2017 IRP Advisory Group. July 21, 2017 IRPAG

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1 2017 IRP Advisory Group

2 Today s Agenda 2

3 General Rate Case Caution Need to avoid the possibility of unintentionally violating ex-parte communication rules Please refrain from bringing up any rate case issues, given WUTC Policy Staff are participating today Nothing on the agenda will violate ex-parte communication rules Please stay on topic We can have a Q & A session at the end, after Policy Staff has left 3

4 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." 4

5 Advisory Group Process Check The Demand Side Resource Conservation Potential Assessment Report authored by Navigant was filed with the WUTC on Friday, June 30, distributed to this group by on July 3, and is now available on pse.com. Meeting note review from June 22, 2017 meeting Next meeting, August 11, will present electric and gas results Draft 2017 IRP due September 12,

6 Operational Flexibility Study Overview Phillip Popoff Manager, Resource Planning & Analysis Elizabeth Hossner, Consulting Resource Planning Analyst July 21, 2017

7 Agenda What is operational flexibility and why is it important? Goals of the 2017 analysis Study methodology and assumptions Summary of results and introduction of E3 to detail the results 7

8 Operational Flexibility What is Operational Flexibility? Operational flexibility is the ability of a power system to increase or decrease demand or supply in response to the changes in demand and supply. Why is Operational Flexibility Important? Increasing intermittent generation affects need to ramp other resources up and down quickly. 8

9 Operational Flexibility in the IRP IRP analysis traditionally focuses on hourly-level granularity Aurora includes operational limits of power plants, but not below hourly level Example, a CCCT plant must run at least 8 hours, but can ramp up and down within limits between hours Sub-hourly operations have always been important Entire WECC system must balance load and generation Resources must be able to ramp up/down as loads fluctuate Operational Flexibility is comprised of ancillary reserve requirements Balancing (load and wind) Contingency reserves (spin and non-spin) Regulation 9

10 CA Duck Curve CAISO, March 16,

11 Sources and Demand for Flexibility Resource Availability - Hydro Conditions - Economic Dispatch - Planned Outages Resource Capacity - Regulation & Following Reserves Resource Ramp Rate Sources of Flexibility Hour-Ahead Regulation, Following, and Contingency Reserves PSE Resources Actual Deviations in Load, Generation, and Interchange from Schedules Forced Outages Demand for Flexibility 11

12 Background PSE has been developing models to analyze sub-hourly flexibility since before the 2011 IRP 2013 IRP: utilized in-house model Model was not robust enough to support acquisition decisions 2015 IRP: in-house model was not adequate for modeling needs 2017 IRP: PSE acquired the Plexos Model, which can simulate 5-minute level granularity Engaged with E3 Consulting to help implement the framework and run the Plexos model for the 2017 IRP Future: Continue to improve analytical framework Use framework to answer planning questions Incorporate Energy Imbalance Market (EIM) opportunities July 21,

13 Two Goals for Flexibility Analysis 1. Physical Needs Will PSE have adequate ramp up/down capability? If not, may need to add an additional dimension to planning standard or operational guidelines to ensure PSE can meet it s operational needs 2. Reflect Sub-Hourly Flexibility Analysis in Portfolio Analysis (Financial Impacts) Different resources have different sub-hourly operational capabilities Even if portfolio has adequate flexibility, different resources can impact how the entire portfolio operates & impact costs Example: Batteries could avoid dispatch of thermal plants for some ramping up and down Need a way to monetize those values, to incorporate in portfolio analysis, to ensure lowest reasonable cost decisions 13

14 Key Terms I: Day-Ahead ( DA ) Schedule and Real Time ( RT ) Day-Ahead (DA) Schedule Utilities Schedule Resources on Hourly Basis in Day-Ahead Market Next day, load and resources in every hour will probably deviate from schedule Portfolio must have the flexibility to adjust to those differences Costs will be different than predicted by day-ahead alone Real Time (RT) Operations In addition to hour to hour differences; there is also sub-hourly differences Within each hour resources will ramp up and/or down Again, a Day-Ahead view alone will miss those cost impacts 14

15 Key Terms II INC ( inking ) increase, turn it up or ramp it up DEC ( decking ) decrease, turn it down or ramp it down Ramping speed at which a unit can increase or decrease its generation Violation E3 will cover this in depth Reserve benefit/cost savings measured in $/kw-year; the cost savings of the additional resource to the Portfolio 15

16 Plexos is: Hourly and sub-hourly chronological production cost model. Plexos can perform a day-ahead simulation for unit commitment and a real-time simulation to re-dispatch resources to meet sub-hourly changes in demand and supply. 16

17 Plexos vs. Aurora Aurora is an hourly chronological production cost model. Aurora performs a unit commitment similar to the day-ahead simulation in Plexos. Database Aurora: A complete North American database is included with Aurora to run power price simulations. Plexos: No database is provided and user has to build own. Plexos has the ability to change the dispatch of resources from the day-ahead to real-time simulation, Aurora does not. 17

18 Methodology Created base portfolio PSE s portfolio as it currently exists Tested each supply-side resource identified in the IRP and compared the results of that to the base portfolio Any cost reduction to the portfolio is assumed to be attributed to the new resources and given as a benefit to the cost in the portfolio analysis. 18

19 Assumptions Had to create a complete picture of PSE as a balancing authority (BA) and PSE s connection to the market. Identified required reserves Contingency Reserves (3% load, 3% generation) Spin 10 minutes Non-spin 60 minutes Regulation up/down < 5 minutes Balancing up/down 10 minutes Used actual 5-minute demand data from 2016 and then scaled to the demand forecast for

20 Assumptions Continued 2016 actual 5-minute data for wind in PSE s BA and run-of-river hydro 2016 daily Mid-C generation was used and then Plexos optimized generation within the day. Utilized PSE s 2016 operating parameters for thermal plants 2017 IRP Base Scenario Forecast PNW power prices from Aurora for Base Base natural gas price Base CO 2 price 20

21 Findings PSE does not appear to have significant ramp up or ramp down flexibility concerns Additional planning standards or operational constraints do not appear necessary based on analysis for 2017 IRP The costs of the various benefits concerning flexibility resources vary greatly; this will be further discussed in the E3 presentation. 21

22 Important Note The second resource added will not have the same benefit as the first resource. The first 25 MW of batteries has a benefit of $119/kw-yr, but the second 25 MW will have a much lower benefit. Example: 3 Reciprocating Engines = $97/kw-yr 6 Reciprocating Engines = $65/kw-yr 12 Reciprocating Engines = $44/kw-yr As more of the same resource is added to the portfolio, the benefit is reduced July 21,

23 Results Most of the benefits are from the DA simulation. The DA benefits from the thermal plants are already included in the portfolio analysis from Aurora. The RT vs. DA difference isolates out just the benefits associated with flexibility IRP Resource Annual Variable cost savings ($/kw-yr) RT vs. DA variable cost savings ($/kw-yr) CCCT ($46) - Frame Peaker ($26) ($1) Aero Peaker ($56) ($7) Recip Peaker ($97) ($11) 2-hr Li-Ion Battery ($119) ($3) 4-hr Li-Ion Battery ($131) ($8) 4-hr Flow Battery ($117) ($2) 6-hr Flow Battery ($128) ($7) Pumped Storage Hydro ($144) ($10) 23

24 Operational Flexibility Study Results Jack Moore Director, Energy + Environment Economics Inc. Arne Olson Partner, Energy + Environment Economics Inc.

25 <E3 presentation> 25

26 2017 IRP Transmission Redirect

27 Overview 2017 IRP will include Transmission Redirect as Resource Alternative Explanation of Transmission Redirect Why bring this up now? Cost assumptions 27

28 Transmission Redirect Redirect: Moving firm receipt point for transmission In this case from Hopkins Ridge and LSR to Mid-C To meet winter peaking load, PSE has found it can redirect ~188 MW of this transmission from Hopkins Ridge and LSR, with no additional BPA infrastructure required Wind output in excess firm transmission capacity will be moved on short-term firm or non-firm transmission service Why Consider Transmission Redirect? 188 MW of capacity avoids long-term generation decision Hopkins Ridge and LSR correlate poorly to peak load Cost is significantly less than any other capacity resource Does increase reliance on short-term market 28

29 Why Consider This Now? Exploring ways to optimize transmission for use in Energy Imbalance Market (EIM) Process identified redirecting wind transmission as feasible Very low cost capacity: $3.26/kW-yr What about risk? Reduces risk: Could avoid long-term generation build under such volatile policy conditions and load uncertainty Increases risk: Increases exposure to reliability risk of short-term wholesale markets Caution: Wholesale market risk very different before 2022 as region adds ~600 MW of energy efficiency-based on NWPCC between and coal plants still operating today 29

30 Redirect Potential Hopkins Ridge LSR Total Full Capacity For Redirect Remaining LT Firm

31 Analytical Approach Estimated MWh in Excess of Lower Transmission Capacity Hopkins Ridge: MWh Above 67 MW on Hourly Basis LSR: MWh Above 245 MW on Hourly Basis Used historic hourly data Calculated the excess generation each hour, by month Average of each month Priced Excess Generation at BPA Short-Term Firm Rate: $5.15/MWh 31

32 350 LSR - Example of Monthly Redirectable MWHs I ~ :i. a::: (/)...J o Dec 4 Dec 9 Dec 14 Dec 19 De<: 24 Dec 29 YES NO Above Hourly Redirect Threshold? 32

33 Redirect Turns This Portion Into Firm Capacity 33

34 Cost Calculation MWh Above 66 MW at HR & Above 245 MW at LSR Nov-Mar 122, Annual 257, Short-Term Firm Trans Rate $/MWh Estimated Annual Cost MW Capacity $/kw-yr $ $ 631, $ $ 1,327, Will Use Nov-March Redirect Cost Annual Would Not Change Resource Plan Analysis But Unnecessary Cost 34

35 Wrap-up/Review Action Items

36 2017 PSE IRP due November 15, 2017 Topics for remaining PSE 2017 IRPAG meetings: 1. Portfolio Analysis Results (August 11, 2017); 2. Review Draft IRP* (October 5, 2017); * Draft IRP will be distributed by or before September 12,

37 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 37

38 THANK YOU 38

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