VERMONT PUBLIC SERVICE DEPARTMENT · transmission planning, new transmission costs would begin in...

VERMONT PUBLIC SERVICE DEPARTMENTRATE DESIGN INITIATIVE / DISTRIBUTED ENERGY RESOURCES STUDYSTAKEHOLDER ENGAGEMENT MEETING #3

April 16, 2020

NEWGEN STRATEGIES AND SOLUTIONS, LLC

VERMONT RATE DESIGN INITIATIVELSAM™ AND THE VT RATE DESIGN INITIATIVE

• LSAM™ allows iteration of input assumptions to evaluate a multitude of future states of the electric market in Vermont

Future electric usage will vary vis-à-vis market forces, decarbonization, and technology adoption

• LSAM™ allows the user to manage system peaks through

Electric rates to send price signals to manage load

• Static and dynamic rate design

• Behavioral change, technology adoption, or both

Directly manage load through flex capacity

Controllable flex load “calls”, timing and duration

2


VERMONT RATE DESIGN INITIATIVELSAM™ UPDATE – SINCE LAST STAKEHOLDER MEETING

• Updated demand elasticity

• Carbon accounting refinement

• “Dynamic” rate design

• Increased detail on Utility Cost Key Performance Indicators (KPIs)

• Increased model functionality from stakeholder feedback

3




RAP/Brattle survey of Critical Peak Pricing (CPP) / Time-of-Use (TOU) program elasticity for non-electric vehicle (EV) loads

4

0%

5%

10%

15%

20%

25%

30%

35%

0% 200% 400% 600% 800% 1000%

Pea

k R

edu

ctio

n

On-Peak to Off-Peak Pricing Differential

RAP Report – Elasticity of Electric Demand

Price Only Technology




RAP/Brattle survey of Critical Peak Pricing (CPP) / Time-of-Use (TOU) program elasticity for non-electric vehicle (EV) loads

EV short-run elasticity is assumed to be substantially greater, per Department of Energy (DOE) EV Project

5

0%

20%

40%

60%

80%

100%

120%

0% 200% 400% 600% 800% 1000%

Pea

k R

edu

ctio

n

On-Peak to Off-Peak Pricing Differential

RAP + DOE (EV) Elasticities

Price Only Technology EV-Specific Elasticity



• Carbon accounting refinement

Feedback from EAN Vermont

Increased detail on accounting for current space / water heating fuel portfolio

• Feedback from Biomass Energy Resource Center (BERC)

6

(3,000,000)

(2,500,000)

(2,000,000)

(1,500,000)

(1,000,000)

(500,000)

-

2017 2021 2025 2029 2033 2037

MET

RIC

TO

NN

S C

O2

CO2 Emissions Savings Sector/Year

EV Savings Vermont Renewables Savings Electrified Space/Water Heating Savings



• Dynamic rate design

Critical Peak Pricing (CPP)

• Regional Network Service (RNS) annual capacity costs moved into an energy rate to be “called” by the model user up to 60 times in a modeled year

Real-Time Pricing

• Passes-through 2018 actual ISO-NE hourly Day-Ahead energy charges to the customer

• Rate design is separated for EV and non-EV load

7



• Increased detail on Utility Cost KPIs RNS-Related Bulk Transmission Costs

• Embedded costs – current RNS rate forecast from Vermont Department of Public Service (PSD)

• Marginal costs – for incremental system peaks above 1,100 MW

VELCO providing feedback on $/MW of new capacity above embedded costs / RNS rate

Incremental Distribution Capacity Costs• Feedback from GMP and VEC on costs

of substantial new load on distribution system

8

-

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2018 2022 2026 2030 2034 2038

Meg

awat

ts

Vermont Modeled Forecast Peak Demand

Current Trans. Capacity Incremental Trans. Capacity



• Increased model functionality from stakeholder feedback

New inputs• New rate implementation assumptions:

% of customers participating in new rate

• Discrete EV adoption inputs, % of vehicles that are EV in 2030 and 2040

• Discrete electric combined cooling, heat and power (CCHP) and heat pump hot water inputs (kWh/yr and % adoption)

• Incremental impacts of rates / flex load:

2018 baseline

Including Tech but no rates / flex load

Including Tech but with rates / flex load

9


VERMONT RATE DESIGN INITIATIVE – WORKSHOP 3

• Introduction

• Panel Discussion 1

Policymaking and planning in the context of VT electric market evolution

• NewGen presentation on LSAM™ modeling and innovative rate design

• Panel Discussion 2

Implementation challenges of electric rate innovation

10

PANEL DISCUSSION 1UTILITY PLANNING FOR THE FUTURE AND THE STATE’S OBJECTIVES

DYNAMIC RATES AND FRAMEWORK FOR EVALUATING FUTURE OPTIONS

RATE DESIGN INITIATIVE / DISTRIBUTED ENERGY RESOURCES STUDYSTAKEHOLDER ENGAGEMENT MEETING #3

13NEWGEN STRATEGIES AND SOLUTIONS, LLC

UTILITIES INCUR COSTS DIFFERENTLY BY UTILITY FUNCTION

13


OVERVIEW OF LSAM™ “UTILITY COST KPIS”

14

Local Distribution System(s)

ISO-NE Power Supply Costs

Bulk TransmissionRegional Network Service (RNS)


REGIONAL NETWORK SERVICE (BULK TRANSMISSION)

• Bulk Transmission is pooled in New England

Vermont is charged for average of state’s aggregate peak load per month

• Future RNS costs depend on several factors:

Total transmission costs in pool

Regional transmission rate design

Vermont load

15

VELCO: Vermont’s system can handle ~1,200 MW without new investment, but for long-term planning, new investment is

needed in the 1,100-1,150 MW range

23.9%

19.2%

26.9%

21.5%

29.9% 28.4%

0%

5%

10%

15%

20%

25%

30%

880

920

960

1,000

1,040

1,080

1,120

1,160

1,200

2008 2010 2012 2014 2016 2018

% In

crea

se t

o 1

,20

0 M

W

Me

gaw

atts

Year

Vermont Peak Load and Excess RNS Capacity


REGIONAL NETWORK SERVICE (BULK TRANSMISSION)

• For this study, we assume the regional transmission pool = Vermont

Capacity has headroom (~28%)

Transmission rate design remains constant

• Vermont load incurs transmission costs in two ways:

Load <1,100 MW billed forecast RNS rate

Load >1,100 MW billed incremental $/MW• Assumed $94/kW-year from updated

screening tool values used for Efficiency Vermont, which was comparable to VELCO levelized cost

16

VELCO: Vermont’s system is built for ~1,200 MW without new investment, but due to long-term nature of

transmission planning, new transmission costs would begin in the 1,100-1,150 range

-

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2018 2022 2026 2030 2034 2038

Meg

awat

ts

Vermont Modeled Forecast Peak Demand

Current Trans. Capacity Incremental Trans. Capacity


OVERVIEW OF LSAM™ “UTILITY COST KPIS”

17





VERMONT RATE DESIGN INITIATIVELSAM™ UPDATE – SINCE LAST STAKEHOLDER MEETING• Increased detail on incremental Distribution

capacity costs Feedback from GMP and VEC on costs of

substantial new load on distribution system

• Cost estimate currently under further review

• Cost does not currently include cost of upgrading nearly all poll transformers, currently <10 kVA

~$1,400/transformer, ~1,000 transformers on 10 evaluated circuits

18

1. Conductor is priced $200k/mi, with each overloaded conductor event equating to 250 ft. of conductor

$240.00

$250.00

$260.00

$270.00

$280.00

$290.00

$300.00

$310.00

$-

$20,000,000

$40,000,000

$60,000,000

5,000 65,000 125,000 185,000

$/kW

Incr

emen

tal L

oad

Gro

wth

$To

tal

kW Incremental Load Growth

Cost of Incremental Dist. Upgrades

Fuses Conductor Regulator Recloser $/kW

GMP Data

Dist. Element $/Overload

Fuses $400

Conductor1 $9,470

Regulator $130,000

Recloser $50,000


REFINED “UTILITY COST KPIS” FOR LSAM

19


• Capacity: Highly Specific to Utility and Specific Location

• Calculated: ~$300/kW


• Embedded Capacity: ~$110-$200/kW-yrAvg. of 12 Monthly Peaks

• Incremental Capacity: $94/kW-yr >1,100 (2020)


• Energy: ~$0.03-$0.07/kWhDepending on Timing

• RES Compliance: ~$1.50-$12.00/MWh over period

• Capacity: ~$6-$7/kWhDuring 1 ISO-NE CP Hour

Important Note: LSAM Utility Cost KPIs

do not make up the entirety of VT utilities’ revenue requirements


CALCULATING “UTILITY COST KPIS” FOR LSAM

Component Billing Determinants and Forecast Cost Basis

ISO-NE Capacity VT Demand during ISO-NE CP Time x Forecast Forward Capacity Price

ISO-NE Energy All Purchased Energy from ISO-NE x Forecast All-In Energy Rate

RES Compliance Costs All Purchased Energy from ISO-NE x RES % x Forecast REC Price

RNS Capacity (Embedded Costs) Average Total VT Monthly Peak Demand x Forecast RNS Capacity Rate

Incremental Bulk Transmission Cost Incremental Annual Peak Demand (>1,100MW) x Incremental Trans. Cost

Incremental Distribution Cost Incremental Annual Peak Demand (>2018 Baseline) x ~$300/kW + infl.

20


LSAM™ SCENARIO ANALYSIS – KEY ASSUMPTIONS/OUTPUTSPROVIDED FOR ILLUSTRATIVE PURPOSES

21

-

50,000

100,000

150,000

200,000

250,000

300,000

350,000

2013 2017 2021 2025 2029 2033 2037

TOTA

L EV

S

EV Adoption Forecast

0%

20%

40%

60%

80%

100%

2019 2023 2027 2031 2035 2039

Assumed EV Chargers by Voltage

1.8 kW 7.2 kW 12 kW

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

KIL

OW

ATT

S -

DC

PV Adoption (Actual + Forecast)

Forecast

-

50,000

100,000

150,000

200,000

2017 2021 2025 2029 2033 2037

TOTA

L U

NIT

S

Electrification Adoption Forecast

Cold Climate Heat Pumps Electric Hot Water

Forecast

Forecast

PV Policy:

Offsetting onsite load credited at

retail;

Excess generation credited at $0.09/kWh,

trued-up hourly

EV Adoption:

20% of all consumer

vehicles by 2030

50% of all consumer

vehicles by 2040

10% of vehicles

have access to at-work charging

Elec. Adoption:

CCHP: 20% by 2030

H2O: 5% by 2030

CCHP: 50% by 2040

H2O: 10% by 2040

EV Charger Voltage:

Reasonable assumptions based on currently available models,

assumed to increase in

voltage over time

Illustrative Scenario


$-

$100,000

$200,000

$300,000

$400,000

$500,000

$600,000

2020 2025 2030

$000

Add Technology Adoption

ISO-NE Capacity ISO-NE Energy

RES Compliance Costs RNS Capacity (Embedded Costs)

Incremental Bulk Transmission Cost Distribution Capacity

$-

$100,000

$200,000

$300,000

$400,000

$500,000

$600,000

2020 2025 2030

$000

2018 Baseline w/ 0.5% Growth




COMPARISON BETWEEN MODELED SCENARIOSBASELINE VS. INCLUDING TECHNOLOGY ADOPTION - 2030

22

3.2% CAGR

5.1% CAGR


$-

$200,000

$400,000

$600,000

$800,000

$1,000,000

$1,200,000

$1,400,000

2020 2025 2030 2035 2040

$000





$-

$200,000

$400,000

$600,000

$800,000

$1,000,000

$1,200,000

$1,400,000

2020 2025 2030 2035 2040

$000






23

3.8% CAGR

7.1% CAGR



24

22.1%, $101,458

78.9%, $510,849

$0

$200,000

$400,000

$600,000

$800,000

$1,000,000

$1,200,000

$1,400,000

Base w/ Tech Base w/ Tech Base w/ Tech Difference Base w/ Tech Base w/ Tech Difference

2020 2025 2030 2030 2035 2040 2040

$0

00

ISO-NE Capacity ISO-NE Energy RES Compliance Costs RNS Capacity (Embedded Costs)

Incremental Bulk Transmission Cost Incremental Dist. Capacity Cost Total Base Total Tech



25

-

1,000,000

2,000,000

3,000,000

4,000,000

5,000,000

6,000,000

7,000,000

$-

$200,000

$400,000

$600,000

$800,000

$1,000,000

$1,200,000

$1,400,000

2020 2025 2030 2035 2040

Ret

ail E

ner

gy (M

Wh

)

$000





Retail Energy - Base

-

1,000,000

2,000,000

3,000,000

4,000,000

5,000,000

6,000,000

7,000,000

$-

$200,000

$400,000

$600,000

$800,000

$1,000,000

$1,200,000

$1,400,000

2020 2025 2030 2035 2040

Ret

ail E

ner

gy (M

Wh

)

$000





Retail Energy - Tech


$-

$0.02

$0.04

$0.06

$0.08

$0.10

$0.12

$0.14

$0.16

$0.18

$0.20

2020 2025 2030 2035 2040

$/kW

h

Average Rate (Cost KPIs / Retail Energy Sales)

Avg. Rate - Base Avg. Rate - Tech

OPTIONS TO MANAGE UPWARD RATE PRESSURE

• Increasing electrification drives both new utility revenues and costs

LSAM™ modeling suggests costs outpace revenue growth

• Options to manage upward rate pressure:

“Pay the bill”

• Continue to buy capacity/energy from the “market”

“Acquire” capacity and energy in other ways

26

2.8% CAGR

4.8% CAGR


FUTURE VERMONT CAPACITY PROCUREMENT

Wholesale-Side Management

• Generation

ISO-NE Capacity

VT Utility-Owned Gen/Storage

• Transmission

RNS Capacity Cleared in Market

VT Utility-Owned Gen/Storage

Load-Side Management

• Sources of controllable load

EV

Industrial/Lg. Commercial

Residential

Energy storage

• Control

Direct: Utility, Third-Party

Indirect: Customer (Rate Design)

27


FUTURE VERMONT CAPACITY PROCUREMENT

Wholesale-Side Management

• Sources of controllable load

EV

Industrial/Lg. Commercial

Residential

Energy storage

• Control

Direct: Utility, Third-Party

Indirect: Customer (Rate Design

Customer Load Control – Rate Design

• Static Rate Design

Non-TOU

TOU

• Demand, Energy

• Seasonal

• Tiered

• Dynamic Rate Design

Real-Time Pricing (RTP)

Critical Peak Pricing (CPP)

28

BREAK FOR LUNCH11:30 – 12:30 EST

DYNAMIC RATES AND FLEXIBLE LOADS TO MANAGE UTILITY COST KPIS


31NEWGEN STRATEGIES AND SOLUTIONS, LLC

INNOVATIVE RATE DESIGN

31


INNOVATIVE RATE DESIGN AND IMPLEMENTATION CHALLENGES

• Without management, increasing electrification will drive an increase in capacity costs outpacing increased revenue

• Rates can serve as a resource in managing loads, but challenges exist:

Efficacy in managing loads requires:

• Higher enrollment in innovative rates / programs

Regulatory mandates

Self-selecting enrollment

Other options?

• Customers changing usage patterns

Third-party and/or technology facilitation

32


RATE DESIGN COMPLEXITY, EFFICACY & RESPONSIVENESS STATUS

Rate Design Enrollment Pricing StrategyComplexity to

CustomerEfficacy in Managing

LoadResponsiveness to

Rapid Market Evolution

Static Rate Design

Non-TOU Status Quo Status Quo

TOU High Aggressive

Mid Less-Aggressive

Low Less-Aggressive

Dynamic Rate Design

Real-Time Pricing High Market pass-through

Low Market pass-through

Critical Peak Pricing High Aggressive

Mid Less-Aggressive

Low Less-Aggressive

33

/

/

/


RATE DESIGN COMPLEXITY, EFFICACY & RESPONSIVENESS STATUS – FILTERED FOR EFFICACY

Rate Design Enrollment Pricing StrategyComplexity to

CustomerEfficacy in Managing

LoadResponsiveness to

Rapid Market Evolution

Static Rate Design

TOU High Aggressive

Dynamic Rate Design

Real-Time Pricing High Market pass-through

Critical Peak Pricing High Aggressive

34

/

/

Aggressive pricing in which there are substantial customer “winners and losers” will not result in high

rates of voluntary enrollment

Higher enrollment can stem from:1. Regulatory mandate2. “Opt-Out” structure3. Third-Party load management

Mandates are challenging with more aggressive pricing/greater efficacy

“Opt-Out” and Third-Party unlikely to get as much enrollment

/

PANEL DISCUSSION 2UTILITY PLANNING FOR THE FUTURE AND THE STATE’S OBJECTIVES

ADDITIONAL SCENARIO MODELING:THE MODELED VALUE OF INNOVATIVE RATES



LSAM™ MODELED SCENARIO

• Tech adoption assumptions previous employed

PV adoption based on updated NM policy

EV adoption

• 20% of vehicles by 2030; 50% by 2040

Electric space and water heating

• CCHP: 20% of Residential by 2030, 50% by 2040

• Heat pump H20: 5% of Residential by 2030, 10% by 2040

37



38

22.1%, $101,458

78.9%, $510,849

$0

$200,000

$400,000

$600,000

$800,000

$1,000,000

$1,200,000

$1,400,000

Base w/ Tech Base w/ Tech Base w/ Tech Difference Base w/ Tech Base w/ Tech Difference

2020 2025 2030 2030 2035 2040 2040

$0

00


Incremental Bulk Transmission Cost Incremental Dist. Capacity Cost Total Base Total Tech

Up

ward

Pre

ssure


LSAM™ MODELED SCENARIOSTRATEGIC RATE DESIGN

• Static TOU Rates

EV charging rates set with 3-4 hour on-peak evening window

• On-Peak rate is current otherwise effective energy rate

• Off-Peak rate is set to 2/3 of On-Peak rate

• Up to 24 flexible load events “called,” with capacity ½ max EV load

Duration of 4 hours, limited at one/day

• RNS capacity costs recovered through Critical Peak Events

Up to 5x per month, with duration of 4 hours, limited at one/day

39


COMPARISON BETWEEN MODELED SCENARIOSTECHNOLOGY ADOPTION FUTURE VS. TECH W/ RATES - 2040

40

-9.0%, $50,324

-12.8%, $148,286

$0

$200,000

$400,000

$600,000

$800,000

$1,000,000

$1,200,000

$1,400,000

Tech w/ Rates w/ Tech Tech w/ Rates w/ Tech Tech w/ Rates w/ Tech Difference Tech w/ Rates w/ Tech Tech w/ Rates w/ Tech Difference

2020 2025 2030 2030 2035 2040 2040

$0

00


Incremental Bulk Transmission Cost Incremental Dist. Capacity Cost Total Tech w Rates Total Tech

Do

wn

ward

Pre

ssure


COMPARISON BETWEEN MODELED SCENARIOSTECHNOLOGY ADOPTION FUTURE VS. TECH W/ RATES, AT-WORK EV - 2040

41

-9.0%, $50,324

-12.8%, $148,286

$0

$200,000

$400,000

$600,000

$800,000

$1,000,000

$1,200,000

$1,400,000

Tech w/ Rates w/ Tech Tech w/ Rates w/ Tech Tech w/ Rates w/ Tech Difference Tech w/ Rates w/ Tech Tech w/ Rates w/ Tech Difference

2020 2025 2030 2030 2035 2040 2040

$0

00


Incremental Bulk Transmission Cost Incremental Dist. Capacity Cost Total Tech w Rates Total Tech

-4.4%, $50,000

50% At-Work EV Charging

Do

wn

ward

Pre

ssure

CONCLUSIONS AND KEY TAKEAWAYSRATE DESIGN INITIATIVE / DISTRIBUTED ENERGY RESOURCES STUDY

STAKEHOLDER ENGAGEMENT MEETING #3


CONCLUSIONS AND KEY TAKEAWAYS

• Electric market evolution will exert upward rate pressure

CAGR of 4.8% vs. 2.8% (Base)

• Innovative rates can send price signals for customers to change usage and manage costs

Initial modeled savings $150M-$200M

43

$-

$0.02

$0.04

$0.06

$0.08

$0.10

$0.12

$0.14

$0.16

$0.18

$0.20

2020 2025 2030 2035 2040

$/kW

h

Average Rate (Cost KPIs / Retail Energy Sales)

Avg. Rate - Base Avg. Rate - Tech Avg. Rate - Tech w/ Rates

2.8% CAGR

4.8% CAGR

4.2% CAGR


CONCLUSIONS AND KEY TAKEAWAYS

• There are challenges in implementing innovative rates:

Increased complexity to the customer

Efficacy in reducing peaks

Program enrollment

Regulatory approval

Third-party participation

44


NEXT STEPS

45

THANK YOU FOR YOUR PARTICIPATION!

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