difficult to assess how these resources would be affected by changes in dam operations. The GCES increased the feasibility of comparisons between power production and the natural resources of Glen Canyon. The GCES has also played a major role in advancing the study of Glen Canyon Dam power economics. It became clear during Phase I of GCES that the existing analysis did not provide an adequate basis for decision making regarding altered dam operations. The quality of this analysis has sub- stantially improved as a result of the extensive power economics studies undertaken during GCES Phase 11. This process has greatly benefited from broader public participation and review external to federal agencies and utilities. FLOWS AFFECT ELECTRICAL OUTPUT AND COSTS The Colorado River Storage Project Act directs the Secretary of the Interior to operate power plants "so as to produce the greatest practicable amount of power and energy that can be sold at firm power and energy rates." In a hydra project such as Glen Canyon, water is impounded behind a dam and discharged at a lower elevation into the river downstream. The mechanical energyofthefallingwateris used toturn turbines, which generate electricity.

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Power Economics 167 Electrical output is measured in two ways. Instantaneous output is re- ferred to as power and is measured in terms of watts Go. Output over time is electrical energy and is expressed in terms of watt-hours (Wh). The quantity of electrical output is typically much larger then a waft, so units such as kW (thousand watts), MW (million watts), and GW (billion watts) are used. Similarly, typical units for energy are kWh, MWh, and GWh. The maximum amount of power that can be produced by a power plant is known as capacity. For a hydra dam, capacity is a function of the number and size of turbines. Subsequent to a rewinding and uprating of generators completed in 1987, Glen Canyon Dam capacity has been 1356 MW (at 33,200 cubic feet per second (cfs), which is the maximum flow through the turbines) (BOR, 1995~. However, the Bureau of Reclamation (BOR) agreed not to use this increased capacity pending completion of a comprehensive study of the effects of historic and current dam operations on environmental resources. Thus, Glen Canyon Dam has generally been limited to a capacity of 1,300 MW (at 31,500 cfs of flow) (PRO, 1995~. The maximum amount of energy that can be produced over time by a hydro dam is determined by the smaller of two constraints: turbine capacity and amount of water in the reservoir. If Glen Canyon Dam were to operate at full capacity continuously for 1 year, it would generate almost 12,000 GWh and discharge 24 million acre-feet (mad of water. This greatly exceeds the amount of water entering Lake Powell, even in wet years (Chapter 4~. At the average annual flow of 10 mat, Glen Canyon Dam can produce about 5,000 GWh annually. Because turbine capacity generally exceeds water supply, the annual electrical output of a dam is determined by the amount of water in the re- servoir. Thus, changes in daily or monthly operations will have no effect on annual power generation (Chapter 4~. They will, however, affect the sched- uling of electrical output and thus its value. The value of electricity varies substantially with time. Demand for elec- tricity fluctuates daily, weekly, and seasonally. It is higher during the day, when businesses are open, and lower at night and on weekends. It is greater during the winter and summer, when required for heating and cooling, than during the fall or spring. In addition, electricity cannot be cheaply or con- veniently stored. The reliabil ty of the electrical power system is also difficult to maintain. Power plants and customers throughout western North America are inter- connected, and electricity moves at the speed of light. If generation and consumption are not continuously and closely matched, the power system

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168 River Resource Management in the Grand Canyon becomes unstable and blackouts can result. Thus, utility systems are plan- ned to have sufficient generating capacity to supply customer requirements arm provide a reserve for malfunctions and other exigencies. The cost of producing electricity includes two principal components: (1 ) fixed costs to build power plants and keep them in operable condition and (2) variable costs associated with operation. For fossil fuel power plants, the variable costs relate mostly to fuel purchases. For hydra plants, which are powered by wafer, variable costs are relatively low, but the fixed costs of dam construction are high. In a typical large power system, several kinds of generating plants are used. In general, plants with high fixed costs and low operating costs (such as coal-fired stations) serve the base load, while plants with low fixed costs and higher operating costs (such as gas- or oil-fired stations) are used to meet peak demancl. Overall, base load is cheaper to serve than peak de- mand because fixed costs can be spread over more hours of output. One notable advantage of hydra plants is that they can respond quickly to variations in demand for electricity. Hydro turbines can be turned on and off almost instantaneously. In contrast, conventional thermal powerplants use boilers to generate steam for a turbine and can require substantial start-up time (ranging from minutes to hours) to generate electricity. Thus, hydro plants are especially well suited for providing peaking power. With the large turbine capacity at Glen Canyon Dam, traditional op- erations provided great flexibility to schedule electrical production at times when it would be most valuable. Changes in dam operations have restricted the maximum flows available during peak periods. These changes have the effect of shifting power output from periods when it is more valuable to periods when it is less valuable, with essentially no change in annual energy production. With less output during peak periods, additional supply is re- quired from other sources. Also, a quantity of off-peak power from Glen Canyon Dam is available for sale to other utilities or to displace the need for other power supplies. Thus, the cost of altered flows has been the difference between (1 ) the cost of peak power required to replace the output shifted to off-peak periods and (2) the value of this incremental off-peak power. THE INSTITUTIONAL CONTEXT Glen Canyon Dam is owned and operated by the Bureau of Reclamation. The Western Area Power Administration (WAPA) markets this electricity on a

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Power Economics 169 wholesale basis to about 180 preferred customers. As required by federal law, these preferred customers are municipal and county utilities, rural electric cooperatives, waterand irrigation districts, U.S. government installations, and other non profit organizations. Each individual customer serves a designated area in the region. As shown in Figure 9.1, most are in the six states of Ar- izona, Colorado, Nevada, New Mexico, Utah, and Wyoming, although some extend into California, Nebraska, and Texas. These preferred customers, in turn, serve 1.7 million end-use customers, including residential, commercial, industrial, and agricultural users. In part, the distribution of costs associated with altered flows is de- termined by the contractual arrangements for sale of Glen Canyon Dam electricity. Under existing contracts, WAPA's costs will increase, because it is obligated to supply fixed quantities of peaking power, which it may have to purchase at higher costs from other utilities. As contracts expire and are renegotiated, however, WAPA could contract to sell less firm peak power and more firm off-peak power. In this case, both the cost and the value of WAPA's electricity will diminish, and the need to replace the dam's output will be shifted to WAPA'S customers. Thus, there is a relationship between these marketing policy issues and the costs associated with altered flow regime. A separate EIS has been established to address marketing issues (WAPA, 1 994). It is important to distinguish between the economic perspective that measures changes in overall costs to society and the financial perspective concerning changes in the costs borne by specific entities. I n the short term, economic costs caused by altered flows will be limited, because the region currently enjoys a surplus of generating capacity (in excess of the required reserve margin). Underthe national economic perspective, the fixed costs of this existing capacity are excluded because they must be paid whether or not the capacity is used as a replacement for Glen Canyon Dam. From a financial point of view, however, there will be differences in costs and benefits among utilities. Utilities that have surplus capacity and can sell power to replace Glen Canyon Dam stand to gain at the expense of other utilities that must purchase power to replace Glen Canyon Dam power. Surpluses eventually will decrease, and prices for peak power can be ex- pected to rise. Eventually, new supplies will be required, which will entail both economic costs to society and financial costs to utilities. Within the restricted six-state marketing area for Glen Canyon Dam, 70 percent of electricity consumers (3.9 million) are served by utilities that do not receive power from the dam. Absent some new type of cost-sharing mech

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170 River Resource Management in the Grand Canyon _ _~ I NEVADA GLEN CANYON I DAM | _ ~ .3 ( WYOMING ~1 , . UTAH ./ COLORADO : .1 ARIZONA NEW MEXICO FIGURE 9.1 The Salt Lake City Area/lntegrated Projects markets power to approximately 180 utilities, mostly in six states. SOURCE: Bureau of Reclamation (1995~. anism, electricity bills for these utilities will be unaffected by changes at Glen Canyon Dam, or may decrease owing to surplus power sales. Notably, most of the region is served by investor-owned utilities (e.g., Arizona Public Service, Nevada Power, Public Service of Coloraclo, Utah Power), which are foreclosed by law from being WAPA preferred customers. Six relatively large utilities, which serve 1.3 million end-use customers, receive about half of Glen Canyon Dam's output. The remainder goes to numerous smaller systems, which together supply only 400,000 customers (7 percent of the region's total). Glen Canyon Dam operations, and the resulting revenues, also relate to a broader set of issues. Access to the relatively low cost electricity produced by the dam is restricted; about half goes to only 7 percent of regional el- ectricity consumers. Recipients of the dam's electricity benefit from the use of public water resources that were developed with low-cost government clebt. Under the terms of the Colorado River Storage Project Act, revenue from Glen Canyon Dam is intended to support reclamation irrigation projects.

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Power Economics 171 Judgments about the appropriateness of these historical arrangements influence determinations of how the costs of altered flows should be dis tributed. If the beneficiaries of Glen Canyon Dam have traditionally been subsidized at the expense of taxpayers and the environment, it is acceptable that they bear the costs of altered operations. Not surprisingly, this point of view is strenuously resisted by the beneficiaries of the dam, notably the Colorado River Energy Distributors Association (CREDA), which represents the utilities receiving the bulk of Colorado River hydropower. They assert that the beneficiaries of Glen Canyon Dam have paid their fair share and should be shielded from any increased costs (Barrett, 1 992a, 1 992b). COST ESTIMATES FOR ALTERED FLOW REGIMES Analyzing the costs of altered flow regimes is complex. The operation of Glen Canyon Dam must be simulated to provide a realistic estimate of the time pattern of power production under the various constraints of each flow regime. These simulations must be carried out over a number of years to reflect annual variations in hydrology. Once the output of the dam under different flow regimes has been es- tablished, the costs of these regimes to power users can be estimated. Such analyses typically rely on computer models, which are used to simulate the planning and operation of electric utility systems. These models require extensive data on existing power plants, new supply options, fuel costs, required reserve margins, interconnections between utilities, and current and projected electric ty demand. They use various mathematical techniques to determine the optimal (least-cost) solution, subject to specific constraints. Output includes data on the operation of each power plant, the new power plants and demand-side management (conservation) programsthat are used to meet requirements for new supply, and capital and operating costs. Relatively little work regarding power economics was undertaken during Phase I of GOES. In response to the National Research Council (NRC) comm ttee's review of GOES Phase I (NRC, 1991), WAPA was requested to analyze the economic effects of increasing minimum flows to either 5,000 or 8,000 cfs all year. WAPA estimated annual costs of $5.0 and $14.7 million, respectively, during the 1990s and much larger costs subsequently (NRC, 1991~. These cost estimates were based solely on a WAPA financial perspective. Moreover, the modeling of Glen Canyon Dam operations did not provide a realistic estimate of the time pattern of power production under the

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172 River Resource Management in the Grand Canyon constraints of each flow regime (NRC, 1991~. Therefore, the loss of peak period capacity and energy output due to altered flows was overstated. As part of GCES Phase 11, detailed power resource studies were initiated in November 1988. These studies were conducted by the Power Resources Committee (PRC). Three of thefour members have historically controlled and benefited from Glen Canyon Dam power resources: BOR, WAPA, and CREDA. In addition, however, the PRC included the Environmental Defense Fund (EDF), a national environmental group. As the developer of a widely used utility simulation model (ELFIN, or Electric Utility Financial and Production Cost Moclel), EDF provided the PRC with substantial technical expertise regarding utility economics, as well as an alternative point of view. The PRC's work focused on Glen Canyon Dam. However, during the early part of GCES Phase 11, individual members of the PRC also produced some analyses of costs related to experimental and interim flows. WAPA estimated overall costs of $10.9 million for experimental flows planned for 1990 and 1991 (NRC, 1991~. Once again, these cost estimates were based solely on a WAPA financial perspective. The modeling of Glen Canyon Dam operations was an improvement over previous work but still did not provide a realistic estimate of the time pattern of power production under the constraints of each flow regime (NRC, 1991~. EDF used ELFIN to evaluate the interim flow regimes proposed by various parties, including WAPA (EDF, 1991~. These estimates were based solely on a national economic perspective, which EDF argued should be given pre- ference over the financial perspective of affected utilities. Estimated costs for WAPA's proposal were only $1 million to $2 million annually over the period 1992 to 1995. For the other proposals, the costs were on the order of $9 million for 1992, increasing to $15 million to $16 million for 1995. For interim flows the BOR's draft environmental assessment noted that conclusive data were not yet available from the detailed power resource studies under way as part of GCES Phase 11 (BOR, 1991~. The costs were expected to be small, however, for the 3-year period of interim flow, because surplus capacity was likely to be available. From a national economic perspective, effects were characterized as a minor increase. The draft en- vironmental assessment stated that the financial effects on WAPA were estimated to be $22 million in fiscal year 1992. If financial exception criteria were provided, allowing limited exceedances flow criteria, costs would be reduced to only $3 million. Exception criteria were ultimately accepted by the BOR, and the costs of interim flows have been relatively low. To date, WAPA has avoided the need

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Power Economics 173 to purchase replacement capacity and has been able to operate with 10 to 15 percent available capacity above peak needs, as opposed to 30 percent previously (BOR, 1995~. The efforts of the PRO were first directed at determining the best app- roach to analyzing power economics. A detailed study (BOR, 1990) re- commended that the EGEAS (Electric Generation Expansion Analysis System) and ELFIN simulation models be used and their results compared. EGEAS has the capability to perform expansion planning (addition of new resources) as well as production cost estimates (dispatch of a given set of resources). ELFIN estimates production costs and utility financial models. For the power resources studies, EGEAS modeling was carried out by Stone and Webster Consultants, Inc., a contractor retained by the BOR through HERS, Inc. (the contractor for GOES recreation and nonuse value economics studies). The expansion plans developed by using EGEAS were used as inputtothe ELFIN modeling conducted by EDF. The production cost projections of the two models were similar. Power system costs were measured over a 50-year period. To allow for changes at Glen Canyon Dam to influence the need for new supplies, the most detailed analysis was conducted for an initial 20-year planning period (1991-2010~. To reflect costs over the lifetime of power plants, a 30-year extension period (201 1-2040) was modeled. Continued escalation in fuel and other costs was assumed, but the level of demand and set of supply re- sources forecast for 2010 were held constant (resources being retired were assumed to be replaced in kind). The operation of Glen Canyon Dam also had to be simulated to estimate the time pattern of power production under each flow regime. The BOR's Colorado River Simulation Model (CRSM) was the source of projections for monthly water releases, capacity, and energy. CRSM has no capability for simulating hourly operational constraints, such as those imposed by fluctuating flow alternatives. As discussed earlier, two marketing approaches were modelecl. For the Contract Rate of Delivery (CROD) marketing app- roach, a simple geometric method was used to determine available capacity. The peak shaving algorithm from ELFIN was utilized for the hydrology mar- keting approach. The foregoing description only begins to capture the intricate array of analyses undertaken for the power resources studies (see Figure 9.2~. In large part, this complexity results from efforts to reflect the institutional context, with its multiplicity of affected parties, viewpoints, and practices. In particular, much of the effort in the power resources studies was devoted to

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74 No-Action Case Flow Alternative ~ ECE\S r I ,r Purchased Avoided Power Economic Costs Supply Costs 1 ' ' 1 Individual and Total Utility Economic Results (CROD only) River Resource Management in the Grand Canyon | CROD | CROD and Fnancal Hydrology Economic Studies h Studies i Federal Repayment and Rate Study Utility Wholesale Rate Impacts Small Systems Retail Rate Impacts Compute Differences No-Action Alternatives 1 Total System Before Transfer Payments Subtract Transfer Payments Between Large and Small Systems Firm Purchased Power Capacity Cost Transactions Total Federal Economic Results 1 1 FIGURE 9.2 Study process to determine power values. SOURCE: Adapted from Power Resources Committee (1994, Fig. 1-3~. detailed modeling of the financial and rate effects on individual utilities. Even for the analysis of the national economic perspective, separate

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Power Economics 175 simulations were conducted for each of seven large utilities (one of these utilities has now been absorbed by the others), with some attempt to re- concile and coordinate the individual analyses. Meanwhile, the small utilities, which rely on WAPA and other utilities for most or all of their supply, were not included in the EGEAS modeling. These were assumed to purchase re- placement powerfrom their alternative suppliers, at costs based on the EGEAS model of large systems. It would have been simpler to model all of the utilities as a single in- tegrated system. This approach was recommended by the NRC committee and rejected by the PRO (NRC, 1992; Roluti, 1993; Power Resources Committee, 1993, 1994~. The rationale was that the individual utilities do not now coordinate the operation of their systems so as to minimize overall costs. Moreover, existing transmission capacity between utilities is limited. Thus, results based on a single optimized system could understate the actual costs of system operations. However, even within the constraints imposed, the resource plans selected were not completely optimized (Power Resources Committee, 1993, 1994~. The focus on individual utilities and financial effects also necessitated detailed modeling of WAPA's marketing practices. The data on Glen Canyon Dam's power production had to be combined with estimates of the output from other hydra projects marketed by WAPA to determine the amount of power and energy that would be contracted for sale to preferred customers. This determination was affected by the marketing criteria used by WAPA. Currently, WAPA uses the approach, CROD (Contract Rate of Delivery) according to which the amount of firm capacity and the amount of energy are fixed in advance, and WAPA must purchase electricity to supplement hydro output in dry years. Alternatively, under the hydrology approach, WAPA would sell only the capacity and energy available given actual hyciro output. Customers, rather than WAPA, would be responsible for meeting any additional needs. The power resources studies modeled both the CROD and hydrology approaches. Extensive analyses were performed of the sensitivity of results to changes in input assumptions or methodology. Sensitivity analyses are standard practice in power economics studies. In keeping with recenttrends, the Glen Canyon Dam analyses relied to some extent on sophisticated probabilistic approaches. The use of sensitivity analyses, however, is not a substitute for selection of appropriate base-case assumptions. When the PRO was unable to reach consensus on these assumptions, remaining disagreements were typically "resolved" by specifying a case for sensitivity analysis. This was also

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176 River Resource Management in the Grand Canyon the response to certain concerns expressed by the NRC committee (NRC, 1992; Roluti, 19g3; Power Resources Committee, 1993, 1994~. The EGEAS model was also used to estimate emissions of atmospheric pollutants. Emissions rates for each power plant (tons of sulfur dioxide (SO2) and nitrogen oxides (N Ox) per unit of fuel burned) were provided as input. The model then combined these data with the results concerning power plant operations to estimate the total tons of SO2 and NOx. Review of the power resources studies is further complicated by the significant changes that occurred over the course of GOES work. The PRO produced three reports that were provided to the NRC committee: a draft Phase 11 report (PRC, 1992), a final Phase 11 report (PRO, 1993), and a Phase 111 report (PRC, 1995~. Each report incorporated improvements in metho- dology and data from the previous one. These improvements addressed problems in the analysis identified bythe NRC committee and other reviewers (NRC, 1992; NRC, 1994~. Unfortunately, the usefulness of GOES Phase 11 and Phase 111 results is compromised by changes in the flow alternatives that were modeled. The Phase 11 studies analyzed eight flow.alternatives (including "no actions. Prior to the release of the draft EIS, beach-building and habitat maintenance flows were added to the moderate fluctuating flow and seasonally adjusted steady flow alternatives; they were also included in the new preferred alternative of the EIS (modified low fluctuating flows). The Phase 11 studies were too ad- vanced to incorporate these changes, so consideration of them was deferred to Phase 111. Because of resource constraints, Phase 111 work was limited to the "no action" and preferred alternatives. As a result, there are no Phase 111 results for most flow alternatives, and the final EIS largely relies on the earlier Phase 11 work. For the three flow alternatives that include beach-building and habitat maintenance flows, cost data for the final EIS were derived from a simple regression analysis based on the amount of capacity lost and the costs estimated for Phase 11 flow alternatives. The final EIS does provide the Phase 111 results as supplemental data for the preferred alternative. Table 9.1 summarizes the most important numerical results from the power resources studies. In the interest of brevity, data are presented for only three flow regimes. "No action" serves as the benchmark for measuring the effects of altered flows. Seasonally adjusted steady flows result in the greatest power resource costs and potentially the greatest benefits in terms of protecting other resources. The preferred alternative and seasonally adjusted steadyflow bracketthe range of operational changes likely to be im

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Power Economics 177 TABLE 9.1 Summary of the Effects of Three Operating Regimes on the Value of Electrical Power From Glen Canyon Dam Preferred Alternative: Seasonally No Modified Low Adjusted Action Fluctuating Flow SteadyFlow Marketable Resource Annual Energy (GWh) 6,010 6,018 6,123 (+0.1%) (+ 1.9%) Winter Capacity (MOO, 1,407 965 640 (-31.4%) (-54.5%) Summer Capacity 1,315 845 498 (-35.2%) (-62.1 %) Increase in Economic Costs (relative to No Action) Arnual (nominal$million) Phase II Phase lil CROD So $44.2 $34.8 $123.5 Hydrology $0 $15.1 $25.0 $88.3 Present Value (1991 $ million) CROD So $511.2 $402.0 $1,428.4 Hydrology $0 $174.6 $286.8 $1,021.2 WAPA Wholesale Rate (FY 1993 /kWh) 1.878 2.316 2.820 (+23.3%) (+50.2%) Retail Rates (/kWh) Customers Large systems (23% end No Slight See text Slight users) change decrease to p.178 decrease to moderate moderate increase increase Small systems (7% end 6.41 7.05 See text 7.58 users) . (+10.0%) p. 178 (+16.3%) No No change No change Other regional utilities p0% change to slight to slight of end users) decrease decrease

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178 River Resource Management in the Grand Canyon plemented and that might occur in connection with endangered-fish research. Costs for fluctuating flow regimes not shown in Table 9.1 are generally intermediate between those for "no action" and the preferred alternative, while those for other steady flow regimes are intermediate between the preferred alternative and seasonally adjusted steady flow. The preferred alternative reduces WAPA's marketable capacity by approximately 450 MW. In the power resources studies, the stream of annual nominal dollar costs is present valued to 1991 using an 8.5 percent nominal discount rate. Based on the GOES Phase 111 study, the present value of the associated economic cost is on the order of $300 to $400 million. Levelized over the 50 year analysis period, this is equivalent to an annual cost of $25 to $35 million in nominal dollars or $15 to $20 million in 1991 dollars. The power resources studies report annual costs on a nominal levelized basis; over the 50-year period being analyzed, the estimated equivalent ann- ual effects remain constant in nominal terms. In constant (inflation-adjusted) dollars, they are highest in the first year and decline steadily due to inflation. The figures for 1991 dollar levelized costs in this report were calculated based on the rea/ discount rate. Given the 3.8 percent inflation rate assumed (Power Resources Committee, 1993, p. 111-13), the 8.5 percent nominal discount rate is equivalent to a 4.5 percent real discount rate. For a 50 year period, this yields a real annualization factor of 5.08 percent. Annual impacts in 1991 dollars are approximately 41 percent less than those calculated on a nominal basis. Costs incurred in any given year are expected to vary substantially over time. In general, they would be lower in earlier years. The region has a surplus capacity, which the power resources modeling assumes would be prolonged as the large utilities implement demand-side management pro- grams. Costs would rise after 1998 as new capacity is required. Costs will also be affected by variations in hydrology. The constraints associated with altered flows will have less effect during wet years. For the preferred alternative, WAPA's wholesale rates are estimated to increase by about 0.5/per kilowatt-hour, but Glen Canyon Dam power would still be highly competitive with alternative sources. Most regional electricitycustomerswould experiencelittle, if any, change intheir retail rates. For several reasons, however, the effect of changes in operations at Glen Canyon Dam will tend to be much greater for the small preferred customers. They typically buy most or all of their power from other utilities and rely heavily on Glen Canyon Dam power. By contrast, the large preferred cus- tomers generate much of their own power. They currently have surplus cap

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Power Economics 179 acity, which can be used to replace lost Glen Canyon Dam power for their own needs and through expanded sales to the small systems. The final EIS for Glen Canyon Dam reports that increases in small system retail rates would range from 4 to 16 percent, averaging 10 percent or about 0.6/per kilowatt-hour. The basis of these estimates is unclear. The draft EIS reported smaller effects on rates, similar to those shown in the GOES Phase 11 study (PRO, 1993). Thefinal EIS cites the Phase 111 study (PRO, 1995), but the version of the report provided to the NRC committee does not include the final EIS data. The data that are provided in the Phase 111 report indicate that effects on rates will vary both across utilities and over time, with a maximum increase of 9.5 percent for one utility in 1 year. On average over the 1991- 2010 period, rates will rise by 1 percent or less for Rural Electric Admin- istration member utilities and by 2 to 5 percent for municipal utilities. Seasonallyadjusted steaclyflow reducesWAPA's marketable capacity by approximately 800 MW. The present value of the associated economic cost is estimated to be on the order of $1 billion to $1.4 billion. Levelized over the 50-year analysis period, this is equivalent to an annual cost of about $90 to $120 million in nominal dollars or about $50 to $70 million in 1991 dollars. As for the preferred alternative, costs would generally be lower in the earlier years. However, the greater loss of capacity would advance the need for construction of new capacity and the associated costs. Cost estimates based on Phase 111 methodology would likely be lower than these, which are based on the Phase 11 approach, which does not value off-peak energy correctly. WAPA's wholesale rates are estimated to increase by about 1 /per kilowatt-hour. Even so, Glen Canyon Dam power would still be competitive with all but the lowest-cost alternative sources. Most regional electricity customers would experience limited, if any, change in their retail rates. Reported increases in small system retail rates would range from 8 to 33 percent or, on average, 18 percent or about 1.2/per kilowatt-hours. In summary, the cost effects of the preferred alternative are relatively modest. Costs for seasonally adjusted steady flows are generally two to three times greater than those for the preferred alternative. Even costs of this magnitude, however, would have only limited effects on agriculture and no material impact on the overall regional economy (BOR, 1995; WAPA, 1994; Flaim et al., 1994~. For any altered flow regime, some small utility customers may bear a disproportionate share of the costs; however, they also received a disproportionate share of the benefits of low-cost Glen Canyon Dam electricity in previous years. The costs of altered flows may be less than estimated, especially for the

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180 River Resource Management in the Grand Canyon small utilities, which account for most of these costs. The GOES power resources studies did not consider the option of having WAPA maintain the same marketing commitment and use its transmission system to procure low- cost replacement capacity on behalf of its customers. Studies in support of the marketing EIS indicated that this approach could considerably reduce economic and financial effects (BOR, 1995~. Even without such an approach, changes in the electricity industry (e.g., the U.S. Energy Policy Act of 1992) are providing greater access to a wide variety of low cost electricity supply sources, especially for small utilities, which traditionally have been limited in their supply options. The base-case analysis in the power resources studies assumes a rapid escalation in oil and gas prices (averaging 8.4 percent nominal or4.4 percent real annually), which now appears highly unlikely. Lower oil and gas prices would reduce the costs of operating the peaking plants used to replace lost capacity at Glen Canyon Dam. The power resources studies also did not explicitly consider the relationship between electricity prices and the amount of energy consumed (price elasticity). If rates increase because of altered flows, this will reduce future electricity demand. In turn, this will delay the need for new capacity and reduce the cost of altered flows. The PRO chose to deal with these issues through sensitivity analyses, which confirm that the estimated costs of altered flows will be substantially lower if lower fuel prices and lower demand materialize in the future. The costs associated with altered flows must be compared with the benefits. The preferred alternative reduces regional SO2 and NOX power plant emissions by almost 1 percent, as fossil fuel generation is shifted from base load to cleaner peaking plants and construction of new cleaner plants is advanced. Under the Clean Air Act Amendments of 1990, there is a market for SO2 emissions allowances. On this basis, the GOES Phase 111 report estimates that SO2 emissions reductions are worth about $5 million (1991 net present value) or about 1 to 2 percent of the estimated increase in electricity costs (PRO, 1995~. Seasonally adjusted steady flow would likely result in even greater reductions in emissions. The power resources studies did not consider othertypes of environmental impacts, such es those associated with fuel supply and transportation. Nonetheless, it is reasonable to assume that by shifting electricity production to newer and cleaner power plants, altered flows will generally reduce adverse environmental impacts. The preferred alternative yields increased recreation values of $43.3 million (1991 present value), equivalent to about 10 to 15 percent of the estimated increase in electricity costs (BOR, 1995~. Nonuse values are of

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Power Economics much greater magnitude than the increase in power costs (Chapter 7~. RECOMMENDATIONS 181 The GCES power resources studies were impeded by an unfortunate combination of factors. The process was dominated by the entities that historically have controlled and benefited from Glen Canyon Dam power resources, notably BOR, WAPA, and CPtEDA. These entities have a clear incentive to deter implementation of altered flows, which would reduce the value of the dam's electrical output. On the other hand, they have the ex- pertise to perform power resource studies, in light of their familiarity with these issues and high level of analytical resources. In fact, however, very little useful information regarding the cost effects of altered flow regimes was provided by those entities during Phase I of GCES. During GCES Phase 11 there was great progress in developing the requisite tools for measuring cost effects. Nonetheless, the end result has not been wholly satisfactory in terms of providing cost estimates that are accurate, well documented, and readily reviewable. Unfortunately, the data in the EIS are principally based on Phase 11 Power Resources studies, rather than the subsequent Phase 111 analyses, which generally indicate lower costs for altered flows. It is difficult, even with hindsight, to make completely definitive judgments of many aspects of the power resources studies. To some degree, the multiple analyses that were undertaken reflect the complex institutional context and the distribution of costs and benefits across different groups. Given the constraints in terms of budget and schedule, however, the strong focus on distributional issues has adversely affected the accuracy and timeliness of the analysis from a national economic perspective. Given that Glen Canyon Dam is federally owned and affects resources of national (and international) significance, the national economic perspective should be given precedence in the future. This approach is in keeping with the principles and guidelines established for federal water projects (Water Resources Council, 1 983~. The power resources studies generally assumed that current practices arid constraints would remain in place throughout the 50-year analysis period. This is problematic because the electric utility industry is evolving toward a more competitive future, which should help reduce the cost of altered flow regimes. The PRO missed a valuable opportunity to inform decision makers

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182 River Resource Management in the Grand Canyon concerning the effect of these changes. In particular, analyses could have been conducted both for the current, less integrated system and for a single optimized system. The former would have provided an upper bound for costs, assuming continuation of the status quo. The latter would provide a lower bound for costs, which could be achieved if the existing constraints on cost minimization were eliminated. In part, the problems with the GOES power resources studies stem from the lack of a continuous open planning process that is accessible to the public. By contrast a very different set of procedures is in place for ad- dressing electric power issues in the Pacific Northwest concerning the Columbia River system. Both the Colorado and Columbia River systems feature extensive hydroelectric facilities operated byfederal agencies that sell power to government-owned utilities under environmental constraints. But due in part to the Northwest Power Planning Act, the Northwest region has long had a major planning effort that has developed the necessary tools and institutions required to evaluate the effects of various alternatives. There is a high level of expertise on the part of federal agencies, the utilities, and other interested parties such as environmental groups and state governments. Furthermore, this process has been steadily building in expertise over the past two decades. In contrast, the GOES and Glen Canyon EIS were the first time that much of this type of analysis had been undertaken for the Colorado River system area. In addition, given the many disparate interests, there were many procedural issues to resolve, and it has been difficult to obtain the requisite economic and financial data. Overall, the process has been difficult, time consuming, and costly. Also, unlike the process for the Columbia River, which involves a continuing mandate and an established institutional en- vironment, it is unclear to what extent power studies for Glen Canyon Dam will continue in the future. Clearly, there is a need to update the power studies over time for the purposes of adaptive management. Moreover, without such projections, it will be difficult to plan and operate the regional power system effectively. The BOR or Department of the Interior should sponsor the development of analytical and modeling capabilities that can continue to provide in- formation concerning the cost of dam operations. This would permit regular revisions to reflect the rapidly evolving electricity industry and other factors. Future studies relating to the operation of Glen Canyon (and other hydra facilities) should explicitly consider how current practices and constraint may be altered by factors such as the evolution of the utility industry. Continued

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Power Economics 183 modeling also could facilitate the numerous processes that are now affecting the Colorado River hydra system. Subsequent to the release of the final WAPA marketing EIS in the summer of 1995, a commitment level will be established for firm power and energy to be marketed through 2004. This process may be delayed, however, by consideration of proposals to privatize WAPA. As mandated by the Grand Canyon Protection Act, WAPA has initiated a Replacement Resources Process to study and report on methods to make up for any reductions in Glen Canyon Dam output. The U.S. Energy Policy Act of 1992 requires WAPA customers to prepare and implement Integrated Resource Plans that consider a full range of supply options, including demand-side management and renewable energy sources. Continuing study of power economics is important, given the complex issues being examined and the need for updating. Such capabilities could be used in optimizing the timing of experimental flows. This could be a major issue. The endangered fish research included as a common element in the EIS alternatives would involve monthly release volumes similar to the seasonally adjusted steady flow alternative. It is unclear how long this re- search would continue, but the EIS indicates that it could be for as much as 1 0 years. More generally, an attractive strategy would be to experiment with highly restrictive flow regimes (e.g., seasonally adjusted steady flow) in the short term when surplus capacity is available and the cost of such alternatives is low. Then, ~ the costs of altered flows rise in the future, decisions on whether to move toward a less restrictive alternative (e.g., modified low fluctuating flows) could be made based on revised studies concerning the effects of flow regimes on power and other resources. Near-term experimentation with highly restrictive flow regimes may also reduce the need to experiment in later years, when less surplus capacity is available and costs could be much higher. Thus, a strategy of extensive short-term experimentation could reduce long-term electricity costs. When evaluating future dam operations, especially experimentation with highly restrictive flow regimes, decision makers should consider long-term, as well as short-term, impacts. Experimentation which has significant long-term benefits should not be unduly restricted in an attempt to minimize short-term increases in power costs.

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184 River Resource Management in the Grand Canyon REFERENCES Barrett, C. 1992a. Letter to the Editor, The Washington Post, January 21, from Clifford Barrett, Executive Director, Colorado River Energy Dis- tributors Association. Barrett, C. 1 992b. Letter to Sheila David, Program Officer, NRC Committee to Review the Glen Canyon Environmental Studies, February 10, from Clifford Barrett, Executive Director, Colorado River Energy Distributors Association. Bureau of Reclamation et al. April 1990. Final Report, Evaluation of Methods of Estimated Power System Impacts of Potential Changes in Glen Canyon Powerplant Operations. Bureau of Reclamation, Washington, D.C. Bureau of Reclamation. 1991. Glen Canyon Dam, Interim Operating Criteria, Draft Environmental Assessment. Bureau of Reclamation, Upper Col- orado River Regional Office, Salt Lake City. Bureau of Reclamation. 1995. Operation of Glen Canyon Dam, Colorado River Storage Project, Final Environmental Impact Statement. Bureau of Reclamation, Salt Lake City. Environmental Defense Fund. 1991. Estimates of Power System Impacts of Proposed Interim Flow Release Patterns at Glen Canyon Dam. Oakland, Calif.: Environmental Defense Fund. Flaim, S.~., R.E. Howitt, and B.K. Edwards. 1994. Impacts on Irrtigated Agriculture of Changes in Electricity Costs Resulting from Western Area Power Administration's Power Marketing Alternatives. Draft report, Argonne National Laboratory, Technical Report No. W-31-109 Eng-38, for the U.S. Department of Energy, Argonne, 111. National Research Council. 1991. Colorado River Ecology and Dam Management. Washington, D.C.: National Academy Press. National Research Council. 1994. Review of the Draft Environmental Impact Statement on Operation of Glen Canyon Dam. Washington, D.C.: National Academy Press. Power Resources Committee. 1992. Power Systems Impacts of Potential Changes in Glen Canyon Powerplant Operations. Glen Canyon En- vironmental Studies Technical Report. Draft, Stone and Webster Man- agement Consultants, Inc., Englewood, Colo. Power Resources Committee. 1993. Power Systems Impacts of Potential Changes in Glen Canyon Powerplant Operations. Glen Canyon En- vironmental Studies Technical Report, Stone and Webster Management Consultants, Inc., Englewood, Colo.

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Power Economics 185 Power Resources Committee. 1995. Power Systems Impacts of Potential Changes in Glen Canyon Powerplant Operations, Glen Canyon Environmental Studies Technical Report. Stone and Webster Con- sultants, Inc., Englewood Colo. Roluti, M.~. 1993. Letter to William M. Lewis, Chair, NRC Committee to Review Glen Canyon Environmental Studies, Subject: Power System Impact of Potential Changes in Glen Canyon Environmental Studies, April 29, from Michael J. Roluti, Chair, Power Resources Committee, Bureau of Reclamation, Upper Colorado Regional Office. Water Resources Council. 1983. Economic and Environmental Principles and Guidelines for Water and Related Lana Resources Implementation Stuclies. Washington, D.C.: Government Printing Office. Western Area Power Administration. 1994. Salt Lake City Area Integrated Projects Electric Power Marketing. Draft Environmental Impact State- ment, Western Area Power Administration, Salt Lake City.