PUGET SOUND ENERGY DEMAND RESPONSE POTENTIAL ASSESSMENT · applicable options to relevant market segments. Develop participation and unit load reduction assumptions under each DR

/ ©2017 NAVIGANT CONSULTING, INC. ALL RIGHTS RESERVED1

DER INTEGRATION INTEREST GROUP36TH PLMA CONFERENCECAMBRIDGE, MA

PUGET SOUND ENERGYDEMAND RESPONSE POTENTIAL ASSESSMENT

NOVEMBER 13, 2017

/ ©2017 NAVIGANT CONSULTING, INC. ALL RIGHTS RESERVED2 / ©2017 NAVIGANT CONSULTING, INC. ALL RIGHTS RESERVED2

• 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

TOPICS


DEMAND SIDE RESOURCE (DSR) ASSESSMENT AND IRP


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 7th Power Plan


THE ANATOMY OF THIS DR POTENTIAL STUDY

Technical Potential

Achievable Technical Potential

Economic Potential

• Customer Forecasts

• Load Forecasts• Prior DR

Achievements

Utility/Market Data

• Awareness of DR Need

• Willingness to Accept DR Offering

Customer Data

DR Measure

Data

• Load Impacts• Measure Life• Technical

Suitability

More DR Measure

Data

• Enablement Cost

IRP Process

• Cost-effective program bundles

• Integrated with other DERs


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


DEMAND RESPONSE POTENTIAL ASSESSMENT


PSE’S DEMAND RESPONSE EXPERIENCE

2001 2008 201620102009 2011 2015

Residential TOU Pilot

Sch. 93 Vol. Curtailment

2002

C&I Load Control Pilot

Residential DR Pilot

Large C&I DR Assessment

Smart Thermostat Program

C&I Load Control RFP

• Initial DR efforts in 2001• C&I and Residential pilots 2008-11• Restart DR efforts in 2015

Interruptible Rates- Rider G (Schedules 43 and 46)


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


DR POTENTIAL ESTIMATION APPROACH

Develop technical achievable potential estimates (winter & summer) by DR option, customer class,

building type and end-use and associated levelized costs.

Characterize PSE’s market for DR potential estimation at different levels: sector, customer class, building

type, and end-use.

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 baseline projections for customer count and load over the forecast horizon (2018-2037)

Step 4: Estimate Potential and Costs

Step 4: Develop Key Assumptions for Potential & Costs

Step 3: Define DR Options and Characterize

Step 2: Develop Baseline Projections

Step 1: Market Characterization


MARKET SEGMENTATION FOR DR ANALYSIS

Level Description

Level 1: By Sector• Residential• Commercial and Industrial (C&I)

Level 2: By Size Customer Class

• Residential

• 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

Level 3: By Building Type(under each C&I class)

Segmentation based on mapping of NAICS codes to building types.

C&I segments are: Grocery, Hospital, Hotel, Office, Restaurant, Retail, School, University, Warehouse, Industrial.

Level 4: By End-use (for each building type)

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.


DR OPTIONS CONSIDERED IN THE STUDY

DR Options Characteristics of DR Options Eligible CustomerClasses

Targeted/ControllableEnd uses

Direct Load Control (DLC) Thermostat Load Control Switch

Control of electric loads by a thermostat and/or load control switch.

Residential, Small C&I, Medium C&I

Electric space heating (including heat pumps), electric water heating, cooling

C&I Curtailment Manual Auto-DR enabled

Firm capacity reduction commitment$/kW payment based on contracted capacity, plus $/kWh payment based on energy reduction during an event.

Large C&I, Extra Large C&I

Various load types including-HVAC, Lighting, Refrigeration, industrialprocess 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, industrialprocess loads.

Dynamic Pricing With and without

enabling technology

Voluntary opt-in offer:• Peak Time Rebate for Residential.• Critical Peak Pricing for C&I.

All classes All

Fast DR Only tech. enabled

Fast responding DR for providing ancillary services (with 10 minutes or less response time).

Customers enrolled in other programs with appropriate enabling technology.

Loads with fast responding capability.


KEY ASSUMPTIONS FOR POTENTIAL ESTIMATION

Key Variables Dimension

Participation Rates(% of eligible load)

Percentage of eligible load by customer class and building type(also varies by average event duration).

Impacts(% of participating load)

Percentage of participating load by customer class, building type and end-use (also varies by average event duration).

Costs(unit varies depending on the type of cost)

• 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.


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.


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


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.


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.


DR POTENTIAL BY SEASON AND BY OPTION (ACCELERATED SCENARIO)

• Considered an accelerated DR scenario with a linear three-year ramp instead of a five-year S-shaped ramp.

• Dynamic pricing participation is also assumed to ramp up in three years from 2023 onward.

• The “accelerated” scenario leads to substantial increase in potential in the early years (2018-2021; 2023-2025), 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.

0

50

100

150

200

MW

Winter Demand Response Achievable Potential 4 Hr Event Duration (MW)

Direct Load Control Dynamic Pricing C&I Curtailment Economic DR

0

50

100

150

200

MW

Summer Demand Response Achievable Potential 4 Hr Event Duration (MW)

Direct Load Control Dynamic Pricing C&I Curtailment Economic DR


LEVELIZED COSTS

DR Option Levelized Costs ($/kW-season) for Winter

2037 Achievable Technical

Potential (MW)Direct Load Control $118 83C&I Curtailment $137 43Economic DR $72 15Dynamic 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


MOVING DR FORWARD –A STRATEGIC VISION FOR DR


DR PROGRAM PORTFOLIO ROLLOUT PLAN


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.


STRATEGIC VISION FOR DR

2017: IRP establishes the contribution from DSR, including DR

2017-2018: DR strategic planning and resource acquisition.

2018-2022: Deployment of Direct Load Control and C&I Curtailment programs.

2023-2026: New DR pilots/programs and rate offerings; AMI/Smart Grid enable greater control, price-responsiveness and customer engagement

2026 and beyond: Long-term program portfolio will evolve with technology and system needs.


GREG WIKLERManaging DirectorNavigant Consulting101 California Street,Suite 4100San Francisco, CA [email protected]

mailto:[email protected]

Documents

PUGET SOUND ENERGY DEMAND RESPONSE POTENTIAL ASSESSMENT · applicable options to relevant market segments. Develop participation and unit load reduction assumptions under each DR