NEPOOL Participants Committee Meeting - ISO New England

Document Sample
NEPOOL Participants Committee Meeting - ISO New England Powered By Docstoc
					NEPOOL Participants Committee Meeting

            April 4, 2003

             Boston, MA


                                   Stephen G. Whitley
                          Senior Vice President & COO
Agenda

 •    System Operations
 •    Gas Study Initiative
 •    SMD Market Operations Update
 •    Summer 2003 – “A Look Ahead”
 •    ISO/NEPOOL Cost Causation
      Update
 •    Demand Response Kickoff Update
 •    Back – Up Details
     –   Demand Response
     –   New Generation                2
     –   SW CT/Boston
System Operations




                    3
    Operation’s Highlights

•   Boston & Hartford Weather Pattern:
     – Temperatures were below the average (longest sustained 6-month period
        in 50 years) with normal to above normal precipitation.
•   Peak Load
     – Peak load of 18,039 MW at 20:00 hours on March 31.
•   During March
     – Minimum Generation on March 22 & 28.
     – Requested Shared Activation of Reserves (SAR) – March 5, 7 and 20(2);
        Provided SAR on March 29.
     – Resources postured on March 22, 23, 28 and 30.
     – Emergency Sales on March 3.
     – Solar Magnetic Disturbances – K7 forecasts on March 17 & 18.
     – The following were not implemented in March:
          • M/S#2;
          • M/S#3;
          • OP#4; and,
          • Class 6 Load Management.                                  4
Gas Study




            5
Gas Study Update

• Northeast very dependent on gas storage during
  winter heating season.
• Too much cold weather beginning in November –
  January 2003 – Almost a peak design/month.
• Depletion of working gas storage inventories.
• Maintenance of line pack is a daily issue.
• LNG is OK (Distrigas).
• ISO-NE is performing a post-winter assessment
  to determine the capacity impacts on gas-fired
  generation.
                                          6
        Gas Study Update
        Winter Capacity of Gas Capable Units
                        Primary Primary No.2          Primary Other
                            Gas      Fuel Oil       No.6 Fuel    fuel
   SMD       Gas        w/No.2         w/Gas        Oil w/Gas w/Gas
  Zone      Only       Fuel Oil       Backup           Backup Backup Totals
CT            778        1,636          -                 902   -     3,316
ME          1,365          349          -                 -     108   1,822
NEMA        1,868            83         117               623         2,691
NH            -          1,305          -                 400         1,705
RI          2,046          -            -                 -           2,046
SEMASS      1,360        1,335            56            1,118         3,869
VT            -            -            -                 -       53     53
WCMA          173        1,187          354               115         1,829
Totals      7,590        5,895          527             3,158   161 17,331

Includes 2003 units: AES GRANITE RIDGE, MILFORD PDC, SITHE FORE RIVER, SITHE MYSTIC


                                                                                      7
                       Gas Study Update
                                 Temperature Impacts on Gas-Fired
                                 Generating Capacity, 12/02 – 3/03
               2,400                                                                     60


               2,000                                                                     50


               1,600                                                                     40




                                                                                              Temp. @ Peak
MW Curtailed




               1,200                                                                     30


                800                                                                      20


                400                                                                      10


                  0                                                                      0
                       12/1    12/15   12/29   1/12   1/26   2/9     2/23   3/9   3/23

                              Peak Day Temp.    MW    Temp. @ Peak
                                                                                                    8
Gas Study Update – Scope of
Work
“A Natural Gas Assessment & Reliability Implications for New
England’s Electric Generation Sector” Natural Gas:
       1) Assume Salem Harbor Is Converted To Fire
          1.1 Assume final technology will attain compliance with the MA DEP 310
              CMR 7.29 by October 2004 or October 2006.
          1.2 Assume Salem Harbor’s conversion to fire natural gas uses existing
              infrastructure & design (steam turbine generator mode) and reflects
              minimization of costs.
          1.3 Discuss whether residual fuel oil or distillate oil is a viable primary or
              backup fuel.

       2) Assess Natural Gas Supply Issues:
          2.1 Discuss the uncertainties surrounding natural gas supplies from North
              America, including Sable Island, Gulf Coast, Western Canada, and LNG.
          2.1 Discuss current exploration and production (E&P) outlook in Atlantic
              Canada, including retrenchment of Canadian majors, expiry profiles, and
              production constraints.
          2.2 Discuss current issues concerning maturation of the resource base in North
              America, accelerated “depletion rates,” storage issues affecting the
              Northeast, and gas price volatility parameters.
          2.3 Discuss potential electric sector impacts from sustained high natural gas
              prices.
          2.4 Discuss Canadian and U.S. regulatory issues associated with transport
              pricing on TransCanada Pipeline (TCPL), Iroquois Gas Transmission
              System (IGTS), Portland Natural Gas Transmission System (PNGTS), and
              Maritime & Northeast (M&N).
          2.5 Discuss supply issues relative to LNG sources and increased worldwide        9
              demand.
Gas Study Update – Scope of Work,
cont.
“
A Natural Gas Assessment & Reliability Implications for New
England’s Electric Generation Sector”
   Assess Natural Gas Deliverability Issues Affecting New England:
      3.1 Discuss on a seasonal basis (winter & summer), the current and future
          deliverability concerns impacting both New England, and in particular, the
          transmission constrained greater Boston-area load pocket.
      3.2 Discuss current and future LNG supply adequacy concerns impacting New
          Mystic station.
      3.3 Discuss deliverability issues in Items 3.1 & 3.2, both with and without
          Salem Harbor as a natural gas fired facility.
      3.4 For Items 3.1, 3.2, & 3.3, discuss seasonal (winter and summer) electric
          sector reliability issues relating to:
                  3.4.1 Impacts associated with new Homeland Security
                           requirements (to be defined).
                  3.4.2 Postulated discontinued LNG refills at the Distrigas
                           terminal in Everett (short duration), including loss of truck-
                           transported liquids.
                  3.4.3 Postulated discontinued LNG refills at the Distrigas
                           terminal in Everett (long duration), including loss of truck-
                           transported liquids.
                  3.4.4 Potential impacts due to gas-side contingencies.
                  3.4.5 Post-contingency sustainability issues surrounding
                           emergency pipeline supplies from other New England
                           pipelines. Addressed both with and without a New Mystic
                           connection to HubLine through the proposed Everett               10
                           lateral.
       Gas Study Update – Scope of Work,
       cont.

       “A Natural Gas Assessment & Reliability Implications for New
       England’s Electric Generation Sector”



Assess Fuel Diversity Concerns:
          4.1 Discuss seasonal electric sector reliability issues surrounding New England
              merchant generators’ growing reliance on natural gas.
          4.2 Discuss overall portfolio concerns about decreasing fuel diversity for both New
              England, and in particular, the transmission constrained greater Boston sub-area.
          4.3 Discuss the relationship between fuel diversity and volatility events at gas market
              hubs in New England.
          4.4 Discuss impacts both with and without Salem Harbor burning natural gas.




                                                                                         11
SMD Operations




                 12
     SMD Experience in March

•   Standard Market Design (SMD) cut-over was virtually
    seamless.
•   The March implementation date was designed to allow
    for a learning curve prior to the summer.
•   Energy prices were consistent with the cost of fuel:
     – Higher fuel costs in the first few weeks created higher
        energy prices; and,
     – Recently, energy prices have decreased consistent with
        the downward trend of fuel prices.
•   Software and business systems have generally worked well
    and functioning as designed.
     – Limited number of hardware and software issues,
        resulted in interruption of data flow.            13
SMD Experience in March (cont.)
•   Potential for error is elevated during this learning process:
     – Internally
         • Data – issues such as Non-PTF Loss Factors
         • Operator Error – RT dispatch or selection in day ahead
     – Externally
         • Methods used to reflect “Seller Choice” strategies
         • Self Scheduling
•   Internal decisions reviewed and business process and software tools
    enhanced to mitigate potential for repeat.
•   No reliability issues since going live.
•   NERC Control Performance within criteria.
•   Conditions experienced in Real-time so far:
     – Congestion;
     – Excess ramping curtailments;
     – Minimum generation emergency;
     – Major generation contingencies; and,                       14
     – Emergency sales.
SMD Action Plan

                         Action                                      Date
Computer Systems
   Data availability and navigation improvements to the   May – June 2003
     web site.
   List servers in addition to web postings.              Special notices now
                                                            available.
Customer Forums
    Outage Coordination                                   April
    SMD Unit Commitment and Market Mitigation             May
    SMD Markets Forum                                     Fall
Online Forums
    Summer Operational and Market Issues                  As needed.
Customer Training
    FTR/ARR re-offer with QUA’s                           May
    Virtual Markets Workshop                              June
    Capacity Market Workshop                              September/October
    Full SMD Training re-offer                            September/October



                                                                                  15
           Day-ahead & Real-time Prices,
           ISO-NE Hub
                                                         March 2003

        $140.00



        $120.00



        $100.00
                                                                                           Average Spread
                                                                                           (DA - RT): $1.39
         $80.00
$/MWh




         $60.00
                        Ave. % DA Pool Generation Cleared
                              vs. Forecast Load: 91%
         $40.00
                          Ave. % DA Demand Cleared
                            vs. Forecast Load: 96%
         $20.00



          $0.00
           03/01/2003      03/06/2003       03/11/2003       03/16/2003       03/21/2003   03/26/2003         03/31/2003

                                                                Date

                                                  Average DA Price     Average RT Price


                                                                                                                16
         Day Ahead – LMP Average by Zone & Hub

                                                                March 2003




        $70.00          (-1.3)        (-1.4)     (+0.1)               (-2.7)    (-2.8)




        $50.00
$/MWh




        $30.00




        $10.00




                  Hub            ME        NH         VT       CT          RI    SEMASS   WCMASS    NEMASS
                                                                                                    & Bos ton
        -$10.00

                                                             Region

                        LMP                    Marginal Loss Component               Congestion Component



                                                                                                                17
         Real Time – LMP Average by Zone & Hub

                                                             M arch 2003

                        (-5.7)        (-1.5)    (+0.1)    (+0.1)    97.4%
                                                                     (-2.6)        (-2.0)
        $70.00




        $50.00
$/MWh




        $30.00




        $10.00




                  Hub            ME        NH        VT        CT             RI     SEMASS WCMASS NEMASS
        -$10.00                                                                                    & Boston

                                                            Region


                            LMP                  Marginal Loss Component                    Congestion Component

                                                                                                                   18
                                                                                       $/MWh
                                         3/
                                            1/
                                              03
                                                 0




                                                          25
                                                               50
                                                                    75
                                                                                                             100
                                                                                                                   125
                                                                                                                         150
                                                                                                                               175
                                                                                                                                     200




                                                      0
                                         3/
                                            2/ 1
                                              03
                                         3/      0
                                            3/ 1
                                              03
                                         3/      0
                                            4/ 1
                                              03
                                         3/      0
                                            5/ 1
                                              03
                                         3/      0
                                            6/ 1
                                              03
                                         3/      01
                                            7




                WCMASS
                                     03 /0 3
                                        /0
                                           8 01
                                     03 /03
                                        /0




 RHODEISLAND
                                           9 01
                                      03 /03
                                         /1
                                            0 01
                                      03 /03
                                         /1      01
                                            1
                                      03 /03
                                         /1      01
                                            2
                                      03 /03
                                         /1




 SEMASS
                                                 01
                                            3
                                      03 /03
                                         /1      01
                                     3/ 4 /0




                CONNECTICUT
                                       15 3
                                          /2 0
                                     3/ 00 1
                                       16 3
                                          /2 0
                                     3/ 00 1
                                       17 3
                                          /2 0
                                                                                                                                                        Real-time LMP




                                     3/ 00 1
                                       18 3
                                          /2 0




                MAINE
                                                                                                                                           March 2003




                               Day
                                     3/ 00 1
                                       19 3




 VERMONT
                                          / 2 01
                                     3/ 00
                                       20 3
                                          / 2 01
                                     3/ 00
                                       21 3
                                          /2 0
                                     3/ 00 1
                                       22 3
                                          /2 0
                                     3/ 00 1
                                       23 3
                                          /2 0
                                     3/ 00 1
                                       24 3
                                          /2 0
                                     3/ 00 1
                                       25 3
                                          / 2 01
                                     3/ 00
                NEMASSBOST



                                       26 3
                                          / 2 01
 INTERNAL_HUB



                                     3/ 00
                                       27 3
                                          /2 0
                                     3/ 00 1
                                                                         Emergencies




                                       28 3
                                          /2 0
                                                                                       Minimum Generat ion




                                     3/ 00 1
                                       29 3
                                          /2 0
                                     3/ 00 1
                                       30 3
                                          /2 0
                                     3/ 00 1
                                       31 3
                                          / 2 01
                                             00
                                               3
                NEWHAMPSHIRE




                                                 01
19
        DAM LMP
                                                                  March 2003

        220


        200            No signif icant t r ansmission out ages;
                            Maine and NEMASSBOST
                           Congest ion r esult ed Bidding
        180                           Pat t er ns




        160

                                                                           303 Line Ter minal OOS;
        140
                                                                    C129N- 2 Line const r ained f or L/ O 315
                                                                                                                                          1977 OOS; 1710 Line
                                                                                      Line
                                                                                                                                       const r ained f or L/ O 1480
                                                                                                                                                 Bus Tie
        120
$/MWh




                                                                                                                   PV20 was OOS
                                                                                                                                                                       379 OOS, Vir t ual Bids;
                                                                                                                      causing
                                                                                                                                                                      Result ing congest ion on
                                                                                                                   congest ion on
        100                                                                                                           NWVT_I
                                                                                                                                                                         W149 f or L/ O 340




         80


         60


         40
                                                                                                                                379 OOS, Vir t ual Bids;
                                                                                                                          Result ing congest ion on W149
                                                                                                                                     f or L/ O 340
         20


          0
               2/ 1

               3/ 1

               4/ 1

               5/ 1

               6/ 1

               7/ 1

                /0 1




        3/ 00 1

        3/ 00 1

        3/ 00 1

        3/ 00 1

        3/ 00 1

        3/ 00 1

        3/ 00 1

        3/ 00 1
             / 2 01

                      01
            09 01

            10 01

            11 01

            12 1

            13 01

            14 01

            15 1

            16 01

            17 01

            18 1

            19 01

            20 01

            21 01

             / 2 01
                      0

                      0

                      0

                      0

                      0

                      0

            08 0




             /2 0

             /2 0

             /2 0

             /2 0

             /2 0

             /2 0

             /2 0

             /2 0
          3/ 3 0




          3/ 3 0




          3/ 3 0
                  03

                  03

                  03

                  03

                  03

                  03

          3/ 0 3




          23 3

          24 3

          25 3

          26 3

          27 3

          28 3

          29 3

          30 3

          31 3

                    3
          3/ 3



          3/ 3

          3/ 3



          3/ 3

          3/ 3



          3/ 3

          3/ 3

          3/ 3

          22 3
          3/ 3

          3/ 3




        3/ 00




                00
                 /0

                 /0

                 /0

                 /0

                 /0

                 /0

                 /0

                 /0

                 /0

                 /0

                 /0

        3/ / 0
                /0
               1/
            3/

            3/

            3/

            3/

            3/

            3/

            3/




                                                                                     Day

              CONNECTICUT                 MAINE                               NEMASSBOST                        NEWHAMPSHIRE                           RHODEISLAND
              SEMASS                      VERMONT                             WCMASS                            INTERNAL_HUB

                                                                                                                                                                                              20
Summer 2003




              21
  Summer 2003 Capacity Assessment
  Least Operable Capacity Margin - Weeks beginning June 7, 14 and 21

                                                    MW
Projected Peak (50/50)                             25,120
Operating Reserve Required                          1,700
Total Operable Cap. Required                       26,820
Projected Capacity                                 31,920
Assumed Outages                                     3,600
Total Capacity                                     28,320
Operable Capacity Margin                            1,500
                                                                       22
Summer 2003 Capacity Assessment
                            ISO-NE 2003 OPERABLE CAPACITY ANALYSIS
                    March 15, 2003 - WITH KNOWN EXTERNAL CONTRACTS - 50th PERCENTILE PLE
        This analysis is a tabulation of weekly assessments shown in one single table. The information shows the operable capacity situation under assumed conditions for each
        week. It is not expected that the system peak will occur every week during June, July a

Week Beginning, Saturday

                          Installed
                         Seasonal Interchange                                                                             Allowance
                          Claimed    (NYPP,                                                     Operating                     for               Extent of OP 4 Actions That
                         Capability NB, HQ,                   New             Peak Load          Reserve                  Unplanned Operable      May be Necessary (OP 4
                            (SCC)   Highgate,              Generation   Net   Exposure         Requirement    Total Known Outages   Capacity     Actions up to and including)




                                                    Note
 Year      Month     Day [Note 1] Block Load)               [Note 2] Capacity [Note 3]           [Note 4]     Maintenance [Note 6] Margin (+/-)           [Note 7]
                            (MW)      (MW)                   (MW)      (MW)     (MW)              (MW)           (MW)       (MW)     (MW)
2003       May        31   27,974      550                   3,400    31,920   21,580             1,700          1,000      2,800    4,840
2003       June       7    27,974      550                   3,400    31,920   25,120             1,700           800       2,800    1,500
                      14    27,974        550               3,400     31,920      25,120          1,700            800          2,800        1,500
                      21    27,974        550               3,400     31,920      25,120          1,700            800          2,800        1,500
                      28    27,936        550               3,400     31,890      25,120          1,700            100          2,800        2,170
2003        July       5    27,936        550               3,400     31,890      25,120          1,700            100          2,100        2,870
                      12    27,936        550               3,400     31,890      25,120          1,700            100          2,100        2,870
                      19    27,936        550               3,400     31,890      25,120          1,700            100          2,100        2,870
                      26    27,937        550               3,400     31,890      25,120          1,700            100          2,100        2,870
2003      August       2    27,937        550               3,500     31,990      25,120          1,700            100          2,100        2,970
                       9    27,937        550               3,500     31,990      25,120          1,700            100          2,100        2,970
                      16    27,937        550               3,500     31,990      25,120          1,700            200          2,100        2,870
                      23    27,937        550               3,500     31,990      25,120          1,700            300          2,100        2,770
                      30    27,937        550               3,500     31,990      25,120          1,700            500          2,100        2,570
2003 September         6    27,937        550               3,500     31,990      23,100          1,700           1,100         2,100        3,990
                      13    27,937        550               3,500     31,990      21,850          1,700            800          2,100        5,540
                      20    27,937        550               3,500     31,990      21,520          1,700           2,000         2,100        4,670
                      27    29,994        550               3,500     34,040      21,440          1,700           1,200         2,100        7,600
2003      October      4    29,994        710               3,500     34,200      17,310          1,700           3,900         2,800        8,490

             Notes: Please note that the information contained within the Capacity Analysis is a deterministic projection of system conditions which could materialize during any
                    given week of the year.
                 1. Installed Capability per March 1, 2003 SCC Report and adjusted for known generator additions.
                 2. New Generation information as assumed by ISO-NE Planning Department and rounded to the nearest hundred.
                 3. Peak Load Exposure per the preliminary April 2003 CELT Report.
                 4. Operating Reserve Requirement based on the first contingency (Generator at 1160 MW) plus 1/2 the second contingency (Generator at 1145 MW).
                 5. Highgate maintenance scheduled.
                 6. Allowance for Unplanned Outages includes: forced outages and maintenance outages scheduled less than 14 days in advance.
                                                                                                                                                                                    23
                 7. Relief from certain OP 4 Actions varies, depending on system conditions.
Summer 2003 Capacity Assessment




                                  24
  Summer 2003 Capacity Assessment
  Least Operable Capacity Margin - Weeks beginning June 7, 14 and 21

                              MW
Projected Peak (90/10)       26,630
Operating Reserve Required    1,700
Total Operable Cap. Required 28,330
Projected Capacity           31,920
Assumed Outages               3,600
Total Capacity               28,320
Operable Capacity Margin            (10)
                                                                       25
Summer 2003 Capacity Assessment
                                    ISO-NE 2003 OPERABLE CAPACITY ANALYSIS
                           March 15, 2003 - WITH KNOWN EXTERNAL CONTRACTS - 90th PERCENTILE PLE
        This analysis is a tabulation of weekly assessments shown in one single table. The information shows the operable capacity situation under assumed conditions for each week. It is not
        expected that the system peak will occur every week during June, July a

Week Beginning, Saturday
                            Installed
                           Seasonal Interchange                                                                           Allowance        Operable
                            Claimed    (NYPP,                                                  Operating                      for          Capacity                 Extent of OP 4 Actions That
                           Capability NB, HQ,                 New             Peak Load         Reserve                   Unplanned       Margin (+/-)  Operable      May be Necessary (OP 4
                              (SCC)   Highgate,            Generation   Net   Exposure        Requirement     Total Known Outages          With HQ      Capacity     Actions up to and including)




                                                    Note
 Year      Month     Day   [Note 1] Block Load)             [Note 2] Capacity [Note 3]          [Note 4]      Maintenance [Note 6]           FEC       Margin (+/-)           [Note 7]
                              (MW)      (MW)                 (MW)      (MW)     (MW)             (MW)            (MW)       (MW)            (MW)         (MW)
2003       May        31     27,974      550                 3,400    31,920   22,880            1,700           1,000      2,800           3,540        3,540
2003       June       7      27,974      550                 3,400    31,920   26,630            1,700            800       2,800            (10)         (10)                 Action 5
                      14     27,974      550                 3,400    31,920   26,630            1,700            800       2,800            (10)         (10)                 Action 5
                      21     27,974      550                 3,400    31,920   26,630            1,700            800       2,800            (10)         (10)                 Action 5
                      28     27,936      550                 3,400    31,890   26,630            1,700            100       2,800            660          660
2003        July      5      27,936      550                 3,400    31,890   26,630            1,700            100       2,100           1,360        1,360
                      12     27,936      550                 3,400    31,890   26,630            1,700            100       2,100           1,360        1,360
                      19     27,936      550                 3,400    31,890   26,630            1,700            100       2,100           1,360        1,360
                      26     27,937      550                 3,400    31,890   26,630            1,700            100       2,100           1,360        1,360
2003      August      2      27,937      550                 3,500    31,990   26,630            1,700            100       2,100           1,460        1,460
                      9      27,937      550                 3,500    31,990   26,630            1,700            100       2,100           1,460        1,460
                      16     27,937      550                 3,500    31,990   26,630            1,700            200       2,100           1,360        1,360
                      23     27,937      550                 3,500    31,990   26,630            1,700            300       2,100           1,260        1,260
                      30     27,937      550                 3,500    31,990   26,630            1,700            500       2,100           1,060        1,060
2003 September        6      27,937      550                 3,500    31,990   24,490            1,700           1,100      2,100           2,600        2,600
                      13     27,937      550                 3,500    31,990   23,170            1,700            800       2,100           4,220        4,220
                      20     27,937      550                 3,500    31,990   22,820            1,700           2,000      2,100           3,370        3,370
                      27     29,994      550                 3,500    34,040   22,730            1,700           1,200      2,100           6,310        6,310
2003      October     4      29,994      710                 3,500    34,200   18,000            1,700           3,900      2,800           7,800        7,800

             Notes: Please note that the information contained within the Capacity Analysis is a deterministic projection of system conditions which could materialize during any given week of the
                    year.
                 1. Installed Capability per March 1, 2003 SCC Report and adjusted for known generator additions.
                 2. New Generation information as assumed by ISO-NE Planning Department and rounded to the nearest hundred.
                 3. Peak Load Exposure per the preliminary April 2003 CELT Report.
                 4. Operating Reserve Requirement based on the first contingency (Generator at 1160 MW) plus 1/2 the second contingency (Generator at 1145 MW).
                 5. Highgate maintenance scheduled.
                 6. Allowance for Unplanned Outages includes: forced outages and maintenance outages scheduled less than 14 days in advance.                                         26
                 7. Relief from certain OP 4 Actions varies, depending on system conditions.
Summer 2003 Capacity Assessment




                                  27
Cost Causation for System
       Upgrades



                            28
     Transmission Cost Allocation
     Workshops

1. ISO-NE presented “staff recommendation” for transmission
   cost allocation at the fourth and final stakeholder workshop
   on March 14.
2. Workshop participants included regulators from all six New
   England states and the FERC. (ISO-NE Board members
   also in attendance).
3. ISO-NE invited further comment beyond the workshop.
4. Next steps:
    1. Present ISO-NE staff proposal to NECPUC and
       NEPOOL Tariff Committee (April);
    2. Investigate least-cost-planning and resource parity
       issues with NECPUC and NEPOOL (April-June);
    3. Present proposal to NPC and ISO-NE Board (May);
       and,                                              29
ISO-NE Cost Allocation Method
Proposal

1. ISO-NE/NEPOOL define upgrade categories.
2. Through RTEP, ISO staff recommends to
    SPARC/BOD each upgrade’s assignment to the
    appropriate category.
3. If the assignment can be reasonably made to both local
    or regional, Regional Cost Allocation is utilized.
4. Regional Mechanism – Project is “Regionalized” for
    the life of the project if:
   • Project provides loop/network benefits… 2-way
       traffic; and,
   • Project is 115-kV and above.
5. Any discretionary costs are borne by the entity
    requiring the special design (e.g. entities requesting
                                                        30
    underground).
       System Upgrade Categories

A.   Generator Interconnections                       Direct Assignment
     • Generator interconnection in accordance with
       “minimum inter-connection standard.”

B.   Participant Funding                              Voluntary among Participants

C.   Load Interconnection                             Direct Assignment to Load
     • Second feed to industrial substation.
D.   Local                                            Individual sub-areas
     • Radial transmission line.
     • 13-kV capacitor bank.
     • Project that does not improve inter-area
       transfer capability.
E.   Regional or Network                              Load Pro-rata (roll in)
     • Loop/network project that increase inter-
       area transfer capability. Two-way traffic.
     • Phase shifting transformer, FACTS device.
                                                                                  31
Demand Response Summit




                         32
New England Demand Response
Summit
                         Radisson Hotel
                      75 Felton Street
                     Marlborough, MA
                       April 17, 2003
                   8:30 a.m. – 12:00 p.m.
 8: 30 – 9:00    Registration and Continental Breakfast
                 Visit Exhibitor Booths
 9:00 – 9: 20    Welcome and Opening Remarks
                 “What is Demand Response and How Can Customers Benefit”
                  Steve Whitley, Chief Operating Officer, ISO New England Inc.
 9:20 – 10:30    Case Studies and Lessons Learned:
                 Presentations by customers, utilities and competitive suppliers describing their
                 experiences participating in the 2002 Demand Response Programs. Learn first-
                 hand from customers what it takes to successfully participate in a program, the
                 benefits they received and their lessons learned.
 10:30 – 10:45   Break
 10:45 – 11:15   Technology for Demand Response
                 Presentations by leading metering, technology and software providers
                 describing how their products and services have helped customers reduce load
                 and participate in the Demand Response Programs. In addition, learn about the
                 other benefits these technologies and information services deliver.
 11:15 – 11:45   What’s New for 2003?
                 Presentations by ISO New England on the changes and new programs for 2003.
 11:45 – Noon    Q&A and Closing Comments                                                           33
Back-Up Details




                  34
          Demand Response
          (as of March 31, 2003)


Active:       212 Assets    284.0 MW        Pending: 15 Asset     7.5 MW
 Zone      Assets   RT     RT 30- Profiled Assets      RT     RT 30- Profiled
                   Price    Min      *                Price    Min      *
CT              88    38.3    18.2    76.6        13      0.2     4.5
ME              29    20.3            65.0
NEMA            19    26.0     7.2      1.4        4              1.9
NH               2     0.1     0.4
RI               7     0.8
SEMA            14     1.7     0.8                 1              0.4
VT               7     1.1     2.0      5.0
WCMA            46     4.8     7.1      7.3        1              0.5
Total         212     93.1    35.7   155.2        19      0.2     7.3      0.0
  * Represents former Type 2 Interruptible Loads
                                                                        35
      New Generation Update (Revised)


• No new generating resources were added in March
• Approximately 3,382 MW expected by June 2003
• Generation Projects as of March 14, 2003
                              No.       MW
        In Construction        6        3,382
        with 18.4 approval

        Not in Construction    5        1,783
        with 18.4 Approval
                                                36
 RMR Contracts

• NRG
  – NRG filed Cost-of-Service RMR Contracts on February 26.
  – Annual fixed cost of about $180 million, including $44 million
    for normal and deferred maintenance.
  – FERC issued an order on NRG’s emergency motion on March
    25, putting the “Reliability Cost Tracker” in place effective
    February 27.
  – ISO-NE to serve as escrow agent for these funds.
• PPL
  – PPL Requesting Cost of Service RMR Contracts for Wallingford
    Station – Four of Five Nominal 45MW Peaking Units.
  – Filed on January 16, 2003. FERC issued Deficiency Letter on
    February 28, 2003.
  – PPL responded on March 31 and stated they will file an 18.4
    Application for temporary deactivation effective July 1, 2003.
                                                               37
  RMR Contracts
              (cont.)




• PG&E (PGET and USGen New England)

  – Considering filing an 18.4 Application for Salem Harbor 1-4
    effective October 1, 2004.
  – Governor has stated that units must be in environmental
    compliance by that date or shut down.
  – PG&E was planning environmental upgrades for compliance
    by October 1, 2006.
  – October 1, 2004 date is under appeal before a DEP ALJ.
  – ISO in discussion with DOER and DTE, National Grid and
    NSTAR on NEMA reliability needs and possible transmission
    improvements.

                                                            38

				
DOCUMENT INFO
Shared By:
Categories:
Tags:
Stats:
views:3
posted:8/21/2012
language:Unknown
pages:38