1. Demand Response in the 7th Power Plan
Pacific Northwest Demand Response Symposium
September 28th, 2016

2. Demand Response Actions in 7th Plan
Expand regional demand response infrastructure
At least 600 MW is cost-effective
Form a Demand Response Advisory Committee (DRAC)
Support regional market transformation for demand response
Collaborate on demand response data collection

3. Council’s Analytical Process Flow
Units &
Baseline
Unit Use
New Energy Efficiency Resource Potential Assessment
Load
Forecast
Model
Energy
Efficiency
“Supply
Curves”
Baseline
Load
Forecast
(w/o new
efficiency)
Council Reviews Cost and Risk of Alternative Resource Portfolios
Regional Portfolio Model
“Supply Side”
Resource
Cost &
Availability
New Generating Resource Potential Assessment
New Demand Response Potential Assessment

4. Demand Response Programs Included in Potential Study
Summer Peaking
Year-Round Peaking
When will the RPM likely acquire DR?
Irrigation Pumping - DLC and AutoDR
(Agricultural /Industrial)
Space Cooling – DLC and AutoDR
(Residential and Commercial)
Water Heating - DLC and AutoDR
(Residential)
Curtailable/Interruptible Tariffs - DLC and AutoDR
(Agricultural/Industrial)
Lighting Controls – AutoDR only
(Commercial)
Load Aggregators – AutoDR only
When it is economic and least cost
But more likely…
When there is insufficient peak capacity to meet system peak demand
Winter Peaking
Space Heating – DLC and AutoDR
(Residential and Commercial)

5. Developing Demand Response Inputs in RPM
Four cost bins of DR available for selection
Cost Assumptions
Benefits/Potential Included
Benefits/Potential Not Included
Real, levelized costs calculated in 2012 dollars
Seasonal Firm, Peak Capacity Potential
Balancing Capability
Implementation and Enablement Costs
Deferral of New Transmission
Deferral of New Distribution
Each cost bin uses a weighted average cost for price signal
Resource Size:
10 MW blocks
DR can be more granular than 10 MW
All programs have five year life (recurring enablement costs)
Multiple sector potential
Non-Firm DR potential

7. Demand Response Resource Program Potential by Cost Bin
(2012$ per kW-year)
Levelized Costs
2021 Winter MW
2026 Winter MW
2035 Winter MW
2021 Summer MW
2026 Summer MW
2035 Summer MW
Demand Response Price Bin 1
$25 per kW-yr
1246
1337
1462
1294
1388
1518
Demand Response Price Bin 2
$57 per kW- yr
1016
1094
1196
764
823
899
Demand Response Price Bin 3
$77 per kW-yr 47 50 55
342
368
402
Demand Response Price Bin 4
$144 per kW-yr
697
752
822
395
426
465

8. Resource Adequacy as a Guide

9. Factors Driving the Pace for Demand Response Development
Need for seasonal capacity
Assumptions about conservation development
Assumptions about the availability and cost of external market resources in extreme weather and poor water conditions
Assumptions about further CO2 emissions reduction policies

10. Updated Scenario Analysis Shows Material Change In Demand Response Development Through 2021

11. Demand Response Deployment Probability in 2021 by Magnitude of Capacity Shortfall

12. Minimal New Gas Generation Development Across Scenarios, Except for the “No DR” Scenario

13. Balancing and Flexibility Curtailment Analysis FY 2021
Name of Scenario
Hydro Years
(out of 80)
Percent of Hydro Years
Total
Events
Existing System 37
46%
260
aMW Energy Efficiency 17
21% 38
aMW Energy Efficiency MW Demand Response 6 8% 14
aMW Energy Efficiency MW Demand Response 3 4% 8

14. System Cost and Economic Risk of Alternative Resource Strategies

15. Observations
Without developing the 7th Power Plan recommended energy efficiency and at least 600 MW of demand response the region may not meet adequacy standards and/or could have difficulty providing balancing reserves
Instead pursuing demand response, the region could build additional new gas-fired generation
However, this alternative resource strategy increases system cost by $4 billion and system risk by $5 billion

16. Questions?
Council’s DR Webpage:
RPM Online:
7th Power Plan Technical Data
DR supply curve derivation and potential study