PUGET SOUND ENERGY DEMAND RESPONSE POTENTIAL ASSESSMENT

Transcription

1 PUGET SOUND ENERGY DEMAND RESPONSE POTENTIAL ASSESSMENT DER INTEGRATION INTEREST GROUP 36 TH PLMA CONFERENCE CAMBRIDGE, MA NOVEMBER 13,

2 TOPICS Overview of PSE s Demand-Side Resource Assessment and IRP DR Potential Assessment Drivers for Demand Response (DR) Approach for Modeling DR Potential DR Potential Results Moving DR Forward A Strategic Vision for DR 2

3 DEMAND SIDE RESOURCE (DSR) ASSESSMENT AND IRP 3

4 2017 PSE DEMAND SIDE RESOURCE ASSESSMENT Conservation Potential Assessment (CPA) was conducted for all demand-side resources Measures were aggregated into cost bundles and input into PSE s IRP portfolio model Consistent with the Northwest Power and Conservation Council s methodology and its assessment of regional potential in the 7 th Power Plan 4

5 THE ANATOMY OF THIS DR POTENTIAL STUDY Utility/ Market Data Customer Forecasts Load Forecasts Prior DR Achievements Technical Potential Achievable Technical Potential Load Impacts Measure Life Technical Suitability DR Measure Data Customer Data Awareness of DR Need Willingness to Accept DR Offering Economic Potential Enablement Cost More DR Measure Data Cost-effective program bundles Integrated with other DERs IRP Process 5

6 CUMULATIVE ACHIEVABLE TECHNICAL POTENTIAL (WINTER PEAK DEMAND REDUCTION) ELECTRIC RESOURCES 6

7 DEMAND RESPONSE POTENTIAL ASSESSMENT 7

8 PSE S DEMAND RESPONSE EXPERIENCE Initial DR efforts in 2001 C&I and Residential pilots Restart DR efforts in Residential TOU Pilot Sch. 93 Vol. Curtailment C&I Load Control Pilot Residential DR Pilot C&I Load Control RFP Large C&I DR Assessment Smart Thermostat Program Interruptible Rates- Rider G (Schedules 43 and 46) 8

9 OBJECTIVES FOR DR RESOURCE ACQUISITION Primary objectives Avoid investment in generation capacity to meet demand during peak periods Fulfill operating reserve requirements Secondary objectives Address system emergency conditions Utilize energy arbitrage opportunities Enhance customer service Integrate emerging technologies 9

10 DR POTENTIAL ESTIMATION APPROACH Step 1: Market Characterization Characterize PSE s market for DR potential estimation at different levels: sector, customer class, building type, and end-use. Step 2: Develop Baseline Projections Develop baseline projections for customer count and load over the forecast horizon ( ) Step 3: Define DR Options and Characterize Step 4: Develop Key Assumptions for Potential & Costs Step 4: Estimate Potential and Costs Define and characterize DR Options/programs and map applicable options to relevant market segments. Develop participation and unit load reduction assumptions under each DR option by market segment and by end use; also develop itemized cost assumptions. Develop technical achievable potential estimates (winter & summer) by DR option, customer class, building type and end-use and associated levelized costs. 10

11 MARKET SEGMENTATION FOR DR ANALYSIS Level Description Level 1: By Sector Residential Commercial and Industrial (C&I) Residential Level 2: By Size Customer Class Level 3: By Building Type (under each C&I class) Level 4: By End-use (for each building type) C&I customers by size, based on maximum demand values:» Small C&I: <=50 kw maximum demand» Medium C&I: >50 kw, but <=150 kw maximum demand» Large C&I: >150 kw maximum demand (excluding customers under primary and high voltage service)» Extra Large C&I: Very large sized customers under primary and high voltage service Segmentation based on mapping of NAICS codes to building types. C&I segments are: Grocery, Hospital, Hotel, Office, Restaurant, Retail, School, University, Warehouse, Industrial. Disaggregation by end-use based on available end-use load shapes from PSE. Residential: central AC, electric central furnace, heat pump, electric water heating, others. C&I: HVAC, water heating, lighting, refrigeration, industrial process, others. 11

12 DR OPTIONS CONSIDERED IN THE STUDY DR Options Characteristics of DR Options Eligible Customer Classes Targeted/Controllable End uses Direct Load Control (DLC) Thermostat Load Control Switch C&I Curtailment Manual Auto-DR enabled Control of electric loads by a thermostat and/or load control switch. Firm capacity reduction commitment $/kw payment based on contracted capacity, plus $/kwh payment based on energy reduction during an event. Residential, Small C&I, Medium C&I Large C&I, Extra Large C&I Electric space heating (including heat pumps), electric water heating, cooling Various load types including- HVAC, Lighting, Refrigeration, industrial process loads. Economic DR Manual Auto-DR enabled No firm capacity commitment; voluntarily reduce load during events; only $/kwh payment for energy reduction; Large C&I, Extra Large C&I Various load types including- HVAC, Lighting, Refrigeration, industrial process loads. Dynamic Pricing Voluntary opt-in offer: With and without enabling technology Fast DR Only tech. enabled Peak Time Rebate for Residential. Critical Peak Pricing for C&I. Fast responding DR for providing ancillary services (with 10 minutes or less response time). All classes Customers enrolled in other programs with appropriate enabling technology. All Loads with fast responding capability. 12

13 KEY ASSUMPTIONS FOR POTENTIAL ESTIMATION Key Variables Dimension Participation Rates (% of eligible load) Impacts (% of participating load) Costs (unit varies depending on the type of cost) Percentage of eligible load by customer class and building type (also varies by average event duration). Percentage of participating load by customer class, building type and end-use (also varies by average event duration). One-time fixed costs related to program development. One-time variable costs for customer recruitment and program marketing, equipment installation and enablement. Recurring variable costs such as customer incentives, O&M, etc. Global Parameters Program Lifetime, Discount Rate, Inflation Rate, Line Losses. 13

14 DR POTENTIAL BY SEASON AND BY OPTION Winter DR potential reaches 188 MW by 2037 DLC has highest share in winter potential (~45%) C&I Curtailment and Dynamic Pricing have almost equal contribution (each with 25% share). Economic DR contribution is less than 10%. Summer DR potential is ~73% of winter potential (137 MW by 2037). Both DLC and C&I Curtailment have equal contribution (~33% each) in summer potential. o C&I Curtailment potential is ~5% higher in summer than winter. o DLC potential is ~45% lower in summer than winter. 14

15 DR POTENTIAL BY SUB-OPTION Top contributors to winter peak demand reduction are: Residential electric space heating control via thermostat. Dynamic pricing Auto-DR enabled C&I Curtailment. Top contributors to summer peak demand reduction are: CAC control Auto-DR enabled C&I Curtailment Dynamic pricing 15

16 DR POTENTIAL BY CUSTOMER CLASS Majority of the potential is from residential customers. Large and Extra Large C&I customers contribute a third of the total winter potential. SMB customers have less than 5% contribution. in winter potential. C&I customers (Large and Extra Large classes combined) have highest contribution in summer potential (~50% of the total summer potential in 2037). Potential from Small and Medium C&I customers in summer is approximately double of their winter potential. 16

17 DR POTENTIAL BY END USE Central electric air furnaces have highest contribution in winter DR potential (43% share at 80 MW in 2037), followed by Heat Pumps (16% share at 31 MW in 2037). Electric water heating and lighting each have ~15% share Share of industrial load is ~5% in 2037 winter DR potential. Cooling estimated to provide more than half of the total summer reduction potential. Second highest contributor to summer DR potential is lighting (18% share in total). Industrial loads, heat pumps, and electric water heating, each have less than 10% share in summer load reduction potential. 17

18 DR POTENTIAL BY SEASON AND BY OPTION (ACCELERATED SCENARIO) Winter Demand Response Achievable Potential 4 Hr Event Duration (MW) Considered an accelerated DR scenario with a linear three-year ramp instead of a fiveyear S-shaped ramp. MW Dynamic pricing participation is also assumed to ramp up in three years from 2023 onward. MW Direct Load Control Dynamic Pricing C&I Curtailment Economic DR Summer Demand Response Achievable Potential 4 Hr Event Duration (MW) Direct Load Control Dynamic Pricing C&I Curtailment Economic DR The accelerated scenario leads to substantial increase in potential in the early years ( ; ), when compared with the regular DR scenario. Under the accelerated scenario, winter 2021 estimated potential is ~10% higher at 133 MW vs. 120 MW under the regular DR scenario. Also, 2025 potential under accelerated scenario is 10% higher than the regular scenario due to faster ramp up in dynamic pricing. 18

19 LEVELIZED COSTS DR Option Levelized Costs ($/kw-season) for Winter 2037 Achievable Technical Potential (MW) Direct Load Control $ C&I Curtailment $ Economic DR $72 15 Dynamic Pricing $64 47 Dynamic pricing is the least cost option with 25% share in total potential C&I Curtailment has approximately the same contribution as dynamic pricing but at significantly higher cost DLC costs lower than C&I Curtailment and has highest potential Economic DR with lowest potential has moderate costs 19

20 20 MOVING DR FORWARD A STRATEGIC VISION FOR DR

21 DR PROGRAM PORTFOLIO ROLLOUT PLAN 21

22 POSSIBLE FUTURE STATE: CUSTOMER DISTRIBUTED ENERGY RESOURCES STRUCTURE Future vision for DR under an integrated DER framework DR considered an additional resource type along with other DSRs (EE, customer-side storage and distributed generation). The future structure would require interactions across many different groups. 22

23 STRATEGIC VISION FOR DR : New DR pilots/programs and rate offerings; AMI/Smart Grid enable greater control, price-responsiveness and customer engagement : DR strategic planning and resource acquisition : Deployment of Direct Load Control and C&I Curtailment programs and beyond: Long-term program portfolio will evolve with technology and system needs. 2017: IRP establishes the contribution from DSR, including DR 23

24 GREG WIKLER Managing Director Navigant Consulting 101 California Street, Suite 4100 San Francisco, CA