APPENDIX J MODELING TEHCNICAL MEMORANDUM (RESSIM MODELING)
Technical Memorandum To: Michael J. Preszler, California Water Consulting From: Marieke Armstrong, Mead & Hunt Rahul Ranade, Mead & Hunt Date: December 7, 2009 Subject: HEC-ResSim Impact Analysis for the El Dorado Water & Power Authority Supplemental Water Rights Project EIR 1.0 Introduction and Background Mead & Hunt has conducted an analysis of the El Dorado Water & Power Authority Supplemental Water Rights Project using HEC-ResSim, a reservoir simulation model. This technical memorandum outlines and describes the ResSim modeling assumptions and operational approach used in generating the hydrologic output. Evaluation of the impact of the Supplemental Water Rights Project has been done through a comparison of the base condition scenario with various projected scenarios, which has also been described in this memorandum. 1.1 Supplemental Water Rights Project The El Dorado Water & Power Authority (EDWPA), a joint powers authority composed of El Dorado County, El Dorado County Water Agency, El Dorado Irrigation District (EID) and Georgetown Divide Public Utility District (GDPUD), has filed an application for supplemental water rights from the upper American River basin. The objective of the application is to establish permitted water rights allowing diversion of water from the American River basin to meet planned future water demands in the EID and GDPUD service areas and other areas located within El Dorado County that are outside of these service areas. EDWPA s filing entails a total withdrawal for use of 40,000 acre-feet (AF) per annum, consistent with the diversion and storage locations allowed under the El Dorado - Sacramento Municipal Utility District (SMUD) Cooperation Agreement. EDWPA has retained California Water Consulting to provide the engineering and draft environmental impact report requirements to support the water rights application. Mead & Hunt is assisting California Water Consulting with the execution of certain technical tasks, including the HEC-ResSim analysis of the impacts of the proposed water rights. 1.2 Project location and components The Supplemental Water Rights Project involves multiple water bodies including several reservoirs and watercourses within the upper American River basin. These are part of the Upper American River Project (UARP) owned and operated by the Sacramento Municipal Utility District (SMUD) and include Union Valley Reservoir, Ice House Reservoir, Loon Lake Reservoir, Gerle Creek at Loon Lake Reservoir, Gerle Creek at Gerle Creek Reservoir, Rubicon River and Rubicon Reservoir, Little Rubicon River at Buck Island Reservoir, South Fork (SF) Rubicon River at Robbs Peak Reservoir, and Silver Creek at Camino
Technical Memorandum Michael J. Preszler December 7, 2009 Page 2 Reservoir. The project also includes parts of the South Fork of the American River, White Rock Powerhouse Penstock, and Folsom Reservoir. Figure 1 shows map of the project area. 1.3 HEC-ResSim analysis Owing to the complexity of the project, a numerical computer modeling exercise was necessary to evaluate the impacts of the Supplemental Water Rights Project on existing conditions. HEC-ResSim (Version 3.0.1), a public domain software package developed by the Hydrologic Engineering Center of the U.S. Army Corps of Engineers (HEC) as a decision support tool for reservoir regulators, was used for the purpose. Features of ResSim include: A map-based schematic development environment. A complex reservoir element that can include multiple dams and outlets. An operations scheme that can define the reservoir's operating goals and constraints in terms of pool zones and zone dependent rules. A set of operation rule types that include release requirements and constraints, downstream control requirements and constraints, pool elevation or inflow rate-of-change limits, hydropower requirements, and induced surcharge (emergency gate operation). Operation of multiple reservoirs for a common downstream control, including storage balancing. Alternative builder to allow for a wide range of "what if" analysis. Computation timesteps from 15 minutes to 1 day. Summary Reports and a Release Decision Report. HEC-DSS (a scientific database system developed by HEC) for storage of input and output data. As a starting point, this analysis used an existing ResSim model (Hughes, 2007), jointly developed by the Department of Fish & Game and U.S. Forest Service as part of SMUD s UARP FERC relicensing process. This model is based on the conditions established in the Relicensing Settlement Agreement for the UARP and Chili Bar project between SMUD, Pacific Gas & Electric (PG&E), and various governmental and non-governmental agencies and individuals (SMUD et al, 2007). Following the California Department of Fish and Game (CDFG) model, we selected the period extending from Water Year (WY) 1975 through WY 1999 as our study period because of the availability of observed data and unimpaired flow estimates for this period. Alternate scenarios were created to reflect the various possible withdrawal cases under the proposed water rights and the model was used to verify the environmental boundary conditions associated with EDWPA s proposed diversion and provide a means of determining the potential impact to the reservoirs and watercourses in the project area, relative to those established in the Settlement Agreement. \\Sacd\entp\03355-00\08001\TECH\Memo\Impacts Tech Memo 120709.doc
Technical Memorandum Michael J. Preszler December 7, 2009 Page 3 2.0 Approach The existing ResSim model, with modifications to reflect the diversion at White Rock penstock, was used to generate the time-series for comparison. Because this analysis is based on a pre-existing model, detailed background information on the model construction is not provided here. Such information may be found in the supporting document for the Settlement Agreement ResSim model published by California Department of Fish & Game (Hughes, 2007). The objective of the model is to evaluate the impacts of the proposed EDWPA diversions on the reservoirs and watercourses in the project area. Modifications were made to the model to incorporate the proposed diversion and are described in Section 2.1. The evaluation of the impacts of the diversion was done through a comparison of the base condition (i.e., Settlement Agreement scenario) with four possible diversion scenarios (described in Section 2.2) using various metrics such as power generation, rafting flows, reservoir storage, and lake levels (described in Section 2.3). Computational limitations of the model are discussed in 2.4. Finally, the period of evaluation for the results is presented in Section 2.5. 2.1 Model Modifications The ResSim model contains a, which reflects the Relicensing Settlement Agreement and four proposed scenarios. These different diversion scenarios are summarized in Table 1. In all scenarios, the total annual diversion has a monthly distribution in accordance with the Monthly Water Need Schedule table attached in Appendix A. Instantaneous diversion values at White Rock Penstock and Folsom Reservoir are summarized in Tables 2 and 3. The spatial location of the diversion points is shown in Figure 1. The following modifications were made to the UARP model to reflect the White Rock Diversion in physical and operational terms: 2.1.1 Diverted Outlet A Diverted Outlet was added at Slab Creek Reservoir (identified as EDWPA Diversion). 2.1.2 Operation of Slab Creek Reservoir Operation of Slab Creek Reservoir in the Base Scenario model (formerly ResLevel2 from DFG model) is governed by the operation set RecFlow-6. Copies of this set were made to retain all other parameters, and the copies were then modified to create four new operation sets, each of which reflects one of the four scenarios being studied. These operation sets are: -2 \\Sacd\entp\03355-00\08001\TECH\Memo\Impacts Tech Memo 120709.doc
Technical Memorandum Michael J. Preszler December 7, 2009 Page 4-2 2.1.3 Alternatives Under each of these alternatives, eponymous new rules were created to reflect the proposed diversions. These rules operate release from Slab Creek Reservoir through the EDWPA Diversion (entity identified in the model as Slab Creek Reservoir EDWPA Diversion ). Each of these rules contains Release Functions which reflect the monthly flows shown in Table 2. The Release Functions were created using a Date Function. 2.1.4 EDWPA Null To ensure that no water is diverted to EDWPA Diversion during the base scenario, a rule called EDWPA Null was created under the operation set RecFlow-6 (which operates the Base Scenario alternative). This rule restricts the diversion to zero throughout the year. 2.1.5 Time-step A time-step of one day was adopted for the model 2.2 Diversion Scenarios The EIR includes the Project and six alternatives including the No Project Alternative. Only some of the alternatives are being evaluated with the ResSim model to represent the base case conditions and the maximum and minimum proposed diversions. It is assumed that all other scenarios would fall within these extremes. The various diversion scenarios considered for this analysis are described below and summarized in Table 1. In all scenarios, the total annual diversion has a monthly distribution in accordance with the Monthly Water Need Schedule table attached in Appendix A. Instantaneous diversion values at White Rock Penstock and Folsom Reservoir are summarized in Tables 2 and 3. The spatial location of the diversion points is shown in Figure 1. 2.2.1 No ondition The base case is the same as the Settlement Agreement scenario. The Settlement Agreement has established various environmental thresholds (e.g., minimum instream flows, limits on tunnel diversions, provisions for geomorphic releases etc) which have been followed during the simulation of this scenario. This scenario does not include any additional water diversions and would represent the No project condition. The diversions are assumed to take place throughout the year based on the monthly water need schedule that was developed for the project. 2.2.2 This alternative scenario entails a total annual diversion of 40,000 AF from the turnout on White Rock Powerhouse Penstock. The diversions are assumed to take place throughout the year based on the monthly water need schedule that was developed for the project. \\Sacd\entp\03355-00\08001\TECH\Memo\Impacts Tech Memo 120709.doc
Technical Memorandum Michael J. Preszler December 7, 2009 Page 5 2.2.3 This alternative scenario entails a total annual diversion of 40,000 AF comprised of 30,000 AF from the turnout on White Rock Powerhouse Penstock and 10,000 AF from the American River Pump Station. The diversions are assumed to take place throughout the year based on the monthly water need schedule that was developed for the project. 2.2.4-2 This scenario entails a reduced total annual diversion of 20,000 AF from the turnout on White Rock Powerhouse Penstock. The diversions are assumed to take place throughout the year based on the monthly water need schedule that was developed for the project. 2.2.5-2 This scenario entails a reduced total annual diversion of 20,000 AF comprised of 15,000 AF from the turnout on White Rock Powerhouse Penstock and 5,000 AF from the American River Pump Station. The diversions are assumed to take place throughout the year based on the monthly water need schedule that was developed for the project. 2.3 Parameters Used for Comparison of Alternatives To quantitatively evaluate the impact of the four alternative scenarios with reference to the base scenario, it was necessary to identify parameters which could be easily discretized for numerical comparison. The parameters chosen for comparison are described below: 2.3.1 Power Generation The ResSim model is not specifically designed as a tool to evaluate energy generation impacts; however, the model does report energy generation with sufficient accuracy to be used to evaluate the overall difference in generation between two alternatives (Hughes, 2007). Power generation is calculated separately for each Upper American River Project and Chili Bar Project power plants. For evaluation, we evaluated total generation for both SMUD s Upper American River Project and PG&E s Chili Bar Project. 2.3.2 Reservoir Storage Annual inflows in the following reservoirs have been evaluated for comparison: Loon Lake Reservoir Union Valley Reservoir Ice House Reservoir Camino Reservoir Slab Creek Reservoir Chili Bar Reservoir \\Sacd\entp\03355-00\08001\TECH\Memo\Impacts Tech Memo 120709.doc
Technical Memorandum Michael J. Preszler December 7, 2009 Page 6 2.3.3 Reservoir Levels Lake levels in the following lakes have been evaluated from the recreation point of view: Loon Lake Reservoir Union Valley Reservoir Ice House Reservoir Camino Reservoir Slab Creek Reservoir Chili Bar Reservoir 2.3.4 Rafting Flows River flows are evaluated in the following reaches of Silver Creek and South Fork (SF) American River, which are popularly used for whitewater rafting: Silver Creek above SF American River SF American River below Slab Creek Reservoir SF American River Below Chili Bar Reservoir 2.4 Model Computational Limitations This analysis is based on a ResSim model for the Upper American River Project created by the CDFG. Operational modifications and addition of physical facilities to the model network were made as necessary to reflect the proposed EDWPA diversions. However, in order to preserve the nature of the model in its original form as created by its original author, we have attempted not to modify any other preexisting model features unless they related directly with the proposed EDWPA diversions. The flip side of this approach is that wherever the original model simulation encountered numerical instabilities, we did not mitigate them since any attempts at improving numerical efficiency of the model would entail modifying the structure or construction of the model, even if slightly. When simulation runs were conducted on the model in its original condition, it appeared there were minor numerical instabilities were found and the model was unable to converge on several instances when computing levels for Camino Reservoir. However, these instabilities were not significant enough to impede the simulation or affect the results. However, after adding the EDWPA diversion at White Rock Penstock, adding the associated rules and operation sets, and running the model over a continuous daily time series from WY 75 through WY 99, these instabilities were found to be amplified to the extent that the model simulation would stall. It appears that when ResSim is unable to converge on a solution after several passes, it automatically refers to the Lookback time-series and picks a value for the particular time-step for which it has been unable to converge. The model for this study is split in four simulations representing sub-periods (WY 75-81, WY 82-88, WY 89-95, WY 95-99). Naturally, each simulation (except the first one) was set to look back on the end result of the previous simulation period for its starting conditions and there was no single \\Sacd\entp\03355-00\08001\TECH\Memo\Impacts Tech Memo 120709.doc
Technical Memorandum Michael J. Preszler December 7, 2009 Page 7 continuous Lookback time-series for ResSim to refer to in case of a severe numerical instability. This lead to the model stalling because of the lack of a Lookback file when instabilities were found in the middle of a simulation period. To mitigate this situation, all four simulations were programmed to look back at an artificial WY1975-1999 Lookback time-series, rather than just the end results of the preceding time series. The disadvantage of this approach is that the starting condition of simulation periods would not match the ending condition of the previous simulation; however, we have observed that given the constraints imposed by the model Operation Sets, the results would quickly seek out appropriate values in a matter of a few time-steps. Therefore, some unrealistic results are seen at the beginning of each simulation period (except the first), but they do not cause significant impact on aggregated results. Owing to the numerical constraints described above, the model provides results that can be compared across scenarios within a given time period with an acceptable level of confidence. However, we advise that the numerical results should not be used at their absolute values for evaluation of tangible benefits like power generation or flow. If results are required for such application, the model can be modified to improve its numerical stability; these measures were outside the scope of this study. 2.5 Period of Evaluation Unimpaired mean daily data is available for the UARP and Chili Bar Projects from the Hydrology Technical Report (DTA & Hannaford, 2005) prepared as part of the relicensing efforts for the two projects for the period from WY 1974 through WY 2001. Though the model was run for the period from WY1975 through WY1999, for the ease of reporting and evaluation, only selected years have been presented in the results. These years have been selected on the basis of the water year type (i.e., based on amount of rainfall) - the Hydrology Technical Report classified each month between WY 1975 and WY 2001 as Critically Dry, Dry, Below Normal, Above Normal, and Wet. For the purpose of this analysis, we have used WY 1977 to represent a Critically Dry year, WY 1992 as Dry, WY 1990 as Below Normal, and WY 1997 as a Wet year. However, in the study period of WY1975-1999, there is no water year that showed unambiguous qualities in order to be represented as an Above Normal Year (water year-type definitions are based on SMUD Hydrology Technical Report). When Mead & Hunt presented a preliminary draft of this study in early January, we used a study period of WY 1975-2000 which had enabled us to use WY 2000 as an Above Normal year since it had consistently Above Normal rainfall in most of its months. However, that study was not run on a continuous time-series; hence it did not encounter the numerical instabilities described in Section 2.4. The current model runs have been programmed to look back at a single Lookback time-series. This time-series which was part of the original CDFG model stops at the end of WY 1999. As a result, the latest version of the model cannot be run past WY 1999. It was decided to leave out the Above Normal water year since there was no good representation within the dataset and values could be inferred using the Below Normal and Wet data. \\Sacd\entp\03355-00\08001\TECH\Memo\Impacts Tech Memo 120709.doc
Technical Memorandum Michael J. Preszler December 7, 2009 Page 8 3.0 Compliance with El Dorado-SMUD Agreement While the primary purpose of this study was to determine water availability for the various diversion scenarios summarized in Appendix A, it was also necessary to verify that all scenarios considered comply with other terms of the El Dorado-SMUD Cooperation Agreement (2005). Those requirements in the Agreement that have any implication on the proposed operational changes are discussed below. A number of other requirements in the Agreement pertain to non-operational factors such as communication, construction, maintenance, and forecasting, and are not discussed here. Further, some sections pertain to SMUD or El Dorado Emergency Conditions which are a result of unforeseen conditions beyond the control of parties involved; these requirements were not evaluated in the modeling study and are not discussed here. There are a number of terms in the following discussion that have not been explained in this memorandum because they are specific to the El Dorado-SMUD Agreement. These terms have been capitalized and their definitions can be found in Appendix D of the Agreement. Section 5.1.1 requires that SMUD supply up to 30,000 AF through 2025 and 40,000 AF thereafter to the El Dorado Parties. This requirement is satisfied through the proposed diversion at Slab Creek Reservoir, which releases water to the El Dorado Parties according to the monthly pattern summarized in Appendix A, totaling up to 40,000 AF per year. Section 5.1.2 requires that in any year that the El Dorado Parties are restricted from receiving agreed supplies because of drought or Emergency Conditions, SMUD will deliver water from Carryover Storage. In the period of this analysis (1975-1999), there were no years when agreed supplies could not be provided; hence this condition could not be evaluated. Section 5.1.3 requires that at any time when the Daily Net Storage exceeds 150,000 AF, SMUD make deliveries to Carryover Storage in amounts described therein. However, since the condition described in Section 5.1.2 was never encountered during the study period, it was assumed that the Carryover Storage is static and will not be required to be replenished on a frequent basis. Further, since the condition of Daily Net Storage exceeding 150,000 AF is a relatively frequent occurrence (87% of days during the study period), flow requirements to meet this condition would be small and distributed in even smaller portions when divided between contributing reservoirs. This number was assumed to be negligible and has not been evaluated in the modeling study. Section 5.2.2.3 requires that all El Dorado Water be delivered by SMUD through the White Rock Penstock interconnection shutoff valve. Because of software limitations, it was not possible to simulate the diversion exactly through the White Rock Penstock. The proposed El Dorado supply was programmed to be diverted directly from Slab Creek Reservoir instead. \\Sacd\entp\03355-00\08001\TECH\Memo\Impacts Tech Memo 120709.doc
Technical Memorandum Michael J. Preszler December 7, 2009 Page 9 Section 5.7 limits the diversion at the White Rock Delivery Point to a maximum rate of 100 cfs with the caveat that the rate may be increased up to 200 cfs during the period of May 1 through October 31 during the hours of midnight to 6:00 AM. Among the alternative scenarios considered here, flow rates at White Rock exceed 100 cfs only in one scenario () during the months of July and August. The excess flow of 4 cfs during regular hours can be compensated by releasing an additional flow of 12 cfs during the period from midnight to 6:00 AM; hence this condition is met (see following discussion on Section 5.8.1(i)). Section 5.8.1(i) precludes delivery to El Dorado Parties from May 1 through September 30 of any year from 2:00 PM to 7:00 PM. The loss of flow during these hours can be met by releasing additional 87 cfs during the period from midnight to 6:00 AM without violating the condition for maximum flow (Section 5.7). Section 5.8.1(iii) precludes delivery to El Dorado Parties when elevation of Slab Creek Reservoir drops below 1,815 feet. This scenario did not occur during the entire study period (1975-1999). 4.0 Results Raw results generated by HEC-ResSim are voluminous because of the extensive and complex nature of the basin, so efforts have been made to synthesize the results into analyzable form. Instead of presenting daily data, results have been compiled using average or instantaneous monthly/month-end values for clarity. Figures 2 through 5 show monthly comparisons for various parameters (i.e., energy, storage, lake levels, and rafting flows). Further, four figures have been presented for each parameter (e.g., 2A through 2D) for each representative water year. These comparisons have been plotted using absolute values of the results. On the other hand, all values shown in tables are normalized as a change from the base case scenario, so that the magnitude of impact between various alternatives can be easily read off the tables. Similar to the figures, Tables 4 through 10 show monthly comparison for each parameter, with sub-tables (e.g., 2A through 2D) for each representative reservoir and/or water year. Refer to the following Tables and Figures for each comparison of individual parameter: 4.1 Energy Generation: SMUD s Upper American River Project: Tables 4A through 4D and Figures 2A through 2D PG&E s Chili Bar Project: Tables 5A through 5D and Figures 3A through 3D \\Sacd\entp\03355-00\08001\TECH\Memo\Impacts Tech Memo 120709.doc
Technical Memorandum Michael J. Preszler December 7, 2009 Page 10 4.2 Reservoir Storage: Figures 4A through 4D show total storage for the six included reservoirs averaged over the month and presented by Water Year. 4.3 Tables 6.0A -6.0D Tables 6.0A -6.0D represent the total storage for the basin by Water Year with sub-tables for each of the following reservoirs: Loon Lake Reservoir: Tables 6.1A - 6.1D Union Valley Reservoir: Tables 6.2A - 6.2D Ice House Reservoir: Tables 6.3A - 6.3D Camino Reservoir: Tables 6.4A - 6.4D Slab Creek Reservoir: Tables 6.5A - 6.5D Chili Bar Reservoir: Tables 6.6A - 6.6D 4.4 Reservoir levels: Figures 5A through 5D show average reservoir elevation for the six included reservoirs averaged over the month and presented by Water Year. 4.5 Tables 7.0A -7.0D Tables 7.0A -7.0D show average reservoir elevation by Water Year with sub-tables for each of the following reservoirs: Loon Lake Reservoir: Tables 7.1A - 7.1D Union Valley Reservoir: Tables 7.2A - 7.2D Ice House Reservoir: Tables 7.3A - 7.3D Camino Reservoir: Tables 7.4A - 7.4D Slab Creek Reservoir: Tables 7.5A - 7.5D Chili Bar Reservoir: Tables 7.6A - 7.6D 4.6 Rafting Flows: Silver Creek above SF American River Tables 8A through 8D and Figures 6A through 6D. SF American River below Slab Creek Reservoir Tables 9A through 9E and Figures 7A through 7D. SF American River below Chili Bar Reservoir Tables 10A through 10E and Figures 8A through 8D. \\Sacd\entp\03355-00\08001\TECH\Memo\Impacts Tech Memo 120709.doc
Technical Memorandum Michael J. Preszler December 7, 2009 Page 11 5.0 Observations In general, impacts are more pronounced during dry years and tend to be minimal during wet years. The overall trends and comparisons across water years are reflected in the results, but some modeling noise may be observed in the absolute values of the results, thus we advise that the numerical results should not be used at their absolute values for evaluation of tangible benefits. Energy generation impacts are higher for SMUD than for PG&E in terms of total MWh. Energy generation impacts are greater during the summer months (June September). Overall reservoir storage and average reservoir pool elevation impacts are primarily attributed to Slab Creek Reservoir with more minor impacts at Union Valley and Chili Bar. The remaining reservoirs appear unaffected. The rafting flows at Silver Creek Above SF American River rafting flows appear unaffected Impacts to rafting flows at SF American River below Slab Creek seem more pronounced during wet years. The diversions appear to have little effect on the upstream system and are mostly incurred by the river stretches and reservoirs downstream of the diversion point at White Rock Penstock. The following is the range of impacts found across various parameters. To illustrate the worst case scenario, results from the Critically Dry Year (1977) have been used as an example. Naturally, impacts will be lower in years with greater flows. Impact on SMUD energy generation: 1 to 140 MWh Impact on PG&E energy generation: 0 to 12 MWh Impact on Slab Creek reservoir storage: 0 to 500 acre-feet Impact on Slab Creek reservoir levels: 0 to 2.5 feet Impact on Silver Creek above SF American River rafting flows: 0 cfs Impact on SF American River below Slab Creek rafting flows: Critically dry year: 0 cfs Wet year: 0 to 60 cfs Impact on SF American River below Chili Bar rafting flows: 10 to 105 cfs 6.0 Conclusion The diversion impacts appear to correlate with the amount of water diverted. Thus, (40,000 AF withdrawal at White Rock) causes the most severe impacts, while -2 (15,000 AF withdrawal at White Rock) has the lowest. Detailed economic analysis of the impacts may need to be conducted to assist in selection of the most appropriate analysis. \\Sacd\entp\03355-00\08001\TECH\Memo\Impacts Tech Memo 120709.doc
Technical Memorandum Michael J. Preszler December 7, 2009 Page 12 7.0 References DTA and Hannaford, 2005, Hydrology Technical Report for Sacramento Municipal Utility District Upper American River Project and Pacific Gas & Electric Company Chili Bar Project, Version 3, Devine Tarbell & Associates, Inc. and Margaret Hannaford, May 2005. El Dorado-SMUD, 2005, El Dorado-SMUD Cooperation Agreement, Various Parties, 2007 Hughes, Robert W., 2007, HEC-ResSim model of the Settlement Agreement Alternative for the Sacramento Municipal Utility District Upper American River Project and Pacific Gas & Electric Company Chili Bar Project, California Department of Fish & Game, January 2007 SMUD et al, 2007, Relicensing Settlement Agreement for the Upper American River Project and Chili Bar Hydroelectric Project, Various parties, January 2007 USACE, 2003, HEC-ResSim Reservoir System Simulation User s Manual Version 2.0, US Army Corps of Engineers, September 2003 \\Sacd\entp\03355-00\08001\TECH\Memo\Impacts Tech Memo 120709.doc
TABLES Table 1: Table 2: Table 3: Tables 4A 4D 1 : Tables 5A 4D: Summary of diversion scenarios Monthly diversions at White Rock Penstock Monthly diversions at Folsom Reservoir SMUD Energy Generation Tables PG&E Energy Generation Tables Tables 6.0A 6.0D: Total Reservoir Storage Tables 6.1A -6.1D Loon Lake Reservoir Tables 6.2A -6.2D Union Valley Reservoir Tables 6.3A -6.3D Ice House Reservoir Tables 6.4A -6.4D Camino Reservoir Tables 6.5A -6.5D Slab Creek Reservoir Tables 6.6A -6.6D Chili Bar Reservoir Tables 7.0A 7.0D: Average Reservoir Pool Elevation Tables 7.1A -7.1D Loon Lake Reservoir Tables 7.2A -7.2D Union Valley Reservoir Tables 7.3A -7.3D Ice House Reservoir Tables 7.4A -7.4D Camino Reservoir Tables 7.5A -7.5D Slab Creek Reservoir Tables 7.6A -7.6D Chili Bar Reservoir Tables 8A - 8D Tables 9A - 9E Tables 10A - 10E Rafting Flows Silver Creek above SF American River Rafting Flows SF American River below Slab Creek Reservoir Rafting Flows SF American River below Chili Bar Reservoir 1 All Project values in Tables 4 through 10 represent change from the listed.
Table 1 Summary of diversion scenarios Location of Diversion Name of scenario White Rock Powerhouse Penstock Folsom Reservoir American River Pump Station (future) Base Scenario - - - 40,000 - - 30,000-10,000-2 20,000 - - -2 15,000-5,000 Scenarios that have not been modeled (same as Base Scenario) Project A - 30,000 10,000 Project D - 40,000 - Project A-2-15,000 5,000 Project D-2-20,000 - Note: All values are in Acre-Feet and reflect annual diversions. Monthly distribution is shown in Table 2. X:\03355-00\08001\TECH\Memo\Memo tables 072009.doc 1
Table 2: Monthly diversions at White Rock Penstock Monthly distribution % 10% 5% 4% 4% 4% 4% 4% 8% 13% 16% 16% 12% 100% Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Total Monthly volume (AF) 4,000 2,000 1,600 1,600 1,600 1,600 1,600 3,200 5,200 6,400 6,400 4,800 40,000 Average flow (cfs) 65 34 26 26 29 26 27 52 87 104 104 78 Monthly volume (AF) 3,000 1,500 1,200 1,200 1,200 1,200 1,200 2,400 3,900 4,800 4,800 3,600 30,000 Average flow (cfs) 49 25 20 20 22 20 20 39 66 78 78 59-2 Monthly volume (AF) 2,000 1,000 800 800 800 800 800 1,600 2,600 3,200 3,200 2,400 20,000 Average flow (cfs) 33 17 13 13 14 13 13 26 44 52 52 39-2 Monthly volume (AF) 1,500 750 600 600 600 600 600 1,200 1,950 2,400 2,400 1,800 15,000 Average flow (cfs) 24 13 10 10 11 10 10 20 33 39 39 29 Note: Scenarios with no diversion at White Rock are not shown here X:\03355-00\08001\TECH\Memo\Memo tables 072009.doc 2
Table 3: Monthly diversions at Folsom Reservoir Monthly distribution % 10% 5% 4% 4% 4% 4% 4% 8% 13% 16% 16% 12% 100% Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Total Project A Monthly volume (AF) 3,000 1,500 1,200 1,200 1,200 1,200 1,200 2,400 3,900 4,800 4,800 3,600 30,000 Average flow (cfs) 49 25 20 20 22 20 20 39 66 78 78 59 Project D Monthly volume (AF) 4,000 2,000 1,600 1,600 1,600 1,600 1,600 3,200 5,200 6,400 6,400 4,800 40,000 Average flow (cfs) 65 34 26 26 29 26 27 52 87 104 104 78 Project A-2 Monthly volume (AF) 1,500 750 600 600 600 600 600 1,200 1,950 2,400 2,400 1,800 15,000 Average flow (cfs) 24 13 10 10 11 10 10 20 33 39 39 29 Project D-2 Monthly volume (AF) 2,000 1,000 800 800 800 800 800 1,600 2,600 3,200 3,200 2,400 20,000 Average flow (cfs) 33 17 13 13 14 13 13 26 44 52 52 39 Note: Scenarios with no diversion at Folsom Reservoir are not shown here X:\03355-00\08001\TECH\Memo\Memo tables 072009.doc 3
SMUD Energy Generation Tables Table 4A: Total SMUD Daily Energy Generation (MWh) for Critically Dry Year 1977-2 -2 October 2,205.08-87.53-47.59-44.47-32.38 November 2,382.40-47.18-34.55-23.56-17.96 December 2,217.67-34.89-26.78-17.44-13.42 January 2,417.00-34.81-26.77-17.40-13.39 February 788.38-38.31-28.73-18.54-14.55 March 677.18-34.85-31.69-17.38-13.39 April 741.55-35.89-24.09-17.32-13.33 May 832.38-67.23-49.96-33.58-25.84 June 3,031.69-114.55-86.87-56.73-42.64 July 2,978.36-137.79-103.42-68.97-52.00 August 2,730.76-139.16-104.38-69.61-52.26 September 2,221.80-106.57-80.57-53.29-39.68 Table 4B: Total SMUD Daily Energy Generation (MWh) for Dry Year 1992-2 -2 October 2,512.41-88.22-47.75-44.84-32.69 November 2,508.94-48.82-35.71-24.39-18.51 December 2,357.60-35.27-27.04-17.64-13.56 January 2,626.12-34.83-26.80-17.42-13.40 February 1,641.58-30.48-23.10-14.69-11.53 March 1,525.29-34.97-33.59-17.47-13.45 April 1,689.86-36.37-27.01-17.50-13.46 May 1,271.54-68.90-51.69-34.26-26.35 June 3,210.79-115.72-87.85-57.65-43.34 July 2,803.63-138.68-104.09-69.42-52.08 August 2,786.31-139.22-104.46-69.67-52.27 September 2,338.99-105.56-79.85-52.82-39.30 Table 4C: Total SMUD Daily Energy Generation (MWh) for Below Normal Year 1990-2 -2 October 4,315.36-54.40-24.07-27.62-20.08 November 2,529.48-48.62-35.75-24.35-18.50 December 2,343.24-35.29-27.05-17.64-13.56 January 3,253.37-34.93-26.87-17.47-13.44 February 1,190.51-38.46-29.21-18.62-14.61 March 1,737.29-35.23-33.77-17.58-13.54 April 1,955.36-36.43-27.08-17.57-13.51 May 1,437.11-67.71-50.77-33.83-26.02 June 3,446.57-88.69-65.92-42.78-31.61 July 2,837.05-138.01-103.62-69.11-51.85 August 2,902.38-139.31-104.53-69.72-52.30 September 2,873.12-107.69-81.61-54.27-40.59 X:\03355-00\08001\TECH\Memo\Memo tables 072009.doc 4
Table 4D: Total SMUD Daily Energy Generation (MWh) for Wet Year 1997-2 -2 October 5,197.75-31.75-21.52-17.51-12.68 November 3,348.60-36.61-26.20-17.77-13.53 December 6,845.23-10.20-7.90-5.35-4.25 January 11,566.78-4.84-3.72-2.42-1.89 February 9,706.11-6.05-4.59-9.59-2.30 March 6,894.12 11.46 11.79 4.99 3.58 April 3,609.13-11.83-9.01-5.80-4.54 May 2,862.16-9.15-6.71-4.37-3.35 June 4,407.58-28.26-21.15-13.74-10.20 July 3,322.65-138.47-103.96-69.34-52.02 August 3,876.39-135.25-100.30-65.30-48.17 September 6,435.70-33.31-24.16-15.37-11.01 PG&E Energy Generation Tables Table 5A: Total PG&E Daily Energy Generation (MWh) for Critically Dry Year 1977-2 -2 October 36.72-7.30-3.98-3.73-2.72 November 39.83-3.93-2.86-1.94-1.47 December 34.77-3.23-2.48-1.62-1.24 January 39.46-2.83-2.14-1.37-1.06 February 15.13-2.87-2.18-1.42-1.12 March 13.45-2.72-2.48-1.39-1.08 April 24.03-2.97-2.00-1.45-1.12 May 32.50-5.66-4.22-2.80-2.14 June 62.51-9.55-7.26-4.76-3.58 July 44.80-11.24-8.19-5.50-4.14 August 39.85-11.77-8.70-5.51-4.05 September 33.47-9.25-7.09-4.75-3.55 Table 5B: Total PG&E Daily Energy Generation (MWh) for Dry Year 1992-2 -2 October 44.50-7.53-4.02-3.81-2.80 November 50.50-4.05-2.97-2.04-1.55 December 40.93-2.79-2.14-1.40-1.08 January 42.85-2.77-2.13-1.39-1.07 February 65.37-2.77-2.10-1.34-1.05 March 63.34-2.99-2.87-1.50-1.15 April 76.58-3.04-2.26-1.47-1.13 May 50.27-5.87-4.42-2.95-2.27 June 55.09-9.67-7.39-4.88-3.67 July 52.19-11.35-8.59-5.78-4.35 August 42.41-11.49-8.30-5.47-4.12 September 38.73-8.95-6.63-4.28-3.12 X:\03355-00\08001\TECH\Memo\Memo tables 072009.doc 5
Table 5C: Total PG&E Daily Energy Generation (MWh) for Below Normal Year 1990-2 -2 October 83.50-5.80-2.88-2.96-2.17 November 58.52-4.13-3.04-2.07-1.57 December 44.84-2.86-2.20-1.44-1.11 January 58.52-2.90-2.24-1.45-1.12 February 36.51-3.23-2.46-1.58-1.24 March 75.45-2.96-2.84-1.48-1.14 April 95.46-3.05-2.27-1.47-1.13 May 70.85-5.73-4.30-2.87-2.21 June 89.50-9.49-7.19-4.68-3.51 July 55.15-11.49-8.69-5.84-4.40 August 45.81-11.32-8.31-5.59-4.21 September 48.46-8.85-6.61-4.29-3.20 Table 5D: Total PG&E Daily Energy Generation (MWh) for Wet Year 1997-2 -2 October 101.77-5.13-3.46-2.60-1.80 November 83.71-3.09-2.29-1.56-1.19 December 150.61-0.67-0.51-0.33-0.26 January 168.00 0.00 0.00 0.00 0.00 February 168.00 0.00 0.00 0.00 0.00 March 168.00 0.00 0.00 0.00 0.00 April 152.15-1.29-0.95-0.63-0.48 May 165.81-0.48-0.36-0.26-0.20 June 144.46-5.17-3.81-2.47-1.83 July 73.70-11.80-8.85-5.87-4.38 August 69.27-11.72-8.77-5.87-4.41 September 114.54-9.16-6.90-4.55-3.37 Total Reservoir Storage Tables Table 6.0A: Total Daily Reservoir Storage (Acre-feet) for Critically Dry Year 1977-2 -2 October 168,093.60-534.04-172.18-228.79-179.10 November 148,963.85-136.79-78.52-44.91-52.19 December 129,714.50-103.67-57.76-28.40-39.87 January 111,576.06-103.16-57.44-28.14-39.68 February 101,643.16-114.75-64.03-31.97-43.51 March 102,334.76-103.54-72.39-28.28-39.81 April 111,084.52-106.99-49.81-28.18-39.68 May 128,191.14-204.22-126.40-78.14-78.07 June 137,670.31-341.67-223.61-146.54-127.49 July 114,142.50-410.40-272.57-182.16-160.80 August 86,969.77-412.58-274.38-183.36-173.87 September 63,163.15-312.87-202.59-133.66-135.00 X:\03355-00\08001\TECH\Memo\Memo tables 072009.doc 6
Table 6.1A: Loon Lake Daily Reservoir Storage (Acre-feet) for Critically Dry Year 1977-2 -2 October 28,191.00 0.00 0.00 0.00 0.00 November 24,649.75 0.00 0.00 0.00 0.00 December 20,522.88 0.00 0.00 0.00 0.00 January 14,862.08 0.00 0.00 0.00 0.00 February 11,308.38 0.00 0.00 0.00 0.00 March 11,447.55 0.00 0.00 0.00 0.00 April 14,688.86 0.00 0.00 0.00 0.00 May 21,701.51 0.00 0.68 0.00 0.00 June 28,049.46 0.00 0.00 0.00 0.00 July 19,545.51 0.00 0.00 0.00 0.00 August 9,960.77 0.00 0.00 0.00 0.00 September 5,221.10 0.00 0.00 0.00 0.00 Table 6.2A: Union Valley Daily Reservoir Storage (Acre-feet) for Critically Dry Year 1977-2 -2 October 95,764.28-0.01 21.58 23.46-0.01 November 80,768.06-0.01 21.55 23.44-0.01 December 66,707.83-0.01 21.55 23.43-0.01 January 55,354.84-0.01 21.55 23.43-0.01 February 50,358.02-0.01 21.55 23.43-0.01 March 51,600.26-0.01 21.54 23.42-0.01 April 56,249.62-0.01 21.51 23.39-0.01 May 64,136.97-0.01 25.13 23.33-0.01 June 65,099.08-0.01 35.52 23.24-0.01 July 51,267.83-0.01 35.32 23.10-6.86 August 34,981.25-0.01 35.04 22.92-19.17 September 18,345.51-0.01 33.94 22.77-18.65 Table 6.3A: Ice House Daily Reservoir Storage (Acre-feet) for Critically Dry Year 1977-2 -2 October 29,892.37 0.00 0.35 0.00 0.00 November 29,170.60 0.00 0.35 0.00 0.00 December 28,210.62 0.00 0.35 0.00 0.00 January 27,014.39 0.00 0.35 0.00 0.00 February 26,063.74 0.00 0.35 0.00 0.00 March 25,405.48 0.00 0.35 0.00 0.00 April 26,203.25 0.00 0.35 0.00 0.00 May 28,308.02 0.00 0.39 0.00 0.00 June 29,857.63 0.00 0.02 0.00 0.00 July 28,907.79 0.00 0.00 0.00 0.01 August 27,639.75 0.00 0.00 0.00 0.02 September 25,326.91 0.00 0.03 0.00 0.01 X:\03355-00\08001\TECH\Memo\Memo tables 072009.doc 7
Table 6.4A: Camino Daily Reservoir Storage (Acre-feet) for Critically Dry Year 1977-2 -2 October 298.98 0.00 0.00 0.00 0.00 November 298.98 0.00 0.00 0.00 0.00 December 298.98 0.00 0.00 0.00 0.00 January 298.98 0.00 0.00 0.00 0.00 February 298.98 0.00 0.00 0.00 0.00 March 298.98 0.00 0.00 0.00 0.00 April 298.98 0.00 0.00 0.00 0.00 May 298.98 0.00 0.00 0.00 0.00 June 298.98 0.00 0.00 0.00 0.00 July 298.98 0.00 0.00 0.00 0.00 August 298.98 0.00 0.00 0.00 0.00 September 298.98 0.00 0.00 0.00 0.00 Table 6.5A: Slab Creek Daily Reservoir Storage (Acre-feet) for Critically Dry Year 1977-2 -2 October 12,336.64-489.85-182.02-232.75-165.49 November 12,436.46-136.78-100.43-68.35-52.17 December 12,334.20-103.65-79.66-51.83-39.86 January 12,405.77-103.14-79.34-51.57-39.67 February 11,974.04-114.62-85.93-55.40-43.49 March 11,942.49-103.52-94.28-51.70-39.80 April 12,003.81-106.98-71.67-51.57-39.67 May 12,105.66-204.20-152.61-101.48-78.06 June 12,725.16-341.65-259.14-169.79-127.47 July 12,482.39-410.39-307.89-205.26-153.94 August 12,449.02-412.56-309.42-206.28-154.71 September 12,330.65-312.86-236.56-156.43-116.36 Table 6.6A: Chili Bar Daily Reservoir Storage (Acre-feet) for Critically Dry Year 1977-2 -2 October 1,610.33-44.17-12.09-19.51-13.59 November 1,640.00 0.00 0.00 0.00 0.00 December 1,640.00 0.00 0.00 0.00 0.00 January 1,640.00 0.00 0.00 0.00 0.00 February 1,640.00-0.12 0.00 0.00 0.00 March 1,640.00 0.00 0.00 0.00 0.00 April 1,640.00 0.00 0.00 0.00 0.00 May 1,640.00 0.00 0.00 0.00 0.00 June 1,640.00 0.00 0.00 0.00 0.00 July 1,640.00 0.00 0.00 0.00 0.00 August 1,640.00 0.00 0.00 0.00 0.00 September 1,640.00 0.00 0.00 0.00 0.00 X:\03355-00\08001\TECH\Memo\Memo tables 072009.doc 8
Table 6.0B: Total Average Daily Reservoir Storage (Acre-feet) for Dry Water Year 1992-2 -2 October 228,395.65-195.60-527.66-183.05-255.53 November 212,886.82-102.35-139.57-53.13-69.74 December 197,976.30-79.98-104.17-40.06-52.08 January 181,588.23-79.34-103.14-39.67-51.57 February 175,859.96-78.84-103.17-39.00-49.70 March 200,986.80-98.57-103.31-39.70-51.59 April 242,693.77-83.73-111.81-40.33-52.43 May 278,898.13-159.86-211.94-78.70-102.31 June 271,257.02-278.92-362.16-143.91-187.02 July 245,850.36-329.84-432.66-172.20-223.64 August 217,954.40-329.29-431.98-171.86-223.24 September 193,487.85-255.63-331.27-133.08-172.88 Table 6.1B: Loon Lake Average Daily Reservoir Storage (Acre-feet) for Dry Year 1992-2 -2 October 38,600.59 0.00 0.00 0.00 0.00 November 37,739.11 0.00 0.00 0.00 0.00 December 36,351.63 0.00 0.00 0.00 0.00 January 28,405.97 0.00 0.00 0.00 0.00 February 23,236.99 0.00 0.00 0.00 0.00 March 27,583.61 0.00 0.00 0.00 0.00 April 36,845.91-0.11-0.11 0.00 0.00 May 47,885.04 0.00 0.00 0.00 0.00 June 43,978.40 0.00 0.00 0.00 0.00 July 39,592.57 0.00 0.00 0.00 0.00 August 36,029.44 0.00 0.00 0.00 0.00 September 30,484.54 0.00 0.00 0.00 0.00 Table 6.2B: Union Valley Average Daily Reservoir Storage (Acre-feet) for Dry Year 1992-2 -2 October 144,497.15 0.00 0.00 0.00 0.00 November 130,106.02 0.00 0.00 0.00 0.00 December 118,490.23 0.00 0.00 0.00 0.00 January 111,547.91 0.00 0.00 0.00 0.00 February 111,486.04 0.00 0.00 0.00 0.00 March 130,640.08 0.00 0.00 0.00 0.00 April 158,264.87-2.96-2.96 0.00 0.00 May 179,703.57-3.34-3.34 0.00 0.00 June 175,998.91-17.05-17.05-13.72-13.72 July 155,971.30-20.43-20.43-17.12-17.12 August 132,935.97-20.33-20.33-17.04-17.04 September 115,769.59-20.81-20.81-17.53-17.53 X:\03355-00\08001\TECH\Memo\Memo tables 072009.doc 9
Table 6.3B: Ice House Average Daily Reservoir Storage (Acre-feet) for Dry Year 1992-2 -2 October 30,896.90 0.00 0.00 0.00 0.00 November 30,497.27 0.00 0.00 0.00 0.00 December 28,760.09 0.00 0.00 0.00 0.00 January 27,253.70 0.00 0.00 0.00 0.00 February 26,615.28 0.00 0.00 0.00 0.00 March 28,264.52 0.00 0.00 0.00 0.00 April 32,935.80-0.05-0.05 0.00 0.00 May 37,048.85 0.00 0.00 0.00 0.00 June 36,739.53-0.60-0.60-0.60-0.60 July 35,792.12-0.75-0.75-0.75-0.75 August 34,581.84-0.75-0.75-0.75-0.75 September 32,866.94-0.17-0.17-0.17-0.17 Table 6.4B: Camino Average Daily Reservoir Storage (Acre-feet) for Dry Year 1992-2 -2 October 298.98 0.00 0.00 0.00 0.00 November 298.98 0.00 0.00 0.00 0.00 December 298.98 0.00 0.00 0.00 0.00 January 298.98 0.00 0.00 0.00 0.00 February 298.98 0.00 0.00 0.00 0.00 March 298.98 0.00 0.00 0.00 0.00 April 298.98 0.00 0.00 0.00 0.00 May 298.98 0.00 0.00 0.00 0.00 June 298.98 0.00 0.00 0.00 0.00 July 298.98 0.00 0.00 0.00 0.00 August 298.98 0.00 0.00 0.00 0.00 September 298.98 0.00 0.00 0.00 0.00 Table 6.5B: Slab Creek Average Daily Reservoir Storage (Acre-feet) for Dry Year 1992-2 -2 October 12,492.16-185.39-485.65-166.27-233.97 November 12,605.44-102.34-139.57-53.13-69.74 December 12,435.37-79.98-104.16-40.05-52.08 January 12,441.68-79.34-103.14-39.67-51.57 February 12,565.12-74.40-97.32-36.79-46.87 March 12,559.61-98.57-103.30-39.70-51.59 April 12,708.21-80.62-108.69-40.33-52.43 May 12,321.69-156.52-208.60-78.70-102.31 June 12,601.20-261.27-344.51-129.59-172.69 July 12,555.39-308.65-411.47-154.33-205.77 August 12,468.16-308.21-410.90-154.07-205.45 September 12,427.80-234.64-310.28-115.37-155.17 X:\03355-00\08001\TECH\Memo\Memo tables 072009.doc 10
Table 6.6B: Chili Bar Average Daily Reservoir Storage (Acre-feet) for Dry Year 1992-2 -2 October 1,609.86-10.21-42.02-16.78-21.56 November 1,640.00 0.00 0.00 0.00 0.00 December 1,640.00 0.00 0.00 0.00 0.00 January 1,640.00 0.00 0.00 0.00 0.00 February 1,657.56-4.44-5.84-2.21-2.82 March 1,640.00 0.00 0.00 0.00 0.00 April 1,640.00 0.00 0.00 0.00 0.00 May 1,640.00 0.00 0.00 0.00 0.00 June 1,640.00 0.00 0.00 0.00 0.00 July 1,640.00 0.00 0.00 0.00 0.00 August 1,640.00 0.00 0.00 0.00 0.00 September 1,640.00 0.00 0.00 0.00 0.00 Table 6.0C: Total Daily Reservoir Storage (Acre-feet) for Below Normal Water Year 1990-2 -2 October 233,893.30-382.11-128.62-190.35-136.46 November 217,975.83-139.20-102.34-69.65-53.08 December 204,565.03-104.16-79.98-52.08-40.05 January 196,238.00-103.14-79.34-51.57-39.67 February 194,804.28-114.62-86.99-55.40-43.49 March 210,402.70-103.52-99.39-51.70-39.80 April 258,062.93-106.98-79.38-51.57-39.67 May 304,755.64-206.08-155.02-103.36-79.94 June 327,797.77-280.65-209.16-138.42-104.16 July 308,130.76-417.66-315.16-212.53-161.22 August 280,663.00-419.80-316.66-213.52-161.95 September 255,526.15-318.87-242.57-162.44-122.37 Table 6.1C: Loon Lake Average Daily Reservoir Storage (Acre-feet) for Below Normal Water Year 1990-2 -2 October 39,644.93 0.00 0.00 0.00 0.00 November 37,938.20 0.00 0.00 0.00 0.00 December 37,388.51 0.00 0.00 0.00 0.00 January 27,334.49 0.00 0.00 0.00 0.00 February 17,096.38 0.00 0.00 0.00 0.00 March 18,694.82 0.00 0.00 0.00 0.00 April 29,679.03 0.00 0.00 0.00 0.00 May 43,125.81-0.38-0.38-0.38-0.38 June 54,101.08-0.20-0.20-0.20-0.20 July 52,511.21 0.00 0.00 0.00 0.00 August 48,434.33 0.00 0.00 0.00 0.00 September 42,862.56 0.00 0.00 0.00 0.00 X:\03355-00\08001\TECH\Memo\Memo tables 072009.doc 11
Table 6.2C: Union Valley Average Daily Reservoir Storage (Acre-feet) for Below Normal Water Year 1990-2 -2 October 148,711.59 0.00 0.00 0.00 0.00 November 134,670.17 0.00 0.00 0.00 0.00 December 123,866.35 0.00 0.00 0.00 0.00 January 126,353.95 0.00 0.00 0.00 0.00 February 135,765.51 0.00 0.00 0.00 0.00 March 148,568.23 0.00 0.00 0.00 0.00 April 181,161.90 0.00 0.00 0.00 0.00 May 210,417.88-1.38-1.38-1.38-1.38 June 217,853.62-6.62-6.62-6.62-6.62 July 200,092.13-6.81-6.81-6.81-6.81 August 179,090.30-7.06-7.06-7.06-7.06 September 164,510.58-5.77-5.77-5.77-5.77 Table 6.3C: Ice House Average Daily Reservoir Storage (Acre-feet) for Below Normal Water Year 1990-2 -2 October 30,846.63 0.00 0.00 0.00 0.00 November 30,746.15 0.00 0.00 0.00 0.00 December 28,886.55 0.00 0.00 0.00 0.00 January 27,963.47 0.00 0.00 0.00 0.00 February 27,766.48 0.00 0.00 0.00 0.00 March 28,472.03 0.00 0.00 0.00 0.00 April 32,239.29 0.00 0.00 0.00 0.00 May 36,632.51-0.12-0.12-0.12-0.12 June 40,839.97-0.46-0.46-0.46-0.46 July 40,991.50-0.46-0.46-0.46-0.46 August 38,680.24-0.18-0.18-0.18-0.18 September 33,621.47 0.00 0.00 0.00 0.00 Table 6.4C: Camino Average Daily Reservoir Storage (Acre-feet) for Below Normal Water Year 1990-2 -2 October 341.43 0.00 0.00 0.00 0.00 November 298.98 0.00 0.00 0.00 0.00 December 298.98 0.00 0.00 0.00 0.00 January 298.98 0.00 0.00 0.00 0.00 February 298.98 0.00 0.00 0.00 0.00 March 298.98 0.00 0.00 0.00 0.00 April 298.98 0.00 0.00 0.00 0.00 May 298.98 0.00 0.00 0.00 0.00 June 298.98 0.00 0.00 0.00 0.00 July 298.98 0.00 0.00 0.00 0.00 August 298.98 0.00 0.00 0.00 0.00 September 298.98 0.00 0.00 0.00 0.00 X:\03355-00\08001\TECH\Memo\Memo tables 072009.doc 12
Table 6.5C: Slab Creek Average Daily Reservoir Storage (Acre-feet) for Below Normal Water Year 1990-2 -2 October 12,756.52-354.16-119.91-173.54-122.78 November 12,682.32-139.20-102.34-69.65-53.08 December 12,484.64-104.16-79.98-52.08-40.05 January 12,647.11-103.14-79.34-51.57-39.67 February 12,236.93-114.62-86.99-55.40-43.49 March 12,728.64-103.52-99.39-51.70-39.80 April 13,043.73-106.98-79.38-51.57-39.67 May 12,640.46-204.20-153.14-101.48-78.06 June 13,064.12-273.37-201.88-131.14-96.88 July 12,596.94-410.39-307.89-205.26-153.94 August 12,519.15-412.56-309.42-206.28-154.71 September 12,592.57-313.10-236.80-156.67-116.60 Table 6.6C: Chili Bar Average Daily Reservoir Storage (Acre-feet) for Below Normal Water Year 1990-2 -2 October 1,592.20-27.94-8.71-16.81-13.68 November 1,640.00 0.00 0.00 0.00 0.00 December 1,640.00 0.00 0.00 0.00 0.00 January 1,640.00 0.00 0.00 0.00 0.00 February 1,640.00 0.00 0.00 0.00 0.00 March 1,640.00 0.00 0.00 0.00 0.00 April 1,640.00 0.00 0.00 0.00 0.00 May 1,640.00 0.00 0.00 0.00 0.00 June 1,640.00 0.00 0.00 0.00 0.00 July 1,640.00 0.00 0.00 0.00 0.00 August 1,640.00 0.00 0.00 0.00 0.00 September 1,640.00 0.00 0.00 0.00 0.00 Table 6.0D: Total Daily Reservoir Storage (Acre-feet) for Wet Water Year 1997-2 -2 October 240,282.13-199.41-107.80-79.09-47.19 November 221,078.62-104.26-78.87-53.45-40.74 December 260,201.94-24.24-18.15-11.23-8.26 January 324,193.44-4.23-3.24-1.56-1.28 February 284,898.16-6.82-5.17-6.30-2.59 March 247,917.52-86.96-86.97-39.50-29.09 April 276,160.61-40.05-29.11-19.15-14.41 May 352,181.04-44.18-31.71-19.95-15.25 June 390,606.74-109.48-82.01-53.53-39.81 July 378,485.29-410.35-307.86-205.24-153.93 August 346,044.81-398.35-295.21-192.07-141.68 September 301,486.02-93.20-67.56-42.88-30.92 X:\03355-00\08001\TECH\Memo\Memo tables 072009.doc 13
Table 6.1D: Loon Lake Average Daily Reservoir Storage (Acre-feet) for Wet Water Year 1997-2 -2 October 40,758.14 0.00 0.00 0.00 0.00 November 37,644.85 0.00 0.00 0.00 0.00 December 39,826.44 0.00 0.00 0.00 0.00 January 46,379.81 0.00 0.00 0.00 0.00 February 26,234.39 0.00 0.00 0.00 0.00 March 20,811.98 0.00 0.00 0.00 0.00 April 30,722.37 0.00 0.00 0.00 0.00 May 53,913.27 0.00 0.00 0.00 0.00 June 66,930.54 0.00 0.00 0.00 0.00 July 66,029.82 0.00 0.00 0.00 0.00 August 57,732.12 0.00 0.00 0.00 0.00 September 51,141.47 0.00 0.00-0.01 0.00 Table 6.2D: Union Valley Average Daily Reservoir Storage (Acre-feet) for Wet Water Year 1997-2 -2 October 153,595.46 0.00 0.00 0.00 0.00 November 138,166.70 0.00 0.00 0.00 0.00 December 175,308.93 0.00 0.00 0.00 0.00 January 228,578.97 0.00 0.00 0.00 0.00 February 218,442.18 0.00 0.00 0.00 0.00 March 192,720.51 0.00 0.00 0.00 0.00 April 206,036.77 0.00 0.00 0.00 0.00 May 246,859.76 0.00 0.00 0.00 0.00 June 265,502.42 0.00 0.00 0.00 0.00 July 254,670.49 0.00 0.00 0.00 0.00 August 233,747.96 0.00 0.00 0.00 0.00 September 200,719.85 0.00 0.00 0.00 0.00 Table 6.3D: Ice House Average Daily Reservoir Storage (Acre-feet) for Wet Water Year 1997-2 -2 October 30,979.25 0.00 0.00 0.00 0.00 November 30,422.45 0.00 0.00 0.00 0.00 December 29,114.86 0.00 0.00 0.00 0.00 January 32,061.81 0.00 0.00 0.00 0.00 February 23,839.74 0.00 0.00 0.00 0.00 March 18,466.31 0.00 0.00 0.00 0.00 April 23,857.80 0.00 0.00 0.00 0.00 May 35,575.10 0.00 0.00 0.00 0.00 June 42,747.83 0.00 0.00 0.00 0.00 July 42,965.21 0.00 0.00 0.00 0.00 August 39,736.29 0.00 0.00 0.00 0.00 September 34,350.78 0.00 0.00 0.00 0.00 X:\03355-00\08001\TECH\Memo\Memo tables 072009.doc 14