december 31, 2003 - iso new england · 2018-01-19 · dc_docs_a #1133532 v1 december 1, 2003. a...

DC_DOCS_A #1133532 v1

December 31, 2003 Via Hand Delivery Honorable Magalie R. Salas, Secretary Federal Energy Regulatory Commission 888 First Street, NE Washington, D.C. 20246

Re: Semi-Annual Status Report on Load Response Programs of ISO New England Inc., FERC Docket No. ER03-345-

Dear Ms. Salas,

On February 25, 2003, the Federal Energy Regulatory Commission (“Commission”) issued an order in the above-referenced docket accepting tariff revisions submitted by the New England Power Pool (“NEPOOL”) Participants Committee to change the basis for allocating NEPOOL Load Response Program costs among New England customers.1 In the February 25 Order, the Commission also directed ISO New England Inc. (the “ISO”) to file status reports every six months regarding the Load Response programs revised by that order. Specifically, the Commission stated that:

these filings must include (a) information on customer enrollment for each Load Response program in terms of the number of customers and total potential load reduction in MWs, and (b) information on total load reductions achieved per program per event during the prior six-month period, including ISO-NE system load at time of curtailments, total MWs reduced, total payment for reductions, and effects of the demand response programs on wholesale prices.2

Additionally, in a November 14, 2003 Order, the Commission directed the ISO to include in this report “a description of the progress of efforts to provide additional compensation to Demand Response Resources.”3 1 Order on Tariff Filing, 102 FERC ¶ 61,202 at P 19 (Feb. 25, 2003) (“February 25 Order”). 2 Id. 3 Order Accepting Forward Reserve Market Filing, 105 FERC ¶ 61,204 at P 26 (Nov. 14, 2003) (“November 14 Order”). The ISO notes that in Paragraph 26 of the November 14 Order, the Commission states that this description should be included in the ISO’s “periodic reports on the implementation of Standard Market Design.” Inconsistently, however, the associated footnote 13 in the November 14 Order indicates that the description should be included in the ISO’s semi-annual Load Response status reports. The ISO believes that the information requested is appropriately included in these Load Response status reports, and so will continue to do so unless directed otherwise by the Commission.

Honorable Magalie R. Salas December 31, 2003 of 15

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This is the second report filed pursuant to the Commission’s directive in the February 25 Order; the previous report was filed by the ISO on June 30, 2003 in FERC Docket No. ER03-345-001. Pursuant to Rule 1907 of the Commission’s Rules of Practice and Procedure,4 the ISO hereby submits an original and 5 copies of this status report in accordance with the February 25 Order. I. COMMUNICATIONS

Correspondence and communications regarding this filing should be addressed to the following persons:

James H. Douglass ISO New England Inc. One Sullivan Road Holyoke, MA 01040 (413) 540-4559 and

Howard H. Shafferman Ballard Spahr Andrews & Ingersoll, LLP 601 13th Street, N.W., Suite 1000 South Washington, D.C. 20005 (202) 661-2205

II. PRESENT STATUS OF THE DEMAND RESPONSE PROGRAM

The ISO administers the NEPOOL Demand Response Program (the “Program”) for the New England wholesale electricity market. During the period June 2003 through November 2003, ISO-NE administered the following demand response programs:

• Real Time Demand Response Program (30 minute response) – requires demand response resources to respond within 30 minutes of the ISO’s instructions to interrupt.

• Real Time Demand Response Program (2 hour response) – requires demand response resources to respond within 2 hours of the ISO’s instructions to interrupt.

• Real Time Profiled Response Program – was designed for Enrolling Participants with loads under their direct control and are capable of being interrupted within 2 hours of the ISO’s instructions to interrupt. Individual Customers participating in this program are not required to have an interval meter. Instead, Enrolling

4 See 18 C.F.R. § 385.1907 (2002).


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Participants may develop and submit a monitoring and verification plan as specified in the Load Response manual for ISO approval.5

• Real Time Price Response – voluntary reductions in load by program participants are eligible for payment when the forecast hourly Zonal Price is greater than or equal to $100/MWh, and the ISO has transmitted instructions that the eligibility period is open.

The first three programs listed above are called during zonal or system-wide capacity deficiencies in order to help preserve system reliability. The last program, the Real Time Price Response program, is called during periods of high wholesale prices in order to encourage price responsive loads and to address price volatility.

This section of the report summarizes the information requested in the Commission’s February 25 Order. This information – which pertains to the six-month period of June 1, 2003 through November 30, 2003 (the “Reporting Period”) – is presented in detail in Attachment 1. The summary tables in this section are numbered alphabetically while the corresponding detail provided in Attachment 1 is numbered numerically. The paragraphs and tables below provide the following information: • Number of customers in each load response program and the total potential load

reduction in MWs (Table A). • Information on total load reductions achieved per program per event during the

Reporting Period including ISO system load at time of curtailments, total MWs reduced and total payment for reductions (Tables C, D, and E with corresponding details in Attachment 1 – Tables 1, 2, 3, 4, 4A, and 5).6

• The effects of demand response on wholesale prices (Tables F and G).

A. Current Enrollment

Table A below provides the enrollment in the Demand Response Program by Zone as of December 1, 2003. The numbers provided in Table A represent assets that are active and ready to respond and comprise the total potential load reduction as of

5 In a filing submitted by NEPOOL on November 25, 2003, in accordance with the Commission’s direction, Appendix E of Market Rule1 was modified to state that all programs require interval metering or an “approved” M&V plan and that all of the ISO’s Demand Response Programs are now eligible to make use of an M&V Plan for performance measurement. 6 In a June 6, 2003 Order, the Commission directed the ISO to prepare and submit an independent evaluation of the 2003 Demand Response Programs (“2003 Program Evaluation Report”). See Order on Rehearing and Accepting in Part and Rejecting in Part Compliance Filings, 103 FERC ¶ 61,304 (“June 6 Order”). As discussed in more detail below, the 2003 Program Evaluation Report (prepared by RLW Analytics and Neenan Associates) will be filed with the Commission on December 31, 2003 under separate cover. The evaluation report is based on initial settlement data through August 2003. The data used in preparing this semi-annual compliance filing used 90-day resettlement data through July 2003. Therefore, there may be some minor discrepancies between the 2003 evaluation report and this semi-annual compliance filing.


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December 1, 2003. A total of 340 MW was enrolled in the Program on December 1, 2003, with over 43 percent of the MWs located in the Connecticut zone.

Table A

Zone Assets RT Price RT 30-Min RT 2-Hour Profiled Total

CT 120 27.0 61.8 1.1 57.8 147.7

ME 4 0.4 0.0 0.0 76.0 76.4

NEMA 114 62.9 3.1 0.8 1.4 68.2

NH 1 0.0 0.4 0.0 0.0 0.4

RI 13 2.0 0.0 0.0 0.0 2.0

SEMA 72 7.4 0.5 0.0 0.0 7.9

VT 16 7.1 1.3 0.0 5.9 14.3

WCMA 92 9.3 4.8 2.3 6.9 23.3

Total 432 116.1 72.0 4.3 147.9 340.2

READY TO RESPOND

MW

The Maine and NEMA zones (Northeast Massachusetts) follow with 22 percent and 20 percent of the MWs ready to respond, respectively. In terms of the number of assets by zone, the Connecticut zone leads with 28 percent of the ready to respond assets followed by NEMA and WCMA (26 percent and 21 percent, respectively).

The previous semi-annual compliance filing reported enrollments of approximately 335 MW as of May 31, 2003. Although it may appear that enrollments have increased by only 5 MW during the Reporting Period, it should be noted that because the New England system is a summer peaking system, enrollment in the Demand Response Program is likewise summer peaking.7 Approximately 100 MW of assets were retired during and after the summer. Table A reflects the retirements that have occurred through November 30, 2003 – i.e., Table A includes only those assets that were ready to respond as of December 1, 2003.

Table B provides a bird’s eye view of the price response and demand response events that were called during the Reporting Period. Price response events were 7 At the end of August 2003, the Program had a total of about 380 MW of Ready to Respond demand response assets.


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declared on 36 days (with 38 separate events) and a total of 377 hours. Although there were 38 price response events in the Reporting Period, about 58 percent (or 22 events) occurred in the autumn months (September, October, November) and 50 percent of the events (19 events) occurred exclusively in Connecticut in the autumn. For the entire Reporting Period, 28 events (or approximately 74 percent of the events) occurred exclusively in the Connecticut zone. This suggests that although a larger number of events might be expected during the summer months, the price response program was activated frequently in October and November due to higher locational marginal prices in the Connecticut Zone.

Assets in the Real Time Demand Response and Profiled Response programs (“reliability programs”) were called only on one occasion during the Reporting Period. Real Time Demand Response assets in the 30-minute and 2-Hour programs, and the Profiled Response assets were called on August 15, 2003 for a total of 62 hours (or 14 percent of the total of 439 hours during which price and demand response programs were active).8 The assets in the 30-minute Real Time Demand Response program were called in two stages: load curtailment assets were called at Action 9 of Operating Procedure 4 (“Actions During A Capacity Deficiency”) whereas emergency generators (“EG”) were called at Action 12. The events of August 15, 2003 are discussed further in the next sub-section.

8 The 62 hours is the cumulative number of hours over which each reliability program was activated. Note, however, that the 30-minute Real Time Demand Response program consists of two separate sub-programs that are activated at two different stages of Operating Procedure 4 – at Action 9 and Action 12. Therefore, the 30-minute Real Time Demand Response program accounts for 30 of the total 62 hours over which the reliability programs were called on August 15, 2003.

Honorable Magalie R. Salas December 31, 2003 of 15 Table B

Load ZoneDate Program Start End Hours ME CT NEMA SEMA WCMA NH VT RI06/05/03 Price 07:00 18:00 11 n n n n n n n n

06/25/03 Price 12:00 18:00 6 n

06/26/03 Price 07:00 18:00 11 n n

06/27/03 Price 07:00 18:00 11 n n n n n n n n

07/01/03 Price 11:00 18:00 7 n

07/08/03 Price 07:00 18:00 11 n

07/08/03 Price 12:00 18:00 6 n n n n n

07/21/03 Price 16:00 18:00 2 n

07/23/03 Price 07:00 18:00 11 n

07/31/03 Price 07:00 18:00 11 n

08/11/03 Price 07:00 18:00 11 n

08/15/03 Price 08:00 18:00 10 n

08/20/03 Price 07:00 18:00 11 n

08/21/03 Price 07:00 18:00 11 n

08/22/03 Price 07:00 18:00 11 n

08/27/03 Price 11:00 18:00 7 n

09/15/03 Price 07:00 18:00 11 n

09/15/03 Price 10:00 18:00 8 n n n n n n n

10/17/03 Price 07:00 18:00 11 n

10/27/03 Price 07:00 18:00 11 n

10/28/03 Price 07:00 18:00 11 n

10/29/03 Price 07:00 18:00 11 n

10/30/03 Price 07:00 18:00 11 n

10/31/03 Price 07:00 18:00 11 n

11/03/03 Price 07:00 18:00 11 n

11/04/03 Price 07:00 18:00 11 n

11/05/03 Price 11:00 18:00 7 n

11/06/03 Price 07:00 18:00 11 n

11/07/03 Price 12:00 18:00 6 n

11/10/03 Price 07:00 18:00 11 n

11/13/03 Price 07:00 18:00 11 n

11/14/03 Price 08:00 18:00 10 n

11/17/03 Price 07:00 18:00 11 n

11/18/03 Price 07:00 18:00 11 n

11/19/03 Price 07:00 18:00 11 n

11/20/03 Price 07:00 18:00 11 n

11/24/03 Price 07:00 18:00 11 n

11/25/03 Price 07:00 18:00 11 n

Load ZoneDate Program Start End Hours ME CT NEMA SEMA WCMA NH VT RI08/15/03 2-Hr 08:30 23:59 15 n

08/15/03 Profiled 07:45 23:59 16 n

08/15/03 30-Min A9 08:30 23:59 15 n

08/15/03 30-Min A12 07:45 23:59 16 n

2003 PRICE RESPONSE EVENTS

2003 DEMAND RESPONSE EVENTS


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B. Events of August 15, 2003

Following the Northeast blackout on August 14, power in southwest Connecticut was almost completely restored by the early morning hours of August 15, 2003. However, shortly before 6 a.m. on August 15, a 345 kV line connecting the New England and New York control areas tripped, thereby limiting the ISO’s ability to support the New York control area to 200 MW from a normal level of 400 MW. Consequently, the ISO activated all of its Demand Response Programs for the Connecticut zone at approximately 8 a.m. Two-thirds of the enrolled customers responded and produced a maximum response of 110 MW at 11 a.m. The response averaged 75 MW per hour from 8:00 to 18:00.

Figure A below shows the MW interruption of demand response assets in Connecticut for the hours of 8:00 through 18:00.

Figure A

Program Response 8/15/2003 for Hours Ending 8 - 18:00

0

10

20

30

40

50

60

8 9 10 11 12 13 14 15 16 17 18Hour Ending

MW

In

terr

up

ted

2 HR 30 min w/EG 30 min w/o EG Price Profile

The 2003 program evaluation that is being filed under separate cover will provide detailed analysis as to the performance of the demand response assets in the various programs, both for August 15, 2003 in particular, and for the whole of 2003 in general.


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C. Load Reductions and Payments – Summary Information9

Tables C and D below reflect payments to demand response resources by zone and MW interruptions by zone respectively. The tables are presented so that the impact of the August 15 demand response events may be discerned.

Table C Payments to Demand Response Resources in Reporting

Period Including August 15, 2003 Excluding August 15, 2003 ME $ 1,786 0.15% ME $ 1,786 0.23% VT $ 9,254 0.79% VT $ 9,254 1.20% CT $1,083,898 92.44% CT $684,669 88.54% RI $ 1,080 0.09% RI $ 1,080 0.14% SEMA $ 1,859 0.16% SEMA $ 1,859 0.24% WCMA $ 5,297 0.45% WCMA $ 5,297 0.68% NEMA $ 69,376 5.92% NEMA $ 69,376 8.97% Total $1,172,549 100% $773,320 100%

Table D

MW Interruptions by Demand Response Assets in Reporting Period

Including August 15, 2003 Excluding August 15, 2003 ME 17.9 0.21% ME 17.9 0.24%VT 83.4 0.97% VT 83.4 1.10%CT 7,733.9 90.22% CT 6,729.8 88.92%RI 10.6 0.12% RI 10.6 0.14%SEMA 17.0 0.20% SEMA 17.0 0.22%WCMA 50.4 0.59% WCMA 50.4 0.67%NEMA 659.0 7.69% NEMA 659.0 8.71% Total 8,572.2 100% 7,568.0 100%

As shown above, the Connecticut zone accounted for approximately 92 percent of the payments and 90 percent of the interruptions during the Reporting Period. The only other zone that was significant was Northeast Massachusetts, albeit with a much smaller impact in the range of 6 to 8 percent. A total of $1.17 million was paid for 8,572 MW of interruptions during the Reporting Period. Excluding August 15, 2003, the payments were $773,000 for interruptions of 7,568 MW. The disproportionate increase in

9 The payment and MW interruption statistics in this compliance filing are based on resettlement data through July 2003. Therefore, data from August through November may be revised based on the 90-day resettlement.


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payments including August 15 reflects the fact the demand programs were activated and the demand programs paid more per hour of interruption than the price program in 2003.

Table E

Payments and MW Interruption by Program - Reporting Period

MW Program Payment % Interrupted %

Real Time 2 hour $ 48,545 4% 138.7 1.6% Real Time 30 min with EG $ 175,815 15% 351.6 4.1% Real Time 30 min w/o EG $ 154,359 13% 308.7 3.6% Price $ 774,515 66% 7,580.0 88.4% Profiled $ 19,316 2% 193.2 2.3% Total $ 1,172,549 100% 8,572.2 100%

Table E presents the payments and MW interruptions by program during the Reporting Period. Since the price response program was activated frequently during the Reporting Period, the price response program represents 88 percent of all the MW interruptions. The Real Time 30-minute program accounted for slightly less than 8 percent of the MW interruptions during the Reporting Period, however, the payments to assets in this program accounted for 28 percent of the total. The average payment per MW of demand response during the Reporting Period was approximately $137. This figure closely represents the minimum payment made for each of the programs ($350/MWh for the 2-hour Demand Response, $500/MWh for the 30-minute Demand Response, and $100/MWh for the Price and Profiled programs).

All of the information presented in the summary tables above is presented in detail by event and by zone in the tables in Attachment 1.

D. Effects of Demand Response on Wholesale Prices

As mentioned above, the Price Response events occurred in 377 hours and the

demand (reliability) programs were activated for 62 hours – for a total of 439 hours during the Reporting Period. The 439 hours represents the sum of the number of hours that each demand response program was active during the Reporting Period. Of these 439 hours, the ISO analyzed those hours during which there was an interruption of 10 MW or more. The 10 MW level was selected based on the ISO’s experience in discerning the impact of potential interruptions in the context of system conditions at the time of those interruptions. There were a total of 227 “instances” where there were interruptions of 10 MW or more. The 227 instances include those hours on August 15, 2003, when several programs were activated simultaneously. In such cases, if two or more programs were active during the same hours, then the cumulative MWs were used to meet the 10 MW threshold.


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It is important to note that the methodology used by the ISO to estimate the effects of demand response on wholesale prices does not attempt to predict what the wholesale price would have been had demand response not occurred. The ISO’s method is an estimate of the possible impact of demand response on wholesale prices.10 The ISO’s methodology does not simulate some operational conditions that exist in real time and therefore the impact information provided below is in the form of relative magnitudes of the effects of demand response interruptions.

Table F presents summary information of the estimated impact of interruptions that were greater than or equal to 10 MW during the Reporting Period. The estimated impact in every case was either zero or positive, where a positive impact implies that wholesale prices would have been higher had a demand response interruption not occurred. The first row of Table F below shows the range of impact, which describes the impact on wholesale price when the wholesale price including demand response is compared with the hypothetical situation where there was no demand response. If the estimated wholesale price without demand response is higher, then the difference as a percentage of the price including demand response indicates the impact. For example, of the 227 instances that were studied, demand response had no impact on wholesale prices in 167 (or 74 percent) of the instances, while 26 percent of the instances showed a positive impact of varying degrees. In other words, in 74 percent of the cases the estimated price assuming no demand response interruptions was estimated to be the same as the actual wholesale zonal price with demand response.

Table F Estimated Impact of Interruptions from Demand Response on Wholesale Price

Range of Impact 0% 0% - 10% 11%-20% 21%-30% 31%-40% 41%-50% Total

No. of Instances 167 44 14 0 1 1 227

No. of Instances as a percentage of Total 74% 19% 6% 0% 0.4% 0.4% 100% In 26 percent of the instances, the estimated zonal price without demand response was greater than the estimated price including demand response interruptions, thereby resulting in a positive impact.

10 The ISO’s estimates would only be representative if the system were redispatched without demand response under the exact operating conditions that existed during the actual event. Since it is impractical and perhaps impossible to redispatch the system under a set of exact conditions, actual real time price data is not presented.


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Similarly, in 44 instances or 19 percent of the total, the effect of demand response interruptions on wholesale prices is estimated to be in the range of 0 to 10 percent. In other words, it is estimated that wholesale prices would have been higher by 0 to 10 percent in 44 cases had demand response not occurred. There were 14 instances when demand response interruptions are estimated to have had an impact on wholesale prices with an order of magnitude of 11 to 20 percent. The effect on wholesale prices was greater than 20 percent in two instances.

All of the instances with interruptions of 10 MW or more took place either in the NEMA zone or in the Connecticut zone. Of the 227 instances, only 42 cases (19 percent) occurred in the NEMA zone. Of those 42 cases, 40 had no effect (zero) on wholesale prices. In one case the price impact was 6.4 percent and in the other case it was 1.5 percent. In comparison, the Connecticut zone accounted for 185 of the 227 instances (81 percent) when the interruption was greater than or equal to 10 MW. Eleven of the 227 instances (or 4.8 percent) pertain to hours on August 15, 2003. In terms of the magnitude of the impact on wholesale prices, the top 30 demand response events occurred in the Connecticut zone. In other words, there were no significant price impacts in the other zones (with the exception of the single 6.4 percent impact in NEMA discussed above).

However, out of the 42 cases in NEMA, there were significant effects on wholesale prices in two instances. The first impact ranked 7th and it is estimated that wholesale prices would have been nearly 18 percent higher had demand response not occurred. In the second instance the impact was 6.6 percent and ranked 31st (out of 227). The largest interruption occurred in this case, with an interruption of 109 MW. This information suggests that the impact of demand response on wholesale prices is affected by factors other than the magnitude of the interruption. Some of these other factors include the nature of the supply bids, system and zonal loads, and other real-time operational conditions.

Although the Reporting Period included the summer months of June, July, and August, 63 percent (or 144 of the 227 instances) of interruptions of 10 MW or more occurred in November. In fact, with the exception of the August 15 event, which had an impact on wholesale prices, every instance in the top 30 (measured by impact on wholesale prices) occurred in November. Table G below summarizes the spread of the 227 instances over the Reporting Period.


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Table G

Month No. of Instances with 10 MW or more interruption

As a percentage of total

June 17 7% July 13 6% August 18 8% September 8 4% October 27 12% November 144 63% Total 227 100%

The information in the preceding sections shows that not only did a large number of events occur in November but also that those events are estimated to have had a very significant effect on wholesale prices – i.e., wholesale prices would have increased in about one third of those cases had demand response interruptions not occurred.11

III. 2003 PROGRAM EVALUATION

In the June 6 Order, the Commission directed the ISO to "prepare and submit an 'independent' in-depth process and impact evaluation and market assessment of its 2003 demand response programs by December 31, 2003, and to provide a similar evaluation by the end of each calendar year until and including December 31, 2005."12

ISO New England contracted with the team of RLW Analytics and Neenan Associates to perform process, impact, and market evaluations of its 2003 Demand Response Programs. One objective of the project was to develop an independent, in-depth report to satisfy the Commission's filing requirements. In addition, the project provided an opportunity to better understand the needs of current and future program participants. This improved understanding should assist ISO New England in improving current and future programs. In addition, the market assessment work should help in identifying target customers.

The 2003 Program Evaluation Report will be filed with the Commission on December 31, 2003 under separate cover. It should be noted that the numbers on program participation, asset performance, and settlement amounts reported in the 2003 Program Evaluation Report might differ somewhat from those reported herein. Since the 2003 Program Evaluation commenced in September 2003, the data used in that evaluation was through August 2003, whereas the data used in this report is through 11 It should be noted, however, that the 90-day resettlement data for the months of August through November is not yet available. Subsequent to resettlement, some of the payment and MW interruption statistics may be revised. 12 June 6 Order at P 69.


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November 2003. Additionally, the latter months of data used in the 2003 Program Evaluation Report is based on initial settlement data whereas the data used in this report may have been revised somewhat during the 90-day resettlement period. IV. DAY-AHEAD DEMAND RESPONSE PROGRAM

In accordance with the Commission’s November 17, 2003 Order,13 which requires the ISO to implement day-ahead demand response programs by March 31, 2005,14 the ISO has established a project for the development and implementation of both reliability- and economic-based day-ahead demand response programs. The ISO has also established a core team of individuals who are currently working on the program design.

Additionally, as part of the 2003 Program Evaluation Report, the ISO requested that the independent evaluator conduct a market assessment using customer survey tools to investigate how alternative day-ahead program designs might affect participation in such programs. The results and analysis of that portion of the survey should be available to the ISO in the first quarter of 2004. The ISO will take into consideration the results of the survey and the evaluator’s analysis in further program development efforts.

The ISO will investigate implementation methods for the day-ahead reliability program presently described in Manual M-LRP Load Response Manual and the development of a day-ahead price response program during the first quarter of 2004. Once program designs are developed, the ISO will present those designs for discussion and review with the Demand Response Working Group (“DRWG”) and the NEPOOL Markets Committee (“NMC”). The input received from these stakeholders will be incorporated into the final proposal, which will be presented to the DRWG, the NMC, and the NEPOOL Participants Committee for approval. Once that approval has been obtained, the development of software specifications can commence.

The ISO will provide further information on day-ahead program development in the March 31, 2004 quarterly status report as directed by the Commission.15 V. INCORPORATION OF DEMAND RESPONSE IN CO-OPTIMIZED

MARKETS

In the November 14, 2003 Order, the Commission directed the ISO to include in this report “a description of the progress of efforts to provide additional compensation to

13 See Order on Requests for Rehearing and Compliance Filing, 105 FERC ¶ 61,211 (“November 17 Order”). 14 See November 17 Order at P 22. 15 Id.


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Demand Response Resources.”16 The ISO is currently in the process of developing co-optimized energy and reserve markets. In accordance with the Commission’s directives, the development of the co-optimized market is intended to include the participation of demand response resources in a manner that is comparable to how supply side resources would participate. The ISO believes that incorporation of demand response resources in the co-optimized markets will provide additional compensation to those resources.

Among the ISO’s objectives is to make greater use of demand response resources to improve system reliability and to enable such resources to respond to wholesale market prices. However, the characteristics and behavior of demand resources are very different than generation resources, so achieving the above-mentioned objectives present unique challenges to the ISO. Individual demand response resources are small whereas individual generators are large. Therefore, the use of sophisticated metering and communication technology typically required of large generators to enable system operators to monitor system status and to communicate dispatch instructions would not be cost-effective for demand response. On the other hand, system operators need to monitor system status in real-time and to quickly dispatch supply and demand resources accordingly to preserve reliability.

To address the challenge of allowing demand resources to effectively participate in reserve markets, ISO staff recently met with representatives of three National Laboratories (Lawrence Berkeley National Laboratory, Oak Ridge National Laboratory, and Pacific Northwest National Laboratory). Provided that the National Laboratories receive adequate funding from the Department of Energy to support their work with the ISO, the ISO intends to work with staff from the National Laboratories to address issues related to demand response participation in reserve markets. 16 November 14 Order at P 26.


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VI. CONCLUSION

The ISO hereby submits this status report in compliance with the Commission’s February 25 Order. Copies of this report are being served on all persons on the Commission’s official service list in the captioned proceeding, as well as on the governors and electric utility regulatory agencies for the six New England states that comprise the NEPOOL Control Area. All NEPOOL Participants Committee members are being furnished with an electronic copy of this compliance report. In accordance with the Commission’s rules and practice, there is no need for these entities to be included on the Commission’s official service list in this proceeding unless such entities already are or become intervenors in this proceeding. A draft form of notice that is suitable for publication in the Federal Register is included in this filing, and a diskette containing this form of notice in electronic format is also enclosed.

Respectfully submitted, _______________________________

James H. Douglass ISO New England Inc. One Sullivan Road Holyoke, MA 01040-2841 (413) 540-4559 _______________________________ Perry D. Robinson Craig Galligan Ballard Spahr Andrews & Ingersoll, LLP 601 13th Street, N.W., Suite 1000 South Washington, D.C. 20005 (202) 661-7616 Counsel for ISO New England Inc.

Attachments cc: All parties to FERC Docket No. ER03-345-000 et al.

CERTIFICATE OF SERVICE

I hereby certify that I have this day served the foregoing document upon each

person designated on the official service list compiled by the Secretary in these

proceedings.

Dated at Washington, D.C. this 31st day of December, 2003.

__________________________________ Pamela S. Higgins Ballard Spahr Andrews & Ingersoll, LLP 601 13th Street, N.W., Suite 1000 South Washington, D.C. 20005 (202) 661-2258

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UNITED STATES OF AMERICA BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

) New England Power Pool ) Docket No. ER03-345-___

)

NOTICE OF FILING (_____________)

Take notice that on December 31, 2003, ISO New England Inc. (ISO) submitted a Status Report on Load Response Programs as directed by the Commission in its February 25, 2003 Order on Tariff Filing, 102 FERC ¶ 61,202. The ISO states that copies of the filing have been served on all parties to the above-captioned proceeding.

Any person desiring to intervene or to protest this filing should file with the Federal Energy Regulatory Commission, 888 First Street, N.E., Washington, D.C. 20426, in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214). Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceeding. Any person wishing to become a party must file a motion to intervene. All such motions or protests should be filed on or before the comment date, and, to the extent applicable, must be served on the applicant and on any other person designated on the official service list. This filing is available for review at the Commission or may be viewed on the Commission's web site at http://www.ferc.gov, using the "eLibrary" link. Enter the docket number excluding the last three digits in the docket number field to access the document. For assistance, contact FERC Online Support at [email protected] or toll-free at (866)208-3676, or for TTY, contact (202)502-8659. Protests and interventions may be filed electronically via the Internet in lieu of paper; see 18 CFR 385.2001(a)(1)(iii) and the instructions on the Commission's web site under the "e-Filing" link. The Commission strongly encourages electronic filings. Comment date:___________________

Magalie R. Salas Secretary

Attachment 1

*MWs Interrupted and Payment figures are the sum of hourly numbers over all event hours on a given day.

December 31, 2003 ISO New England Semi-Annual Compliance Report – Attachment I Page 1 of 13

Table 1: June 2003 – November 2003 – Summary* All Programs – Actual Response and Payment – All Event Hours

PROGRAM

Date Data DEMAND 2-HOURDEMAND 30-MIN

WITH EGDEMAND 30-MIN

WITHOUT EGPRICE PROFILED Grand Total

06/05/03 MWs Interrupted 95.50 95.50Payment $9,549.60 $9,549.60

06/25/03 MWs Interrupted 0.64 0.64Payment $63.80 $63.80









08/15/03 MWs Interrupted 138.70 351.63 308.72 11.95 193.16 1004.15Payment $48,545.35 $175,815.00 $154,358.50 $1,194.70 $19,315.90 $399,229.45








Table 1: June 2003 – November 2003 – Summary* (continued) All Programs – Actual Response and Payment - All Event Hours

PROGRAM






















Table 1: June 2003 – November 2003 – Summary* (continued) All Programs – Actual Response and Payment - All Event Hours

PROGRAM








Total MWs Interrupted 138.70 351.63 308.72 7579.96 193.16 8572.16Total Payment $48,545.35 $175,815.00 $154,358.50 $774,514.54 $19,315.90 $1,172,549.29



Table 2: June 2003 – November 2003, Detail By Zone All Programs – Actual Response and Payment - All Event Hours

Program

Date Zone Name Data DEMAND 2-HOURDEMAND 30-MIN



06/05/03 ME MWs Interrupted 17.86 17.86Payment $1,786.40 $1,786.40

VT MWs Interrupted 1.34 1.34Payment $133.70 $133.70

CT MWs Interrupted 46.17 46.17Payment $4,616.50 $4,616.50

RI MWs Interrupted 2.63 2.63Payment $263.20 $263.20

SEMA MWs Interrupted 0.75 0.75Payment $75.20 $75.20

WCMA MWs Interrupted 23.35 23.35Payment $2,335.10 $2,335.10

NEMA MWs Interrupted 3.40 3.40Payment $339.50 $339.50

Total All Zones MWs Interrupted 95.50 95.50Total All Zones Payment $9,549.60 $9,549.60

06/25/03 VT MWs Interrupted 0.64 0.64Payment $63.80 $63.80

Total All Zones MWs Interrupted 0.64 0.64Total All Zones Payment $63.80 $63.80

06/26/03 CT MWs Interrupted 54.54 54.54Payment $5,522.79 $5,522.79

NEMA MWs Interrupted 76.42 76.42Payment $7,642.78 $7,642.78


06/27/03 VT MWs Interrupted 23.68 23.68Payment $3,260.06 $3,260.06




WCMA MWs Interrupted 6.31 6.31Payment $848.55 $848.55





Table 2: June 2003 – November 2003, Detail By Zone (continued) All Programs – Actual Response and Payment - All Event Hours

Program




07/01/03 NEMA MWs Interrupted 107.06 107.06Payment $10,705.50 $10,705.50





WCMA MWs Interrupted 6.67 6.67Payment $667.20 $667.20



07/21/03 CT MWs Interrupted 1.31 1.31Payment $180.42 $180.42






08/11/03 RI MWs Interrupted 3.20 3.20Payment $320.10 $320.10


08/15/03 CT MWs Interrupted 138.70 351.63 308.72 11.95 193.16 1004.15Payment $48,545.35 $175,815.00 $154,358.50 $1,194.70 $19,315.90 $399,229.45

Total All Zones MWs Interrupted 138.70 351.63 308.72 11.95 193.16 1004.15Total All Zones Payment $48,545.35 $175,815.00 $154,358.50 $1,194.70 $19,315.90 $399,229.45






Program








08/27/03 NEMA MWs Interrupted 103.90 103.90Payment $10,389.70 $10,389.70


09/15/03 VT MWs Interrupted 10.82 10.82Payment $1,103.82 $1,103.82




WCMA MWs Interrupted 14.07 14.07Payment $1,445.65 $1,445.65



10/17/03 VT MWs Interrupted 46.93 46.93 Payment $4,692.90 $4,692.90


10/27/03 CT MWs Interrupted 33.69 33.69 Payment $3,616.37 $3,616.37







Program










11/03/03 CT 387.27 387.27$38,768.61 $38,768.61


11/04/03 CT 399.59 399.59$39,959.30 $39,959.30


11/05/03 CT 247.63 247.63$24,784.54 $24,784.54


11/06/03 CT 404.71 404.71$40,470.60 $40,470.60


11/07/03 CT 229.21 229.21$22,921.00 $22,921.00


11/10/03 CT 447.80 447.80$44,780.30 $44,780.30





Program




11/13/03 CT 378.95 378.95$37,894.80 $37,894.80


11/14/03 CT 383.61 383.61$38,361.30 $38,361.30


11/17/03 CT 370.68 370.68$37,067.70 $37,067.70


11/18/03 CT 376.54 376.54$37,654.00 $37,654.00


11/19/03 CT 356.41 356.41$35,640.80 $35,640.80


11/20/03 CT 352.57 352.57$35,957.52 $35,957.52


11/24/03 CT 380.71 380.71$38,070.90 $38,070.90


11/25/03 CT 373.56 373.56$37,355.60 $37,355.60

Total All Zones MWs Interrupted 373.56 373.56Total All Zones Payment $37,355.60 $37,355.60Total All Events MWs Interrupted 138.70 351.63 308.72 7579.96 193.16 8572.16Total All Events Payment $48,545.35 $175,815.00 $154,358.50 $774,514.54 $19,315.90 $1,172,549.29


Table 3: June 2003 – November 2003 Price Response Program - Summary

Actual Response and Payment For Hours Ending 8 – 18:00

Hour EndingDate Data 8 9 10 11 12 13 14 15 16 17 18 Grand Total

06/05/03 MWs Interrupted 2.82 5.04 7.16 9.37 9.49 11.37 11.05 10.48 9.12 10.74 8.87 95.50 Payment $281.80 $504.10 $715.90 $936.70 $948.50 $1,137.30 $1,104.50 $1,047.80 $911.80 $1,074.20 $887.00 $9,549.60

06/25/03 MWs Interrupted 0.27 0.12 0.00 0.06 0.11 0.08 0.64 Payment $26.70 $12.10 $0.20 $5.80 $11.00 $8.00 $63.80

06/26/03 MWs Interrupted 1.09 11.67 17.16 16.96 17.65 16.18 10.97 10.68 11.25 11.52 5.84 130.96 Payment $108.60 $1,166.50 $1,716.40 $1,696.30 $1,764.80 $1,617.80 $1,096.90 $1,138.17 $1,124.50 $1,151.70 $583.90 $13,165.57

06/27/03 MWs Interrupted 2.48 10.54 16.98 17.30 21.38 23.32 19.43 20.95 24.11 25.39 25.17 207.06 Payment $248.30 $1,054.10 $1,698.40 $1,730.10 $2,152.41 $2,638.25 $2,687.28 $2,831.69 $3,648.16 $4,147.92 $2,708.93 $25,545.54

07/01/03 MWs Interrupted 11.17 15.83 16.41 16.06 15.93 16.05 15.60 107.06 Payment $1,117.00 $1,583.30 $1,641.40 $1,606.20 $1,593.20 $1,604.70 $1,559.70 $10,705.50

07/08/03 MWs Interrupted 1.08 4.29 8.99 8.89 8.43 25.10 23.03 20.45 20.41 21.62 21.23 163.51 Payment $107.90 $429.00 $898.90 $888.50 $843.20 $2,509.60 $2,303.10 $2,111.34 $2,107.00 $2,257.60 $2,123.10 $16,579.24

07/21/03 MWs Interrupted 0.75 0.56 1.31 Payment $106.93 $73.49 $180.42

07/23/03 MWs Interrupted 1.27 1.82 2.07 2.62 3.33 3.23 4.84 4.94 6.36 5.98 5.06 41.51 Payment $126.60 $181.90 $206.60 $261.70 $333.40 $322.70 $484.00 $494.10 $636.30 $598.00 $505.80 $4,151.10


08/11/03 MWs Interrupted 0.27 0.32 0.35 0.37 0.35 0.37 0.38 0.35 0.33 0.08 0.03 3.20 Payment $26.60 $31.80 $35.30 $37.40 $35.10 $37.00 $38.10 $34.80 $32.90 $8.10 $3.00 $320.10

08/15/03 MWs Interrupted 0.72 0.75 0.72 0.95 1.04 1.33 1.21 2.75 1.55 0.94 11.95 Payment $72.00 $74.50 $71.60 $94.70 $103.90 $133.20 $120.50 $275.20 $154.70 $94.40 $1,194.70



08/22/03 MWs Interrupted 2.67 2.22 2.30 4.38 4.89 4.14 6.73 6.90 8.05 4.83 4.89 52.00 Payment $266.80 $222.10 $229.90 $437.60 $626.16 $664.25 $1,570.30 $1,872.05 $1,750.91 $483.00 $509.16 $8,632.23


09/15/03 MWs Interrupted 1.52 2.64 2.38 18.40 19.73 21.88 24.65 25.05 24.45 25.05 24.94 190.69 Payment $162.67 $263.90 $237.60 $1,840.30 $2,468.19 $2,187.60 $2,465.40 $2,504.80 $2,445.40 $2,505.40 $2,494.20 $19,575.46

10/17/03 MWs Interrupted 1.44 1.63 1.96 2.40 2.73 15.89 6.18 4.28 3.83 3.26 3.34 46.93 Payment $144.00 $162.50 $195.80 $239.60 $273.30 $1,589.30 $617.70 $428.20 $382.70 $326.30 $333.50 $4,692.90



Table 3: June 2003 – November 2003 Price Response Program – Summary (continued)

Actual Response and Payment For Hours Ending 8 – 18:00

Hour EndingDate Data 8 9 10 11 12 13 14 15 16 17 18 Grand Total

10/28/03 MWs Interrupted 10.24 8.98 7.02 6.98 6.42 8.18 8.36 7.86 7.33 6.19 6.04 83.60 Payment $1,023.70 $898.10 $702.40 $697.70 $642.10 $818.10 $835.90 $785.90 $732.80 $619.20 $888.55 $8,644.45

10/29/03 MWs Interrupted 2.62 2.64 3.64 4.31 5.61 6.80 8.67 54.44 44.03 34.48 33.97 201.21 Payment $261.90 $264.20 $364.30 $430.80 $560.60 $680.40 $867.30 $5,443.80 $4,403.00 $4,798.24 $5,949.67 $24,024.21

10/30/03 MWs Interrupted 36.36 36.53 39.12 41.85 39.86 39.96 41.57 37.30 35.89 32.94 31.38 412.75 Payment $3,635.70 $3,652.80 $3,912.20 $4,184.90 $3,985.90 $3,996.00 $4,156.80 $3,729.70 $3,588.70 $3,294.30 $4,230.21 $42,367.21






11/07/03 MWs Interrupted 40.88 43.10 40.78 37.85 34.73 31.88 229.21 Payment $4,088.20 $4,309.60 $4,077.60 $3,785.00 $3,472.80 $3,187.80 $22,921.00



11/14/03 MWs Interrupted 38.33 41.50 44.80 42.62 41.99 39.49 38.71 34.64 31.05 30.50 383.61 Payment $3,832.90 $4,150.10 $4,479.50 $4,261.70 $4,198.80 $3,949.10 $3,870.70 $3,464.00 $3,104.70 $3,049.80 $38,361.30







Total MWs Interrupted 484.91 576.61 617.13 672.33 710.24 802.18 809.29 810.85 756.19 693.50 646.71 7579.96Total Payment $48,501.47 $57,661.30 $61,712.70 $67,342.23 $71,670.66 $80,774.20 $82,571.68 $83,460.29 $78,264.41 $72,743.11 $69,812.49 $774,514.54

*While demand response assets were not required to respond after 18:00, some customers continued to curtail their loads beyond 18:00 due to the exceptional circumstances surrounding this event. Additionally, the unusually weak transmission infrastructure in Southwest Connecticut (SWCT) requires ISO system operators to maintain direct contact with customers located in SWCT who participate in the program using relatively large generation assets. Some of these customers continued to respond beyond 18:00 because they were requested to do so by ISO system operators. Payments were made to customers who acted in good faith and continued to respond to the event between 18:00-24:00.


Table 4: August 15, 2003 Event in CT Zone* All Programs – Actual Response and Payment

Program

Hour Ending Data DEMAND 2-HOURDEMAND 30-MIN



8 MWs Interrupted 0.00 11.73 0.00 0.00 10.62 22.34Payment $0.00 $5,863.00 $0.00 $0.00 $1,061.60 $6,924.60

9 MWs Interrupted 5.58 48.52 7.91 0.72 20.46 83.19Payment $1,954.05 $24,259.50 $3,954.00 $72.00 $2,045.50 $32,285.05







16 MWs Interrupted 10.54 26.17 22.48 2.75 4.31 66.24Payment $3,687.95 $13,083.00 $11,239.00 $275.20 $430.80 $28,715.95

17 MWs Interrupted 0.05 26.57 21.92 1.55 2.69 52.78Payment $16.45 $13,286.50 $10,960.00 $154.70 $269.00 $24,686.65



20 MWs Interrupted 10.99 0.03 16.42 0.00 0.51 27.95Payment $3,847.90 $14.50 $8,210.00 $0.00 $50.70 $12,123.10





Total MWs Interrupted 138.70 351.63 308.72 11.95 193.16 1004.15Total Payment $48,545.35 $175,815.00 $154,358.50 $1,194.70 $19,315.90 $399,229.45


Table 4A: System Loads (MW) August 15, 2003

For Hours Ending 8 – 24:00

Hour Ending CT SYSTEM LOAD8 4,232 16,6899 4,597 18,196

10 4,905 19,34611 5,198 20,33812 5,449 21,04913 5,610 21,52514 5,761 22,01915 5,846 22,25916 5,872 22,28917 5,889 22,26618 5,808 21,86419 5,604 21,08320 5,359 20,33821 5,347 20,37822 5,093 19,43323 4,650 17,77024 4,179 15,966


Table 5: System Loads (MW) June 2003 – November 2003, Summary Event Days For Hours Ending 8 – 18:00

Hour EndingDate 8 9 10 11 12 13 14 15 16 17 18

06/05/2003 14,448 15,147 15,475 15,743 15,865 15,762 15,741 15,624 15,544 15,636 15,62406/25/2003 16,277 17,860 19,077 20,126 20,851 21,329 21,805 22,061 22,173 22,187 21,91806/26/2003 18,015 19,777 21,144 22,273 22,975 23,366 23,735 23,851 23,900 23,896 23,61506/27/2003 18,442 20,280 21,724 22,842 23,532 23,829 24,112 24,111 23,902 23,613 23,05707/01/2003 15,150 16,517 17,464 18,187 18,636 18,832 19,118 19,244 19,307 19,359 19,13107/08/2003 17,775 19,508 20,818 21,897 22,542 22,886 23,239 23,430 23,527 23,586 23,34207/21/2003 15,804 17,199 18,114 18,737 19,113 19,292 19,503 19,541 19,436 19,384 19,25007/23/2003 17,155 18,388 19,252 19,902 20,380 20,547 20,655 20,617 20,520 20,567 20,39007/31/2003 15,549 16,907 17,882 18,640 19,122 19,337 19,613 19,684 19,659 19,535 19,11108/11/2003 17,400 18,823 19,958 20,936 21,659 22,124 22,570 22,741 22,760 22,708 22,43208/15/2003 16,689 18,196 19,346 20,338 21,049 21,525 22,019 22,259 22,289 22,266 21,86408/20/2003 16,340 17,853 19,073 20,094 20,803 21,338 21,912 22,293 22,487 22,655 22,40508/21/2003 17,138 18,797 20,150 21,283 22,086 22,607 23,064 23,276 23,356 23,354 22,98308/22/2003 17,876 19,640 21,119 22,380 23,253 23,802 24,240 24,339 24,187 23,783 23,07408/27/2003 16,626 18,038 19,295 20,113 20,506 20,725 21,025 21,063 20,982 20,883 20,53009/15/2003 16,181 17,078 17,769 18,380 18,671 18,834 18,992 18,962 18,862 18,749 18,60510/17/2003 14,860 15,220 15,347 15,466 15,399 15,241 15,130 14,892 14,673 14,701 15,02710/27/2003 15,114 15,718 16,039 16,297 16,286 16,210 16,189 16,091 16,284 17,055 17,82510/28/2003 14,823 15,111 15,242 15,355 15,355 15,287 15,254 15,086 15,060 15,696 17,11510/29/2003 15,138 15,687 16,013 16,293 16,357 16,209 16,127 15,907 15,875 16,452 17,41510/30/2003 14,959 15,298 15,410 15,509 15,510 15,367 15,295 15,143 15,085 15,667 17,02210/31/2003 14,887 15,215 15,345 15,446 15,407 15,245 15,144 14,955 14,890 15,479 16,34311/03/2003 14620 15139 15461 15739 15905 15939 15994 15871 15857 16586 1768011/04/2003 14,750 15,309 15,634 15,891 15,967 15,930 15,913 15,824 15,974 16,856 17,74211/05/2003 15,339 15,784 16,003 16,192 16,235 16,136 16,117 16,020 16,178 17,110 17,86511/06/2003 14,822 15,236 15,440 15,639 15,657 15,569 15,535 15,467 15,703 16,696 17,48311/07/2003 14,865 15,239 15,378 15,487 15,417 15,233 15,136 14,922 14,780 15,522 16,74511/10/2003 16,292 16,604 16,610 16,547 16,350 16,057 15,856 15,626 15,586 16,642 18,09211/13/2003 15,246 15,523 15,657 15,709 15,677 15,575 15,573 15,527 15,690 16,826 17,92711/14/2003 15,937 16,303 16,453 16,527 16,440 16,231 16,124 15,926 16,012 16,999 18,02411/17/2003 15,667 16,093 16,271 16,429 16,437 16,338 16,306 16,175 16,334 17,393 18,30811/18/2003 15,691 15,932 15,927 15,898 15,777 15,554 15,478 15,331 15,431 16,681 17,81311/19/2003 15,484 15,834 15,995 16,169 16,177 16,117 16,101 15,972 16,096 17,104 17,81811/20/2003 15,157 15,539 15,753 15,905 15,886 15,794 15,777 15,719 15,970 17,023 17,80311/24/2003 15,744 16,063 16,132 16,135 15,982 15,745 15,625 15,453 15,558 16,810 17,94011/25/2003 15,468 15,790 15,903 15,978 15,901 15,738 15,659 15,550 15,671 16,965 18,165

december 31, 2003 - iso new england · 2018-01-19 · dc_docs_a #1133532 v1 december 1, 2003. a...

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