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Home My WebLink About20170918Attachment 103A - SRA Summary Report.pdfSpokane River System Hydro Assessment Summary Report November 2012 Prepared by: Under Contract: R-36760 Staff_PR_103 Attachment A Page 1 of 17 SRA Summary Report Table of Contents Table of Contents Acronym List .............................................................................................................................. 2 Executive Summary ................................................................................................................... 3 1 Background ........................................................................................................................ 5 2 Evaluation .......................................................................................................................... 5 Phase I ................................................................................................................................... 5 Phase II .................................................................................................................................. 6 Phase III ................................................................................................................................. 6 Risk Evaluation ...................................................................................................................... 7 3 Results/Recommendation .................................................................................................. 8 4 Recommended Alternative 5 Description ...........................................................................10 5 Future Upgrade Decisions .................................................................................................11 Appendix A: Scoring Matrix ......................................................................................................13 Appendix B: Risk Evaluation ....................................................................................................14 Staff_PR_103 Attachment A Page 2 of 17 November 2012 SRA Summary Report Page 2 Acronym List FERC Federal Energy Regulatory Commission HED Hydroelectric Development HMI Hydro Modernization Initiative IRP Integrated Resource Plan MW Megawatt REC Renewable Energy Credit RPS Renewable Portfolio Standard SRA Spokane River Assessment Staff_PR_103 Attachment A Page 3 of 17 November 2012 SRA Summary Report Page 3 Executive Summary In 2011, plans to address ongoing maintenance and operational issues at the Nine Mile Hydroelectric Development (HED) by replacing the Units 1 and 2 turbines were complicated by unexpected failures of the newer vintage turbine in Unit 4. This prompted Avista to initiate a review of the Nine Mile HED to determine the best course of action. Encouraged by initial economic findings at Nine Mile, Avista staff also decided it was prudent to conduct a broader assessment of the entire Spokane River Project1 to determine if upgrading Nine Mile was the best Spokane River investment or if other Spokane River upgrades could provide comparable or better value to Avista’s stakeholders. This broader evaluation led to the Spokane River Assessment (SRA). The SRA evaluated current conditions of the Spokane River Project and potential improvements. The SRA was performed in three phases by a cross functional Project Team. A phased approach was selected, which provide multiple opportunities to assess and report on project progress and direction to a cross functional Policy Team. The Project Team relied upon smaller specialized groups, called Task Groups, to provide more detailed evaluations (i.e. financial, operation and maintenance, safety, and regulatory/permitting considerations). In Phase I, the team developed a SRA framework, which included establishing the cross-functional Project Team, identifying goals and criteria, identifying the upgrade alternatives for the Spokane River plants, and developing the tools necessary to research, quantify, and evaluate the various upgrade alternatives. In Phase II, the team developed reconnaissance level engineering evaluations to determine estimates of potential power generation and associated construction costs. The information from these studies was evaluated by the Financial Task Group to determine if a supportive business case could be made for any of the upgrade alternatives. During the development of the engineering evaluations, three factors changed which led the Financial Task Group and the Project Team to determine not to continue to evaluate any upgrade alternatives with the exception of Nine Mile. These factors were: 1. Significant declines in natural gas prices, 2. A stalled federal carbon cap and trade program (carbon tax), and 3. Passage of a Washington State biomass bill that qualifies Avista's Kettle Falls Project for renewable energy credit (REC) and satisfies Avista’s foreseeable need for additional RECs to meet its Washington State renewable portfolio standard (RPS) requirements. These factors should be periodically monitored and, if significant changes are noted, the potential upgrade alternatives that were "mothballed" should be reassessed. Avista renews its integrated resource plan (IRP) every two years. These factors are considered in that process. In between IRP cycles, should any of these factors significantly change; a simple algorithm relying upon these four factors can be used to determine whether an update of the SRA is warranted. Following the evaluation of potential alternatives, the SRA Project Team determined the only plant that warranted further evaluation was the Nine Mile HED due to its chronic maintenance and operational issues. These issues are primarily a result of aging equipment, reservoir sedimentation, and damage to submerged equipment from the sediment. The team further concluded that long-term regulatory and 1 Includes Post Falls, Upper Falls, Monroe Street, Nine Mile, and Long Lake Hydroelectric Developments. Staff_PR_103 Attachment A Page 4 of 17 November 2012 SRA Summary Report Page 4 license concerns could result from continued operation without addressing the existing equipment, technology, and sediment management challenges. In Phase III, the Project Team evaluated five alternatives at Nine Mile HED. Four of the alternatives would replace the existing powerhouse with a new, higher capacity powerhouse. The fifth alternative would consist of both an upgrade and a rehabilitation of the existing plant. The Project Team conducted a structured evaluation process to evaluate the alternatives at Nine Mile. One tool employed by the team was an evaluation matrix which considered specific criteria tailored to the Nine Mile site. The matrix provides a common set of key metrics to evaluate the financial, operation and maintenance, environmental and permitting, and safety aspects of each alternative. As a result of the evaluation, the Project Team determined the highest ranked option was Alternative 5, which was the previously planned upgrade of Units 1 and 2 coupled with rehabilitation of Units 3 and 4. The Project Team also strongly recommends that Alternative 5 include modeling the project's sediment bypass system to identify modifications to improve the system's reliability and efficiency. These considerations are necessary because the system has not performed up to its potential and because hydraulic conditions in the forebay will be changed by adding higher capacity turbines in Units 1 and 2. The financial value of Alternative 5 was $68M better than the highest-ranked and lowest-cost New Powerhouse Alternative (Alternative 4). Based on the evaluation matrix, the Project Team agreed that Alternative 4 (built in the footprint of the existing powerhouse structure) ranked the highest of the new powerhouse alternatives. Staff_PR_103 Attachment A Page 5 of 17 November 2012 SRA Summary Report Page 5 1 Background In early 2011, the turbine upgrade project for Units 1 and 2 at the Nine Mile Hydroelectric Development (HED) was well into the design procurement stage. However, in April of 2011, the same time as an equipment supply contract was to be executed, the Nine Mile Unit 4 turbine (installed in 1994) experienced a propagating fatigue failure of several of its runner blades, creating a significant forced outage for this unit. The failure of Unit 4 raised new concerns over investing in excess of $40 million in a 104-year-old facility with significant ongoing operation and maintenance issues. As a result, the Unit 1 and 2 Upgrade Project was put on hold and other options for upgrading the Nine Mile facility were developed and evaluated. This preliminary evaluation found that the best option from a net present value perspective would be construction of a new 3-unit, 60 megawatt (MW) powerhouse just downstream of the existing powerhouse. The assessment level cost of the new powerhouse was estimated to be roughly $125 million. Given the considerable cost and the apparent economic feasibility of expanded work at Nine Mile, Avista staff decided it was prudent to conduct a broader assessment of the entire Spokane River Project to determine if upgrading Nine Mile was the best use of capital, or if perhaps other developments within the Spokane River Project2 could be upgraded to provide better value to Avista’s stakeholders. This led to the Spokane River Assessment (SRA). In October 2011, Avista launched the Corporate Strategic Refresh to identify measures to support the corporate strategic plan. The evaluation led to a number of corporate-wide initiatives. As a result, the Hydro Modernization Initiative (HMI) was developed to support responsible stewardship of Avista's existing hydro generation assets. The purpose of the HMI was to develop a long-term strategy to assess and prioritize hydroelectric plant improvement opportunities3 . To support the HMI, the SRA evaluated current conditions of the Spokane River Project and potential improvements. The information was used to help prioritize the implementation of these improvements. The prioritization took into account multiple projects, corporate goals, and criteria. The SRA was conducted in three phases by an interdepartmental Project Team. Phase I established the framework of the SRA, including establishment of , identification of goals and criteria, and development of the tools necessary to research, quantify, and evaluate the various upgrade alternatives during Phases II and III. This SRA Summary Report was developed to communicate the results. 2 Evaluation Phase I During Phase I, the framework of the SRA was developed, including establishment of a Project Team, identification of goals and criteria, and development of the tools necessary to research, quantify, and evaluate the various upgrade scenarios. These tools and documents include: 2 Includes the Post Falls, Upper Falls, Monroe Street, Nine Mile, and Long Lake HEDs. 3 The HMI goals are: generate incremental energy to meet load growth, produce RECs to meet Renewable portfolio standards, increase plant efficiency through utilization of new technology, and reduce risk through improved reliability and environmental mitigation. Staff_PR_103 Attachment A Page 6 of 17 November 2012 SRA Summary Report Page 6 • Proposed Upgrade Alternatives • Project Goals and Evaluation Criteria • Evaluation Matrix • Evaluation Matrix-Baseline Conditions • SRA Risk Register Template Following development and approval by the Project Team, the tools and documents were presented to the Policy Team for approval. The Policy Team concurred and Phase I was completed. Phase II During Phase II of the SRA, the majority of the effort was focused on developing reconnaissance level engineering evaluations to estimate the potential for increased energy generation as well as the corresponding construction cost for the alternatives proposed for each of the plants. A preliminary financial evaluation was developed early in Phase II that indicated at least three new powerhouse alternatives4 looked feasible from a financial standpoint. Later in Phase II, a more extensive financial evaluation was performed by the Financial Task Group using updated information and methodology developed by the Power Supply Department. During the time between the first evaluation and this new evaluation, three factors changed, which led to significantly different results: 1. Significant declines in natural gas prices, 2. A stalled federal carbon cap and trade program (carbon tax), and 3. Passage of a Washington State biomass bill that qualifies Avista's Kettle Falls facility for Renewable Energy Credits (RECs), to meet Washington State's renewable portfolio standard (RPS) requirements. Following the Financial Task Group evaluation of all the proposed alternatives, the business case for the upgrades of the Spokane River plants became marginal compared to other power resource options. In spite of the economics, the current poor plant conditions at Nine Mile warranted further evaluation of upgrade and rehabilitation alternatives in Phase III of the SRA. The Project Team decided not to continue to evaluate any of the other plants and to document the results of the engineering and financial evaluations in the final SRA report. If the three factors noted above become sufficiently reversed, the alternatives that had the most potential will have already been identified and can be further evaluated. Phase III During Phase III, four alternatives were considered for Nine Mile5 4 These initial calculations suggested a new 60 MW powerhouse at Nine Mile (Alternative 4), a new 80 MW second powerhouse at Monroe St (Alternative 2), and a new 68 MW powerhouse at Long Lake (Alternative 2) had the most potential to be further considered. ; three involved construction of a new powerhouse and one consisted of rehabilitating the existing plant. The rehabilitation alternative was initially examined in two configurations (5a and 5b). The 5a configuration proceeds with just the planned Unit 1 and 2 upgrade. The 5b configuration also proceeds with the Unit 1 and 2 upgrade but expands to address Units 3 and 4, modify the sediment bypass system, and rehabilitate the 5 An additional alternative, Alternative 2, was removed from consideration during Phase II of the evaluation. Staff_PR_103 Attachment A Page 7 of 17 November 2012 SRA Summary Report Page 7 powerhouse building. In the process of evaluating these configurations, the Project Team determined that 5a was not acceptable because it did not resolve serious ongoing plant condition and sediment issues. The team decided that the scope of Alternative 5 needs to include the broader 5b configuration. Alternative Description New Powerhouse Alternative 1 3 Units, 60 MW Downstream Left Bank Alternative 3 5 Units, 60 MW Downstream Left Bank Alternative 4 5 Units, 60 MW Existing Location Rehab Alternative 5 Replace Units 1 and 2, rehab Units 3 and 4, and modify the Sediment Bypass System The Project Team evaluated the potential upgrade alternatives proposed for Nine Mile using the evaluation matrix to score the four criteria established in Phase I. The team developed a scoring system for each criteria based on a five point Likert scale. The Project Team evaluated each alternative against the criteria and assigned a score (Appendix A). The team also decided to provide relative weights for the criteria so a weighted average could be developed for each alternative and the final score would better reflect the importance of the criteria. The criteria and their assigned weighting are below: Criteria Weighting Risk Evaluation A qualitative risk assessment was performed to evaluate risks associated with Alternative 4 and Alternative 5, the two top scoring alternatives (Appendix B). A significant risk associated with both Alternative 4 and Alternative 5 was the volatility of the energy market. Given the current historically low prices for natural gas, the cost of the additional power generated from a new, higher capacity hydro powerhouse is much higher than the gas turbine alternative. If (or when) gas prices and power market prices increase in the future, new powerhouse alternatives may in hindsight have been a better option. Similarly, if a carbon tax is imposed or more RECs are required in the future, the value of hydro power may be higher. A sensitivity analysis was performed to determine the percentage increase in REC and power values that would be necessary to change the outcome of cost analyses. The analysis determined that the change would have to be significant. A major risk for Alternative 4 is the ability to acquire the required Major Modified License from the Federal Energy Regulatory Commission (FERC) in a feasible timeframe. For Alternative 5, the project team determined that sediment is a critical issue that has caused significant damage to equipment in the past. If a functional solution for dealing with the sediment is not identified and constructed, the lifespan of submerged mechanical equipment will be substantially shortened, resulting in a need for more frequent major investments. Staff_PR_103 Attachment A Page 8 of 17 November 2012 SRA Summary Report Page 8 3 Results/Recommendation The final weighted average scores6 for each alternative were: Based on the four criteria used by the Project Team to evaluate the Nine Mile Alternatives, Alternative 5 received the best score primarily due to project economics and likelihood of regulatory agency approval. Permitting for the previously considered Unit 1 and 2 upgrade has already been completed and required water rights have been obtained. Consequently, only minor permit modifications are necessary for Alternative 5. Detailed scores can be found in Appendix A, the Final Scoring Matrix: a graphical representation of the scores is included in Figure 1. Results of the financial analysis are summarized in the following table. Alt 1 Alt 3 Alt 4 Alt 5 Value ($000) Compared to 2013 Estimated Revenue Of the new powerhouse alternatives, Alternative 4 received the highest score, primarily due to its more compact footprint. Building a new powerhouse downstream (Alternatives 1 and 3) would require extensive excavation and likely be more difficult to move through the regulatory and permitting process. Acquiring the additional water rights for each of the new powerhouse alternatives would also be challenging. 6 The scores were determined on a five point scale, with one being the worst and five being the best. Staff_PR_103 Attachment A Page 9 of 17 November 2012 SRA Summary Report Page 9 Figure 1. Results of the Nine Mile Alternative Evaluation WORSELess Likely BETTERMore Likely Identify the options with the best customer value Relationships with key stakeholders - NGOs Assess time required to move through regulatory process 1 3 42 5NE U T R A L Opportunities to improve hydro public safety Opportunities to improve dam safety Improve overall plant reliability Ensure the design is flexible enough to meet current and anticipated criteria Relationships with key stakeholders - Agencies Assess likelihood of regulatory approval Staff_PR_103 Attachment A Page 10 of 17 November 2012 SRA Summary Report Page 10 4 Recommended Alternative 5 Description Unit 1 and 2 Upgrade to Seagull turbines:7 • Turbines • Bulkheads • Hydraulic governors • Generators • Static excitation system • 13.8 kV switchgear • Station service • Control and protection package • Powerhouse ventilation upgrade • Rehab intake gates and trash rack • GSU in substation • Communications upgrade (Westside-Nine Mile) • Yard grounding • Cottage 3 demolition • Warehouse construction • Cottage 6 rehabilitation Unit 3 and 4 overhaul: • New runners – overhaul Quadrunners • New thrust bearings • Hydraulic governors • Control and protection package • Switchgear • Static excitation system • Rehab intake gates and trash rack Plant Rehab: • Sediment bypass rehab • Debris handling system • Rehab powerhouse building At the time of this report, the Project Team was assuming that Unit 3 would undergo an overhaul similar to Unit 4 rather than a full turbine replacement like the Units 1 and 2 Seagull turbines. However, the Project Team suggests reaffirming this assumption for Unit 3 based on the actual performance of the new Seagull units, the overhauled Unit 4, and the modified sediment bypass system. This approach is reflected in the timing of the implementation of the proposed alternative. Sediment management improvements are a critical aspect of this project. Most hydroelectric turbines have a useful life of more than 50 years, but that has not been the case at Nine Mile. Newer vintage turbines at Nine Mile showed severe wear and failed after just 15 years. This wear is attributed to the course sandy sediment that has filled the Nine Mile reservoir. 7 This scope is consistent with the previously approved Unit 1 and 2 Upgrade Staff_PR_103 Attachment A Page 11 of 17 November 2012 SRA Summary Report Page 11 The source of the sediment is Hangman Creek, which was extensively modified by road construction in the middle of the 20th century. The modifications reduced the cost of bridge building by cutting off stream meanders, a practice that increases stream velocity and changes stream flow dynamics. These modifications involve many miles of stream in a basin composed of highly erosive soils. Stabilization will not be a simple or inexpensive process. Consequently, Nine Mile must address sediment management as a given for future project operation. Improved sediment management at Nine Mile will require evaluation of the existing sediment bypass system and turbine entrainment patterns, especially with new, higher capacity Seagull units. The Project Team proposed the following timeline for implementing the preferred Nine Mile alternative: 2012 2013 2014 2015 2016 2017 2018 2019 2020 Upgrade Units 1,2 to Seagull Turbines New Runners - Overhaul Unit 4 Quadrunners8 New Runners - Overhaul Unit 3 Quadrunners4 Additional Unit 3 and 4 Upgrades9 Sediment Bypass Rehab Debris Handling System Rehab Powerhouse Building 5 Future Upgrade Decisions Avista will need to continue to monitor the financial factors that contribute to the marginal business case for the upgrade alternatives at the other Spokane River Plants. The Project Team found that a new 80 MW second powerhouse at Monroe St (Alternative 2) and a new 68 MW powerhouse at Long Lake (Alternative 2) have the best potential as future projects. Any combination of the following factors could contribute to a scenario where hydro upgrade alternatives at these projects could compare favorably with the integrated resource plan’s (IRP) avoided cost resource: • Rising natural gas prices 8 Includes New Thrust Bearings and Hydraulic Governors 9 Includes control protection package, switchgear, static excitation system, and rehabilitation of the Unit 3 and 4 intake gates. Staff_PR_103 Attachment A Page 12 of 17 November 2012 SRA Summary Report Page 12 • Rising future power market price forecasts • Carbon tax/cap-&-trade or other similar federal or state legislation • New or increasing state or federal RPS and REC requirements Avista renews its IRP every two years and these factors are considered in that process. In between IRP cycles, should any of these factors significantly change; a simple algorithm relying upon these four factors can be used to determine whether an update within the Spokane River Project is warranted. Staff_PR_103 Attachment A Page 13 of 17 November 2012 SRA Summary Report Page 13 Appendix A: Scoring Matrix Alternative 1 Alternative 3 Alternative 4 Alternative 5 New Downstream 3 Units New Downstream 5 Units New in existing location Full Plant Upgrade Score Score Score Score 3.21 3.25 3.36 5.00 3.21 3.25 3.36 5.00 Goal One Weighting 40% 4.00 4.00 4.25 3.75 3.50 3.50 3.50 3.50 3.75 3.75 3.88 3.63 Goal Two Weighting 10% 2.42 2.42 2.67 3.45 2.66 2.66 2.78 3.22 2.00 2.00 2.32 4.50 2.25 2.25 2.50 4.00 2.33 2.33 2.57 3.79 Goal Three Weighting 40% 3.00 3.00 4.25 3.00 3.00 3.00 4.25 3.00 3.00 3.00 4.25 3.00 Goal Four Weighting 10% 12.29 12.33 14.05 15.42 2.89 2.91 3.18 4.18 Alternative 1 Alternative 3 Alternative 4 Alternative 5 New Downstream 3 Units New Downstream 5 Units New in Existing Location Full Plant Upgrade Relationships with key stakeholders - NGOs Average Average Opportunities to improve hydro public safety Opportunities to improve dam safety Total Points Weighted Average Average Relationships with key stakeholders - Agencies Nine Mile Alternatives - Summary Score Sheet Goal/Criteria 4. Safety - (NOTE: All Alternatives were assumed to Pass Applicable Safety Standards) Identify the options with the best customer value Improve overall plant reliability Ensure the design is flexible enough to meet current and anticipated criteria. 2. Increase Plant Efficiency Assess likelihood of approvals Assess time required to move through regulatory process 1. Provide cost effective generation options to meet resource needs 3. Address environmental, community and permitting requirements/considerations - Red flag if score below 2.25 Average Staff_PR_103 Attachment A Page 14 of 17 November 2012 SRA Summary Report Page 14 Appendix B: Risk Evaluation Nine Mile Risk Identification: Alternative 4 (New Powerhouse) vs. Alternative 5 (Rehabilitated Powerhouse) Financial Energy/REC market volatility • The price of gas/value of RECs may increase in the future. Change in carbon regulations • A carbon tax is imposed on thermal generation resources Four alternative due to current financial assumptions (gas prices, REC values, carbon regulation assumptions). evaluating: • Future gas prices • Future REC values • Carbon tax impacts severity of this risk are both high. In order to mitigate the risk, a sensitivity analysis was performed and found that REC values would need to increase by 200% in order for the New Powerhouse to be Regulatory/ Financial Timeline for approval of a Major Modified License Amendment • The approval process could be longer than anticipated due to appeals (e.g., 401) Alternative Four • Lost revenue • Inability to meet future demand with the preferred resource • Could affect project economics due to changed interest rates, construction costs, inflation, etc. Develop a comprehensive Regulatory and Communication Strategy The driver of this risk is the high probability that the regulatory process would take longer than anticipated, resulting in construction delays and the potential of not meeting load growth in the future necessitating buying power on the market. Risk Key High Moderate Low Staff_PR_103 Attachment A Page 15 of 17 November 2012 SRA Summary Report Page 15 Category Risk Description Alternative Potential Impact Potential Mitigation Risk Level FERC, stakeholders) • A decision on Nine Mile has been delayed causing the relationship with agencies that have already approved the Unit 1 and 2 Non-capacity amendment to be strained the agencies could be affected which could affect future permitting and licensing requests comprehensive Regulatory and Communication Strategy severity of this risk are low. It isn’t likely that Avista’s reputation will be affected provided a plan for addressing Nine Mile is shared with the regulatory agencies. Technical • The solution to dealing with the sediment load at Nine Mile is inadequate. Four submerged equipment is curtailed regardless of which alternative is chosen. of the sediment issue including hydraulic modeling. the sediment isn’t addressed, the cost of replacing equipment could be high, but the probability of the risk occurring is lower with Five damaged equipment is high and the probability that a retrofit of the sediment bypass system would Financial Choosing 5b but executing something closer to the 5a scope. • Budget constraints could impact the construction budget and timeline, affecting the ability to complete rehab of all the components included in the scope of 5b Alternative Five The scope of 5b would not be completed and there would continue to be chronic maintenance issues and costs Establish appropriate rehab program in the budget The probability and severity of this risk are high. If the full scope of the Alternative 5 is not executed, there will be continued equipment failure and costs associated with outages. • The wetpit design provides maintenance and accessibility challenges Five address the inherent access and maintenance issues associated with the wetpit design precautions and proper training probability that this risk will occur with proper training. Staff_PR_103 Attachment A Page 16 of 17 November 2012 SRA Summary Report Page 16 Category Risk Description Alternative Potential Impact Potential Mitigation Risk Level • Potential breech of the bulkhead due to turbine or shaft failure Five equipment due to flooding contemporary design New turbine vibration monitoring system would allow alarm and trip capability is low, but the severity would be high • Will the 100 year old concrete continue to be structurally sound through the life of the license? • Will the post-tensioned anchors be adequate through the life of Five evaluations and funds for remediation. structural elements would need continued evaluation based on FERC’s dam safety program but the severity would be high. Staff_PR_103 Attachment A Page 17 of 17