2017 IRP Advisory Group. June 22, 2017 IRPAG
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1 2017 IRP Advisory Group
2 Today s Agenda 2
3 Purpose of IRP WAC Integrated resource planning. 1) Purpose. Each electric utility regulated by the commission has the responsibility to meet its system demand with a least cost mix of energy supply resources and conservation. In furtherance of that responsibility, each electric utility must develop an "integrated resource plan." 3
4 Advisory Group Process Check Meeting note review from May 22, 2017 meeting Snoqualmie Falls tour reminders and information 4
5 Regulatory Process Overview Phillip Popoff Manager, Resource Planning & Load Forecasting June 22, 2017
6 Purpose of This Overview Explain how Integrated Resource Planning fits into the broader regulatory process regarding resource acquisitions 6
7 Three Regulatory Processes Central Focus: Making prudent resource decisions on behalf of customers WUTC typically does not pre-approve resource decisions prudence is established after-the-fact (ex-post). IRP Acquisition Process Rate Case 7
8 What is Prudence? Description of Prudence Test (Case Law/Precedent) What would a reasonable board of directors and company management have decided given what they knew or reasonably should have known to be true at the time they made a decision. Generally, one cannot rely on the advantage of hindsight. Elements of Prudence Demonstration Need Alternatives Considered Analysis Decision Reevaluation (as relevant) Documentation 8
9 IRP Purpose: WAC (1) Each electric utility regulated by the commission has the responsibility to meet its system demand with a least cost mix of energy supply resources and conservation. In furtherance of that responsibility, each electric utility must develop an integrated resource plan. (2) (a+b) Lowest reasonable cost to ratepayers, including risk, dispatchability, resource preference, cost of risk from environmental effects. Regulatory Process Biennial compliance filing required by the WUTC Utility files IRP work plan for informal review one year before filing date Utility develops IRP, including public participation per work plan Draft IRP distributed informally for feedback Utility files IRP with WUTC Public can file comments to the WUTC WUTC holds open meeting for utility presentation and public comment WUTC reviews IRP filing for compliance with rules WUTC typically sends acknowledgement letter with suggestions for future 9
10 Demand-Side Resource Acquisitions Purpose: (Refer to WAC ) -- Establish conservation targets and set rates to implement conservation programs based on IRP guidance, to acquire all conservation that is available, cost-effective, reliable, and feasible. Utility Develops Filing Utility develops biennial targets, plans, and rates to recover costs Detailed plans and budgets discussed with external stakeholders in the Conservation Resource Advisory Group (CRAG) Filing Utility files tariffs revisions to implement targets WUTC reviews and audits savings and costs from prior periods WUTC approves/rejects/modifies filing 10
11 Supply-Side Resource Acquisitions Purpose: Acquire least cost resources based on specific resource alternatives available. (Refer to WAC ) RFP Regulatory Process Draft RFP filed at WUTC: Required if capacity need is identified within 3 years PSE typically conducts All-Source RFP based on updated IRP need Typically do not target specifics, like CT vs CCCT or specific renewable resource technologies Ownership/contract structures typically left open for bidders WUTC accepts public comments on draft RFP WUTC will accept or order changes to the RFP Utility issues RFP Utility updates key assumptions from IRP (gas prices, loads, etc.) Utility makes acquisition decision(s) Utility publishes and makes a summary of each offer and final ranking public Acquisitions Outside Formal RFP Process WAC : resource can be acquired outside of the RFP process Prudence standards still apply 11
12 Rate Case Cost Recovery Addressed in Rate Case General rate case or other similar proceeding Regulatory Process Utility files general rate case or other approved rate recovery mechanism Formal legal process with intervenors takes place Formal discovery process WUTC seeks public input WUTC makes a ruling on prudence of resource acquisition Prudence Established: utility can recover cost of new resources in rates Finding of Imprudence: WUTC may disallow recovery of imprudent portion of costs 12
13 Questions & Answers 13
14 Portfolio Analysis Methodology Elizabeth Hossner Consulting Energy Resource Planning Analyst
15 IRP Process Establish Resource Needs LOLP Commitment to Action Planning Assumptions & Resource Alternatives Make Decisions Analyze Alternatives and Portfolios Analyze Results 15
16 Models/Tools Planning Assumptions & Resource Alternatives Aurora All other assumptions Wholesale Market Price Forecasts How will different resource alternatives dispatch to market and perform in our portfolio? Analysis of Alternatives Portfolio Analysis Aurora PSM III Financial Plexos Risk Solver Platform 16
17 Intro to PSM III 17
18 Portfolio Screening Model 3 (PSM III) Excel Spreadsheet-based capacity expansion model that evaluates revenue requirement and risks of a wide variety of resource alternatives and portfolio strategies PSM III is used to identify the least cost portfolio resource additions in a given market scenario. Cost is a revenue requirement. Revenue requirement is how costs flow to customer 18
19 Revenue Requirement Resource decisions are based on revenue requirement and impact to portfolio costs. Revenue requirement is calculated on an annual basis for the entire life of the plant and is expressed in ($000). Annual Revenue Requirement includes Return on Ratebase Depreciation Expense New Resources Transmission Costs Fixed Operations & Maintenance Fuel Cost Gas plants include pipeline transport costs along with fuel use and taxes Variable Operations & Maintenance Start-up costs Emission Cost 19
20 History of PSM PSM was originally created in 2001 by Navigant Consulting Used a simplified dispatch Portfolios were created outside the model and then input into the model PSM II was created in 2009 Incorporated unit commitment logic (from Aurora) Portfolios were created in Strategist and then input into the model. Strategist is a third party model used to optimize portfolios PSM III was created in 2010 Incorporated unit commitment logic (from Aurora) Added Risk Solver Platform (Excel add in) to optimize portfolio in the model 20
21 What is a Portfolio? PSE s existing resources. This includes thermal plants, hydro, wind, and long-term contracts. New resources additions. Any new resources added to meet PSE s needs. There will be one optimal portfolio for each of the 14 scenarios plus various sensitivities. 21
22 PSM III in the IRP 22
23 IRP Modeling Process PSE portfolio specific information including: Plant operating characteristics, PSE monthly load and hourly shaping, AURORAxmp Other PSM III Inputs: Existing Resources Resource Alternatives Normal Peak Load Constraints Plexos Flexibility Benefit Mid-C Power Prices Deterministic Input Price Run (PSE Portfolio Only) Energy, Cost, Revenue Optimal Portfolio Deterministic Optimization Stochastic Model PSE Load Sumas Gas Prices Hydro Generation Wind Generation CO2 Price Power Prices Forced Outage Aurora Risk Run (PSE Portfolio Only) Peak Load Stochastic Process Energy, Cost, Revenue Stochastic Risk Analysis Stress Test PSM III
24 Portfolio Optimization 24
25 PSM III Optimization Process Aurora Outputs for each Resource Cost, Revenue, MWhs Resource Assumptions Year available, Capacity Contribution PSM III Financial Model: Evaluates the cost of each resource alternative used in the model Peak Capacity, Energy, and Renewable needs Optimization Model: Linear Program finds the lowest cost portfolio that meets your resource needs Optimal Portfolio 25
26 Portfolio Optimization Model The portfolio optimization model is built into the PSM financial model. The financial model is in Excel The portfolio optimization model is in Risk Solver Platform, an Excel add in The optimization model is a mixed integer linear programing model that solves using the dual simplex method. 26
27 Objection Function and Constraints of PSM III Objective Function: Minimize Expected Portfolio Cost = NPV(cost of Existing Resources) + NPV(cost of Generics Resources) + NPV(Market Purchases/Sales) + NPV(DSR) NPV(REC sales) Subject to 2 Constraints: 1. Peak Capacity >= Peak load + Reserves + Planning Margin 2. REC Need >= RPS*(Sales DSR) 27
28 Incremental Cost of Existing Resources Thermal plants Fuel Cost Gas plants include pipeline transport costs along with fuel use and taxes Variable Operations & Maintenance Start-up costs Emission costs Price of contracts 28
29 Cost of Generic Resources Annual Revenue Requirement includes Fuel Cost Gas plants include pipeline transport costs along with fuel use and taxes Variable Operations & Maintenance Start-up costs Fixed Operations & Maintenance Capital Expenditures Taxes Insurance Emission Cost Oil back-up Transmission Costs The revenue requirement is carried out to the full life of the plant which extends beyond the 20-yr planning horizon 29
30 Market Purchases/(Sales) The net cost or benefit of selling power and buying power Market purchases/(sales) is calculated by assuming we buy all our power at Mid-C at market price. Then we dispatch all our resources to market and get revenue from the sales. This calculation is done by hour in Aurora and summed up to annual number for PSM III 30
31 Other Costs Demand-Side Resources (DSR) The annual cost of the DSR bundles, Distributed Efficiency, and Demand Response Renewable Energy Credit (REC) Sales The surplus RECs are assumed to sold at a forecasted price. 31
32 Constraint 1 - Peak Capacity Need The requirements of meeting the peak need has three components 1. Customer Demand Peak Capacity need is a one hour system peak in December Normal Peak at 23 degrees F at SeaTac 2. Planning Margin (PM) of 13.6% (5% LOLP) 3. Operating Reserves Contingency reserves of 3% load and 3% generation for everything in PSE Balancing Authority (PSEI BA) WECC-BAL- 002 Balancing reserves for load following and wind integration. 32
33 Example Peak Capacity Need Peak Demand December ,153 MW Planning Margin 13.5% Normal Peak Load + PM Operating Reserves Total Capacity Need Total Resources (No DSR) Available Mid-C Transmission Total Operating reserves on new resources Total Resource Deficit/(surplus)* *Resource need before demand-side resources (DSR) 5,836 MW 408 MW 6,244 MW (4,401) MW (1,724) MW 118 MW 4 MW 122 MW 33
34 Example Peak Capacity Need The Constraint in 2020 is that PSE needs at least 6,244 MW of winter peak capacity PSE has 6,126 MW of resources to meet winter peak (including 1,724 MW of open transmission to Mid-C), so the company still needs 118 MW of new demand-side resources or 122 MW of new supply-side resources 34
35 December Peak Need before DSR 9,000 8,000 7, MW 6, MW 1,333 MW 2,012 MW 2,634 MW 5,000 MW 4,000 3,000 2,000 1,000 0 Colstrip Contracts Wind Additional Mid-C Transmission Available w/ Renewals Natural Gas Hydro Available Mid-C Transmission 2017 IRP Dec Peak Load + PM + Op Reserves 35
36 Constraint 2 - REC Need Washington RPS targets: 9% by % by 2020 The IRP uses the REC banking provision to bank forward RECs for one year. Snoqualmie Falls upgrades and Lower Baker 4 meet the requirements for hydro in RCW Hydro RECs cannot be banked and are used in the same year as produced. Other renewable resources include Hopkins Ridge, Wild Horse, Wild Horse Expansion, Lower Snake River I, and Klondike III Wild Horse Expansion and Lower Snake River I also receive the 20% Apprenticeship credit 36
37 Renewable Need Minimum amounts of produced and banked RECs Hydro REC Need: 2017 IRP Base Forecast less draft DSR REC Need: 2017 IRP Base Forecast 3500 RECs ' K RECs = 227 MW Wind (WA) 1,271K RECs = 398 MW Wind (WA)
38 Questions & Answers 38
39 Appendix Revenue Requirement 39
40 Regulatory Compact PSE is an Investor Owned Utility (natural gas and electric) Regulated by the Washington Utilities and Transportation Commission (WUTC) to establish rates that are fair, just, reasonable and sufficient The Regulatory Compact provides that, in return for being allowed to operate as a monopoly, PSE is: Obligated to provide safe & reliable service within our service territory Allowed to recover prudently incurred costs of service Provided an opportunity to earn a fair return on investment 40
41 Revenue Requirement PSE earns a return on dollars invested in capital expenditures and recovers costs Ratebase X Rate of Return = Operating Income Operating Income + Operating Expense = Revenue Requirement 41
42 Ratebase Gross Plant (Invested Capital) Less: Accumulated Book Depreciation Less: Accumulated Deferred Tax Ratebase 42
43 Deferred Taxes Deferred tax assets and liabilities are recognized when there is a temporary difference between the stated value of an asset or liability for tax purposes and the value for financial reporting purposes For example, under tax law companies can often depreciate fixed assets at a faster rate for tax purposes than the actual use of the asset would dictate via book depreciation The tax expense on the book income statement is not the actual amount paid to the IRS but rather represents a combination of current taxes paid and the deferred taxes The cash benefit of deferred taxes is included as a reduction of ratebase Accumulated Book Depreciation Accumulated Tax Depreciation Difference Book vs. Tax x Federal Income Tax Rate Accumulated Deferred Tax 43
44 Rate of Return Sufficient to enable the utility to maintain its credit standing and financial integrity, and to attract new capital at reasonable costs Determined using the overall weighted cost of capital Recognizes that the utility s rate base is financed by two types of capital sources: Debt Equity 44
45 Proposed Allowed Rate of Return 2017 GRC Weighted Average Cost of Capital Structure Cost WACC Long Term Debt 51.5% 5.81% 2.99% Common 48.5% 9.80% 4.75% Total 100% 7.74% 45
46 Sample Revenue Requirement Calculation Generic Wind Year Rate Base 2 Utility Plant in Service and Other Assets $ 208,898 $ 208,898 3 Accumulated Dep. & Amort. (Average) (4,178) (12,534) 4 Accumulated Deferred FIT (Average) (5,849) (21,934) 5 Total Rate Base $ 198,870 $ 174,429 6 Rate of Return 7.74% 7.74% 7 Return on Ratebase $ 15,393 $ 13, Operating Expenses 10 Variable O&M $ 1,862 $ 1, Fixed O&M 2,994 3, Property Tax Insurance Fixed Transmission Cost 4,052 4, Book Depreciation 8,356 8, Production Tax Credits (8,157) (8,138) 17 Taxes 5,086 4, Total Operating Expenses $ 15,243 $ 14, Revenue Requirement (Line 7 + Line 17) $ 30,635 $ 28,386 Nominal cost in $000 46
47 Resulting Income Statement Year 1 Year 2 Income Statement Generic Wind Revenue Requirement $ 30,635 $ 28,386 2 Operating Expenses 3 Variable O&M $ 1,862 $ 1,908 4 Fixed O&M 2,994 3,069 5 Property Tax Insurance Transmission Cost 4,052 4,178 8 Book Depreciation 8,356 8,356 9 Production Tax Credit (8,157) (8,138) 10 Taxes 5,086 4, Total Operating Expenses 12 $ 15,243 $ 14, Operating Income 14 15,393 13, Interest 16 5,946 5, Net Income 9,446 8, Ratebase $ 198,870 $ 174, ROR 7.74% 7.74% 21 Target Operating Income $ 15,393 $ 13,501 Nominal cost in $000 47
48 IRP 2017 Resource Adequacy Model: Updates to Peak Capacity Credit Calculations Villamor Gamponia Consulting Energy Resource Planning Analyst
49 Agenda Purpose: Share the updated peak capacity credit of wind using inputs from DNVGL presented at the last IRPAG, Demand Response and back up fuel oil. Brief Review of PSE s Resource Adequacy Framework: models and metrics Updated Peak Capacity Credit using ELCC(Effective Load Carrying Capability) for variable energy resource or energy limited resource Wind resources based on DNVGL wind inputs Demand Response planning Adequacy of back up fuel oil for dual fuel peakers with no firm gas supply 49
50 PSE s Resource Adequacy Framework Concept Regional Market Mid-C Transmission PSE Models GENESYS WPCM RAM/LOLP (BPA/NPCC) (PSE) (PSE) 50
51 Resource Adequacy Metric Definitions Metrics Definition LOLP (loss of load probability) EUE (expected unserved energy) ELCC (Effective Load Carrying Capability) Number of simulations with any deficit event as a percent of total simulations, regardless of the duration, frequency and magnitude of events(%) Sum of the MW deficits across all simulations divided by total simulations(mw/hr) The equivalent peaker capacity change to get the same LOLP/EUE when a resource is added to the portfolio (expressed as a percent of the resource capacity added); the Peak Capacity Credit of the added resource is this percent of its nameplate capacity 51
52 Agenda Updated Peak Capacity Credit Using ELCC for Variable Energy Resource or Energy Limited Resource Wind Resources Based on DNVGL Wind Inputs 52
53 Monthly Mean Capacity Factors ("CF") 8: Coefficient of Variation of CFs (all hours) *Coefficient of Variation is thickness of line in line chart % Eastern M ont ana 60 17,000 u. (.) DNVGL c: (tl 40% Annual Q) Simulations ~ 30% 20% e 60% 50% 250Annual u. (.) Draws for c: (tl 40% IRP Q) Stochastics ~ 30% 20% Ge Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Resource Eastern Montana Generic WA Offshore Generic WA SE Generic WA Skookumchuck 17,000 DNVGL Annual Simulations - Monthly Mean CFs (all hours) Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Eastern Montana 60% 51% 48% 44% 41% 37% 32% 32% 37% 44% 53% 54% Generic WA Offshore 52% 46% 43% 31% 23% ~1% 23% 19% 22% 3-.% 48% 5--.,., Generic WA Skookumchuck 44% 35% 41% 26% 20% 17% 15% 17% 20% 32% 44% 43% Generic WA SE 30% 24% 40% 35% 34% 35% 29% 27% 26% 26% 28% 29% ~ ONVGL Simulations and IRP Draws within +/- 2% range, thus ONVGL simulation averages displayed in table_ 53
54 Peak Capacity Credits (ELCC) for Wind-DNVGL Draws Skookumchuck is added first, followed by each of the generic wind projects to reflect diversity. Capacity (MW) Equivalent Peaker Capacity Change to Get Back to 5% LOLP(MW) Peak Capacity Credit Based on 5% LOLP Skookumchuck(DNVGL) % Generic Eastern Montana(DNVGL) % Generic LSR(DNVGL) % Generic WA Offshore(DNVGL) % Sources of key differences: DNVGL draws are based on wind data versus for generic LSR & for generic Montana in the last study. DNVGL accounted for turbine availability, icing, wake effects but not for curtailments. Example of Peak Credit Calculation MW LOLP 1) Starting Portfolio % 2) Add Skookumchuck % 3) Reduction in Capacity % Peak Capacity Credit( 3/2 -MWs) 40% 54
55 Agenda Updated Peak Capacity Credit Using ELCC for Variable Energy Resource or Energy Limited Resource Demand Response Planning 55
56 Demand Response Planning Study Goal: Provide ELCC estimates for various DR program designs in terms of magnitude (peak capacity), duration and frequency of calls. Initial RFP bid requirement: maximum of ONE event per day may be called, with a maximum duration of 4 hours; events will not be called on more than two consecutive days: ELCC = 53% Given the daily outage patterns for PSE from RAM, programs were refined to allow DR to be called 2x a day, up to 3 hours duration, with 6 hours recovery between events: ELCC = 77% Summer Single Peak Winter Double Peak 56
57 DR Program Performance Requirements Initial RFP requirement: One event per day, no more than two consecutive days constraint is a common DR design to avoid customer fatigue In North America, most DRs are for summer peaks called once per day Different DR programs will have different performance characteristics based on load control technology, end-uses, or customers (industrial vs. residential, HVAC vs. water heating, etc.) When presented with the ELCC data, the apparent winners for both the C/I DR program and Residential Direct Load Control Program optimized their program design to allow DR to be callable twice per day with 6 hours of recovery between events, with maximum duration of 3 hours per event 57
58 Approach with PSE s Resource Adequacy Model Use EUE - accounts for magnitude, duration and frequency. Describe the outage characteristics that a DR program must address to adequately displace a peaker of similar size 1. Start at 5% LOLP Resource Portfolio 2. Remove X MWs of Peaker Capacity from the Portfolio 3. Difference between 1 and 2 describes the characteristics of an equivalent DR program in terms of: Magnitude (incremental MW deficits) Frequency (how often bad events happen in a day/season) Duration (duration of bad events) Time between bad events 58
59 ELCC Calculation of a DR Program DR program study attributes: 100 MWs, 3 Hours maximum duration, called every 6 hours(addresses dual peak events in a day for typical PSE load shape) 1. Calculate the EUE of portfolio at 5% LOLP 2. Remove 100 MW of peaker capacity and calculate the total incremental EUE from Step 1 3. Implement a DR program given its attributes 4. Calculate the reduction in incremental EUE due to the DR program 5. ELCC of the given DR program is the ratio of the reduction in incremental EUE (Step 4) and the total incremental EUE (Step 2) 59
60 Impacts of Removing 100MW from Portfolio 60
61 ELCC Estimates of Various DR Programs EUE 1) 5% LOLP) ) Base less 100MW CT ) Incremental EUE ) Apply Demand Response 5.9 (100MW, 3Hrs Max, Called Every 6HRs) 5) Reduction in EUE ) ELCC based on EUE (row 5/ row 3) 77% ELCC Estimates for Various DR Event Parameters(100MW) Call Frequency(Elapsed Hrs After Last Event) Duration(Hrs) % 61% 57% 49% 3 80% 77% 72% 59% 4 90% 85% 80% 65% 53% 5 94% 89% 84% 68% 55% 61
62 Agenda Updated Peak Capacity Credit Using ELCC for variable energy resource or energy limited resource Adequacy of back up fuel oil for dual fuel peakers with no firm gas supply 62
63 Adequacy of Backup Fuel Oil for CTs Two key questions: 1. Is the current 2-day fuel oil backup adequate to run the CTs if spot gas is not available for the season? Answer: It Depends Existing Dual Fuel Fleet + Replace Colstrip 1 & 2: Yes AND Replace Colstrip 3 & 4: No all units would need 3 days. 2. If back up fuel oil is used for the season, do we exceed the annual maximum run hours constraint of 300 hours for air emission standards? Answer: No, we do not exceed the annual maximum run hours. 63
64 Methodology Use PSE s Resource Adequacy Model to define outage characteristics if spot gas supply is not available for simple cycle CTs (existing and potential future CT additions). Start with a balanced portfolio meeting the 5% LOLP standard including 2015 DSM savings. Then run the model under the following scenarios: Scenario 1: Remove all existing simple cycles (CTs) (696 MWs) Scenario 2: Scenario 1 and remove Colstrip 1&2(298 MWs) - assuming CTs replace Colstrip 1&2 Scenario 3: Scenario 2 and remove Colstrip 3&4(359 MWs) - assuming CTs replace Colstrip 3&4 Examine the incremental outage characteristics of these three scenarios from base portfolio at 5% LOLP. 64
65 Adequacy of 2-Day Fuel Oil Back Up 1.1 Cumulative Distribution of Incremental Deficit MWHs/Year for Bad Simulations No CTs No CTs&Cols12 No CTs&Cols1234 Two Day Fuel Oil BackUp MWHs Is the current 2-day fuel oil backup adequate to run the CTs if spot gas is not available for the season? YES Base No CTs No CTs/Cols1&2 No CTs/Cols1&2,3&4 LOLP 5% 41% 70% 97% EUE(MW/hr) ELCC Oil BackUp 100% 100% 100% 65
66 Annual Run Hours Emission Constraints Cumulative Distribution of Incremental Deficit Hours/Year for Bad Simulations No CTs No CTs&Cols12 No CTs&Cols Hours If back up fuel oil is used for the season, do we exceed the annual maximum run hours constraint of 300 hours for air emission standards? NO
67 Questions & Answers 67
68 Wrap-up/Review Action Items
69 2017 PSE IRP due November 15, 2017 Topics for remaining PSE 2017 IRPAG meetings: 1. IRP Process Review, Portfolio Analysis Methodology, and Effective Load Carrying Capability Model Results (June 22, 2017); 2. Operational Flexibility Analysis Results (July 21, 2017); 3. Portfolio Analysis Results (August 11, 2017); 4. Review Draft IRP* (October 5, 2017); * Draft IRP will be distributed by or before September 12,
70 2017 IRPAG Meeting Schedule and /RP Milestones - Revised Pursuant to WUTC approval of November 15, 2017 filing deadline 6117/2016 IRPAG Kickoff Meetin PSE Forum 8/31 /2016 7/27/2016 IRPAG DSR-AC and IRPAG scenarios & senistiv ies PSE Auditorium PSE Auditorium Worl<plan filed 8/22/ /27/2016 IRPAG Supply-s ide gas, electric alternative assumptions 9/26/2016 PSE Auditorium IRP Electric Resource Cost Assumptions and Mid-C power prices PSE Auditorium 11/14/2016 IRPAG Electric & Gas Load Forecasts, Regional resource adequacy PSE Auditorium 12 /1 /2016 6/ /3/2017 IRPAG Resource Adequacy & Resource Need, Cost. MT wind PSE Forum 1/ IRPAG OS Navigant Snoqualmi 3/16/2017 IRPAG System Planning PSE Forum \ 8/ IRPAG 7/21 /2017 Portfolio Analys;s Results Operational Flexibi/;ty PSE Auditor;um IRPAG PSE Aud;tonum 5/22/2017 IRPAG ~ W ind, Solar, CT costs 6/22/2 H PSE Forum IRPA IRPAG Works op & ELCCAnaly. PSE AudUonu I IRPAG PSE Aud;conum Review Dratr /RP 9/12/2017 DRAFT IRP 11/15/2017 FINAL IRP Fi ling 12/31/ /1/2017 4/ / 1/2017 1/1/2017 For full account of meeting scope and records, please go to: pse.com/aboutpse/energysupply/pages/resource-planning.aspx 11/ PUGET SOUND ENERGY 70
71 THANK YOU 71
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