NARUC/FERC COLLABORATIVE: DEMAND RESPONSE

Paul Suskie, Chairman,

Arkansas Public Service Commission

July 15, 2007

2

Arkansas Experience

Legislative Action in Arkansas APSC Activities 1977 - Current Comparison of Demand Response by IOUs

and Cooperatives Success of Some Current Activities Regional Activities

3

Legislative Action In Arkansas

Energy Conservation Endorsement Act of 1977 Adopted at a time of energy insecurity Focus of the law was on three areas:

Insulation programs for all customer classes; Renewable programs; and “Programs which result in the improvement of load factors,

contribute to reductions in peak power demands, and promote efficient load management, including the adoption of interruptible service equipment and alternative or additional metering equipment designed to implement new rate structures”

4

Legislative Action (cont.)

Resurrection of a Dead Law

Act 1939 of 2005 directed the Commission to report on its activities under the ECEA of 1977 to the General Assembly for the period of July 1, 1998, through June 30, 2006.”

5

APSC ECEA Activities Since 1977

While this law authorizing APSC action on conservation and EE has been on the books for three decades, until January 2006, it had been neither implemented nor invoked by the Commission in a rulemaking or other proceeding.

During the 90’s, pursuant to Federal law, demand side management and IRP were “considered” but not adopted.

6

APSC ECEA Activities Beginning 2006

January 2006 acted to begin implementing the ECEA to increase the level of energy conservation and energy efficiency activity in the state of Arkansas.

Order issued in January 2007 establishing a schedule for implementing quick start programs.

Programs that have been proposed include energy efficiency and demand response.

On May 24 -25, 2007 the Commission hosted a workshop on DR and AMI

7

Demand Response Activities

IOU activities since 1977: To the extent they have existed have been minimal; Different theories for minimal attention for IOU DR activities

include excess supply, historic low cost generation, sufficient transmission, the IOUs had little incentive to invest in DR and encourage conservation;

In a recent rate case, the Commission determined that an optional irrigation control program could be terminated but this was due to the utility’s failure to maintain the equipment. The Commission approved a BPL pilot and directed the company to investigate reinstating the program.

8

Demand Response Activities

Electric cooperative activities: Started in 1978 and have been significant Coops have approximately 730 MWs of DR (out

of total 2708 MW demand) achieved by:1) Direct control by member coops

2) Voluntary control by customers

3) Direct control of industrial load by Arkansas Electric Cooperative Corporation (Generation & Transmission Cooperative)

9

Total Electric Cooperative Demand both Controlled and FirmApproximately 2,708 MW

Firm Load 73%

Note: AECC’s 2006 firm load = 1,971 MW

Load Controlled by AECC 20%

C&I Voluntary Control 3%

Load Controlled by Member Cooperatives 4%

10

AECC's Rate 1 Peak Day kW by Hour 1978

-

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Hours

KW

kW by Hour 1978

704,430 kW or 95% of 741,512 kW

11

AECC's Firm Load (Rate 1) Peak Day kW by Hour 2006

-

500,000

1,000,000

1,500,000

2,000,000

2,500,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Hours

KW

kW by Hour 2006

1,871 MW or 95% of 1,970 MW

7 hours within 95% of peak 9 hours within 94% of peak

12

Woodruff's Rate 1 Load on AECC's 1978 Peak Day

-

10,000

20,000

30,000

40,000

50,000

60,000

70,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Hours

KW

kW by Hour 1978

AECC's Rate-1 Peak Occur at 1800 hours

13

Woodruff's Rate 1 Load on AECC's 2006 Peak Day

-

20,000

40,000

60,000

80,000

100,000

120,000

140,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Hours

KW

AECC's Rate-1 Peak

Occurred at 1700 hours

14

Reasons for Coops Success?

DR provides an opportunity to gain an economic advantage in the bills of customers and distribution coops

Use of DR avoids ST capacity shortages

Use of DR avoids LT capacity investment

15

Current Activities

Electric utilities (IOUs) have begun filing plans for quick start programs to begin offering service October 1, 2007

Demand response programs proposed include: Emergency load management standard offer Commercial and Industrial standard offer Improving education and outreach about existing programs

After experience with quick start programs, longer term programs to be filed not later than April 1, 2009

16

Regional Activities Arkansas is split by a seam but AR is not a retail

open access state SPP RTO serves the western portion of the state

(including high growth area in NW AR) The SPP has begun to determine how to incorporate DR

into the imbalance market The SPP has formed a DR Task Force Possible future market development could include DR

Entergy serves the remainder of the state Not aware of any regional activity

APSC will continue to build from the experience of other states and experience of those within the state

17

Arkansas – SPP - Entergy

18

Observations

IOUs have work to do, in particular in high growth areas where it is difficult to place generation and transmission

Coops may have flattened their peak as much as possible

Regionally it is important for regulators to share information on DR programs that are working and those that haven’t

19

QUESTIONS?