Panel Discussion: Policy and Planning

Henry Yoshimura

Director, Demand Resource Strategy ISO New England

Henry Yoshimura D I R E C T O R , D E M A N D R E S O U R C E S T R A T E G Y

EBC Renewable Energy Program

The promise of Smart Grid—what does it mean for renewables?

Policy and Planning Panel

The Past, Present, and Future of Demand Resources in New England

J U N E 2 1 , 2 0 1 3 | B O S T O N , M A

Energy Efficiency a Priority for New England Capacity market coupled with state policies have produced robust EE investment

• Ranking of state EE efforts by the American Council for an Energy-Efficient Economy :

– Massachusetts 1

– Vermont 5

– Connecticut 6

– Rhode Island 7

– New Hampshire 18

– Maine 25

• Billions spent over the past few years; more on the horizon – Approximately $1 billion invested from 2008 to 2010

– ISO estimates $5.7 billion to be invested in EE from 2015 to 2021

3

Impact on New England Demand: Energy Demand Flat, Peak Demand Still Growing (but at a Lower Rate)

4

130000

135000

140000

145000

150000

155000

2012 2014 2016 2018 2020 2022

RSP12 RSP12-FCM RSP12-FCM-EEF

New England: Annual Energy (GWh)

28000

29000

30000

31000

32000

33000

34000

35000

2012 2014 2016 2018 2020 2022

RSP12 RSP12-FCM RSP12-FCM-EEF

New England: Summer 90/10 Peak (MW)

PRD Can Further Improve Market Performance

• What is Price Responsive Demand (PRD)? – Consumers change consumption in real time, in response to changes

in wholesale power prices – Use more energy when prices are low and less when prices are high

• What are the benefits? – Increase in system productivity (capacity utilization) by reducing

peak and increasing off-peak use • Demand Response, Distributed Generation, Storage, Electric Vehicles,

– Reduce customer electricity bills • Reduces risk premiums in rates • Uses actionable information to help customers manage energy costs • Reduces peak- period wholesale prices • Eliminates cross-subsidies in rates

– Treat customers as customers • Avoids treating customers as suppliers with obligations • Avoids estimating customer baselines • Supports retail choice—services customized to each customer

5

Progress Has Been Made … But Additional Things Can be Done

• While enormous progress has been made …

• … Retail pricing, with very few exceptions, has retained its non-dynamic, average cost reflective characteristics

6

Barriers to Customer Response to Prices

• Most New England states lack advanced metering infrastructure and associated tools to assist customers to respond to prices – Results in basic/default service being based on a uniform

rate • Consumers cannot benefit from changing their consumption levels

in response to changing real-time wholesale energy prices • Smart grid technology makes little sense under uniform retail rates

– Limits ability of retail suppliers to offer other retail products – Limits the ability of consumers to evaluate other retail

products (e.g., dynamic retail offers) or the cost-effectiveness of smart grid investment opportunities

7

Challenges to Investment in a Smarter Grid

• Utility distribution companies risk disallowance of cost recovery associated with improved infrastructure investments – Use of historic test year

• Incremental benefits of improved infrastructure accrue mostly to customers and society, not to the utility – Savings in utility operating costs may have already been captured

through infrastructure upgrades with limited functionality made at the time of industry restructuring

– Customers benefit from service improvement and bill reductions – Society benefits from an improved environment

8

What Can be Done to Breakdown the Barriers?

• Revise the ratemaking process so as to encourage broader, more forward thinking concerning the future electric grid

• Conduct comprehensive analysis of the benefits and costs of advanced metering and other infrastructure improvements

• Comprehensive stakeholder discussions and participation needed

9

In Conclusion…

• Capacity market payments helped stimulate Demand Resource growth

• ~$650 M (Jan ‘07 – May ’13)

New England Demand Resource

Growth in MW

Past Present

Savings from

reduced LMPs

Payment 0

10

20

30

40

50

60

Oct 2010 - Sept 2011

• ISO implements “smart-grid” system

• Monitor and dispatch demand response in real-time by location

• Dispatch similar to generation: when and where needed

• Facilitates aggregation

Future

Estimated Cost Savings: Demand

Response Millions $

• Full integration of demand response into capacity, energy, and ancillary service markets

• Advanced metering and communications

• Dynamic retail rates

• Automated load control

• Distributed generation

• Energy storage (and EVs)

• All customers enabled to provide demand response

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

APPENDIX Additional Information

About ISO New England

12

• Private not-for-profit

• Regulated by the federal government

• Independent of companies doing business in market

• Administer competitive

wholesale electricity markets

• Operate transmission system

• Plan for long-term system needs

New England’s Electric Power Grid at a Glance

• 6-state region

• 14 million residents; 6.5 million meters

• 350+ generators

• 37,000 MW of resources with capacity supply obligations – 32,000 MW generation – 2,900 MW demand resources – 1,900 MW imports

• 8,400 miles of transmission

• 28,130 MW all-time peak demand

13

Targets for Renewable Resources Increase Significantly over Next Decade

• Renewable targets projected to increase from 10% in 2010 to 18% in 2020 – Adding Energy Efficiency

increases target to 30%

• 18% of total New England energy in 2020 is equivalent to: – 9,400 MW of wind capacity, or – 3,300 MW of biomass capacity

18%

82%

Renewable Targets as % of Energy in New England (2020)

Energy from state renewable targets

Energy from other sources

14

New Opportunities for Regional Consumers to Benefit from Demand Response and Smart Grid

• On June 1, 2010, ISO implemented the Forward Capacity Market (FCM) – Demand resources now represent

approximately 10% of capacity supply obligation

– Demand resources include demand response, distributed generation, energy efficiency

• New infrastructure developed to securely communicate dispatch instructions, and receive near real-time telemetry and revenue-quality meter data from active demand response capacity resources

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000Demand Resources (MW)

FCM

15

Payments to Demand Response 2011 and 2012

Capacity Payments,

$187

DALRP & RTPR, $8

TPRD, $2

$ Million

16

• Through the regional wholesale electricity markets, demand response has been paid approximately $200 million over the past two years

Regional price response programs

Expanding Demand Resource Opportunities in Region Moving toward greater integration into regional electricity markets

Currently

• Demand resources can sell demand reduction capability in the FCM and receive payments comparable to generation resources

• Opportunities for customers to purchase electricity from the wholesale energy market at wholesale energy prices

Long-Term Goal

• Fully integrate demand response into energy, capacity, and ancillary markets

• Support state efforts to encourage demand response through the implementation of advanced metering, monitoring/control infrastructure, dynamic retail rates

17

Smarter Grid Allows Customers to Use Energy More Wisely While Saving Money

18

G3 Basic Service: $38,133.81

Real-Time Price:

$24,367.70

One-Month Savings: 36%

Customer Savings Under Real-Time Prices Exceed Full-LMP Payment For Demand Response

19

Rate

Class

Basic

Service

Real-Time

Price

("RTP") Savings

RTP with

Price

Response Savings

Basic Service

With Full LMP

Payment for

Price Response Savings

R1 4,043$ 3,533$ 13% 3,284$ 19% 3,678$ 9%

G1 8,190$ 7,247$ 12% 6,742$ 18% 7,455$ 9%

G2 124,378$ 106,217$ 15% 98,871$ 21% 113,330$ 9%

G3 1,370,674$ 1,140,709$ 17% 1,064,680$ 22% 1,255,703$ 8%

Comparison of Typical Customer Bills Under National Grid Basic Service and Real-Time

Price (NEMA Load Zone) -- January 1, 2005 to December 31, 2009

Note: This comparison includes generation commodity only – state-regulated wires charges (i.e., T&D costs) are not included

Region Lacks Advanced Metering Infrastructure

20

ME

CT RI

MA

VT

NH

State AMI

Meters (000)

Total Meters (000)

% AMI

% Regional KWh Sales

ME 671 1,373 49 9

NH 77 743 10 9

CT 101 2,045 5 25

MA 71 3,385 2 46

RI 0 477 0 6

VT 0 398 0 5

Region 920 8,421 11 100

Advanced Meter Penetration (2012)*

Comparison of AMI Penetration

California 70%

USA 23%

New England 11%

*Source: FERC 2012 Assessment of Demand Response and Advanced Metering. (December 2012) , Table 2-3.