NEPOOL Participants Committee Report

Transcription

1 N E P O O L P A R T I C I P A N T S C O M M I T T E E I S O - N E C O O R E P O R T J U N E D A T A C i r c u l a t e d J u l y 1 1, NEPOOL Participants Committee Report July 2016 Vamsi Chadalavada E X E C U T I V E V I C E P R E S I D E N T A N D C H I E F O P E R A T I N G O F F I C E R

2 Table of Contents Highlights Page 3 System Operations Page 10 Market Operations Page 20 Back-Up Detail Page 37 Load Response Page 38 New Generation Page 40 Forward Capacity Market Page 47 Reliability Costs - Net Commitment Period Compensation (NCPC) Operating Costs Page 54 Regional System Plan (RSP) Page 85 Operable Capacity Analysis Summer 2016 Page 113 Operable Capacity Analysis Appendix Page 120 2

3 Highlights Day-Ahead (DA), Real-Time (RT) Prices and Transactions Energy Market Value was $257M over the period, up $41M from May 2016 and up $11M from June 2015 June natural gas prices over the period were 9.7% higher than May 2016 average values Average RT Hub Locational Marginal Prices ($21.24/MWh) over the period were 0.3% lower than May 2016 averages Average June 2016 natural gas prices and RT Hub LMPs over the period were up 35% and up 8.3%, respectively, from June 2015 averages Average DA cleared physical energy during the peak hours as percent of forecasted load was 97.8% during June, down from 98.3% during May Underlying natural gas data furnished by: *DA Cleared Physical Energy is the sum of Generation and Net Imports cleared in the DA Energy Market 3

4 Highlights, cont. Daily Net Commitment Period Compensation (NCPC) June NCPC payments totaled $2.7M over the period, up $750K from May and down $6.6M from June 2015 First Contingency payments totaled $1.5M, down $370K from May $1.1M paid to internal resources, down $724K from May $149K charged to DALO, $905K to RT Deviations $439K paid to resources at external locations, up $354K from May $0 charged to DALO at external locations, $439K to RT Deviations Second Contingency payments totaled $865K, up $737K from May DA commitments required for NEMA Load Zone on 5 days of the month Voltage payments were $383K, up $383K from May NCPC payments over the period as percent of Energy Market value were 1.1% 4

5 Highlights, cont Economic Studies Draft reports were posted to the PAC website for stakeholder comment 2016 Economic Study NEPOOL Scenario Analysis Scope of work and high-level assumptions will be finalized at the July 13 PAC meeting Transmission Planning Process Guide has been updated to address changes to Solutions Study, Competitive Process, and Public Policy as a result of FERC Order

6 Forward Capacity Market (FCM) Highlights CCP #5 ( ) through CCP #6 ( ) Less than 100 MW of resources are non-commercial at this time CCP #7 ( ) Evaluation of new resources that were to be commercial on June 1 has commenced and will continue through the end of summer CCP #8 ( ) Second bilateral transaction window closed on May 6 and all transactions were accepted on June 10 Second reconfiguration auction will be August 1-3 CCP Capacity Commitment Period 6

7 FCM Highlights, cont. CCP #9 ( ) First reconfiguration auction was held on June 1-3 This is the first time a reconfiguration auction utilized a sloped demand curve CCP #10 ( ) On July 1, a compliance filing was made in accordance with FERC s May 2, 2016 order in Docket No. EL regarding the Dominion complaint related to self-composite offers for new summer capacity when the resource has equal or greater winter capacity First bilateral transaction window will be April 2017 First reconfiguration auction will be June

8 FCM Highlights, cont. CCP #11 ( ) On June 9, ISO filed a limited waiver with FERC so that RTEG resources that can no longer operate under the EPA rules can change their demand resource type to RTDR resources IMM s Retirement Delist Bid FERC filing will be made no later than July 15 Qualification Notification Letters for static delist bids and new generating capacity resources will be released on September 30 8

9 Highlights, cont. The lowest 50/50 and 90/10 Summer Operable Capacity Margin Week is projected for week beginning August 6, Natural gas pipeline construction and maintenance will continue through the summer Forecasting a net summer peak demand of 26,704 MW for the week beginning August 6,

10 SYSTEM OPERATIONS 10

11 System Operations Weather Patterns Boston Temperature: Below Normal (0.1 F) Max: 87 F, Min: 54 F Precipitation: 1.33 Below Normal Normal: 3.22 Hartford Temperature: Below Normal (-0.3 F) Max: 89 F, Min: 49 F Precipitation: Below Normal Normal: 3.85 Peak Load: 19,808 MW June 29, :00 (Hour ending) MLCC2: None OP-4 : None NPCC Simultaneous Activation of Reserve Events: None Minimum Generation Warnings & Events: Minimum Generation Warning 6/04/16, 03:00 6/04/16, 08:00 No Self Schedules Denied No Interchange cuts 11

12 2016 System Operations - Load Forecast Accuracy Dashboard Indicator Month J F M A M J J A S O N D Avg Mo Avg Day Max Day Min Summer Goal Rest of Year Goal Rest of Year Actual Summer Actual Rest of Year Goal < 1.5% Summer Goal < 2.6% 12

13 2016 System Operations - Load Forecast Accuracy cont. Dashboard Indicator Month J F M A M J J A S O N D Avg Mo Avg Day Max Day Min Summer Goal Rest of Year Goal Rest of Year Actual Summer Actual Rest of Year Goal < 1.5% Summer Goal < 2.6% 13

14 2016 System Operations - Load Forecast Accuracy cont. Target = 50% Plus/Minus = 5% J F M A M J J A S O N D Avg Above % Below % Avg Above Avg Below Avg All

15 2016 System Operations - Load Forecast Accuracy cont. 15

16 Monthly Recorded Net Energy for Load (NEL) and Weather Normalized NEL GR:nel Net Energy for Load (NEL) GR:wnnel Weather Normalized NEL 14,000 14,000 13,000 13,000 12,000 12,000 GWh 11,000 10,000 GWh 11,000 9,000 10,000 8,000 9,000 7,000 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC 8,000 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC Ann Tot (TWh): Ann Tot (TWh): NEPOOL NEL is the total net energy required to serve load and is analogous to RT system load. NEL is calculated as: Generation pumping load + net interchange where imports are positively signed. Current month s data may be preliminary. Weather normalized NEL may be reported on a one-month lag. 16

17 Monthly Peak Loads and Weather Normalized Seasonal Peak History 28,000 GR:PeakEnergy System Load 30,000 GR:SeasonalPeak Weather Normalized Seasonal Peaks 26,000 29,000 24,000 28,000 27,000 MW 22,000 20,000 MW 26,000 25,000 24,000 18,000 23,000 22,000 16,000 14,000 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC 21,000 20,000 F F Summer Winter Winter beginning in year displayed F designates forecasted values, which are updated in April/May of the following year; represents gross forecast 17

18 Wind Power Forecast Error Statistics: MAE Mean Absolute Error [%] Rolling 30-day MAE for ISO Wind Power Forecast, as of June 30, Individual Wind Plants Fleet Horizon [Hours Ahead] Dashboard Indicator Yearly Fleet Performance targets Ideally, MAE and Bias would be both equal to zero. As is typical, MAE increases with the forecast horizon. MAE and Bias for the fleet of wind power resources are less due to offsetting errors. Across all time frames, the ISO-NE/DNV-GL forecast is very good compared to industry standards, and monthly MAE is well within the yearly performance targets specified in the forecast RFP. 18

19 Wind Power Forecast Error Statistics: Bias Rolling 30-day Bias for ISO Wind Power Forecast, as of June 30, Individual Wind Plants Fleet Dashboard Indicator Yearly Fleet Performance targets Bias Error [%] Horizon [Hours Ahead] Ideally, MAE and Bias would be both equal to zero. Positive bias means less windpower was actually available compared to forecast. Negative bias means more windpower was actually available compared to forecast. Across all time frames, the ISO-NE/DNV-GL forecast compares well with industry standards, and June s monthly values are mostly within yearly performance targets specified in the forecast RFP. 19

20 MARKET OPERATIONS 20

21 Daily DA and RT ISO-NE Hub Prices and Input Fuel Prices: June 1-30, 2016 GR:Hubwgas $ $30.00 $ $24.00 Electricity Prices ($/MWh) $90.00 $60.00 $18.00 $12.00 Fuel Price ($/MMBtu) $30.00 $6.00 $0.00 $ /01/16 06/03/16 06/05/16 06/07/16 06/09/16 06/11/16 06/13/16 06/15/16 06/17/16 06/19/16 06/21/16 06/23/16 06/25/16 06/27/16 06/29/16 07/01/16 Underlying natural gas data furnished by: RT LMP DA LMP Natural Gas Average price difference over this period (DA-RT): $1.37 Average price difference over this period ABS(DA-RT): $5.46 Average percentage difference over this period ABS(DA-RT)/RT Average LMP: 26% Gas price is average of Massachusetts delivery points 21

22 DA LMPs Average by Zone & Hub, June 2016 $100 GR:DA_Bar ( 1.5%) 0.1% 1.0% 1.5% ( 0.8%) ( 0.7%) 0.6% 1.9% $80 $60 $/MWh $40 $20 $0 $-20 Hub ME NH VT CT RI SEMA WCMA NEMA LMP Congestion Marginal Losses ME - Maine NH New Hampshire VT Vermont CT Connecticut RI Rhode Island SEMA Southeastern Massachusetts WCMA Western/Central Massachusetts NEMA Northeastern Massachusetts 22

23 RT LMPs Average by Zone & Hub, June 2016 $100 GR:RT_Bar ( 1.8%) ( 0.2%) ( 0.2%) 1.7% ( 0.7%) ( 0.5%) 0.6% 2.2% $80 $60 $/MWh $40 $20 $0 $-20 Hub ME NH VT CT RI SEMA WCMA NEMA LMP Congestion Marginal Losses 23

24 Definitions Day-Ahead Concept Day-Ahead Load Obligation (DALO) Day-Ahead Cleared Physical Energy Definition The sum of day-ahead cleared load (including pump load), exports, and virtual purchases (excluding bulk losses) The sum of day-ahead cleared generation and cleared net imports 24

25 Components of Cleared DA Supply and Demand Last Three Months Supply Demand 22,500 GR:Graph36L 22,500 GR:Graph36R 20,000 20,000 17,500 17,500 Avg Hourly MW 15,000 12,500 10,000 7,500 Avg Hourly MW 15,000 12,500 10,000 7,500 5,000 5,000 2,500 2,500 0 APR2016 MAY2016 JUN APR2016 MAY2016 JUN2016 Gen Incs Imports DA Fcst Load Fixed Dem PrSens Dem Decs Losses Exports Act Load Gen Generation Incs Increment Offers DA Fcst Load Day-Ahead Forecast Load Fixed Dem Fixed Demand PrSens Dem Price Sensitive Demand Decs Decrement Bids Act Load Actual Load 25

26 Components of RT Supply and Demand Last Three Months Supply Demand 22,500 GR:Graph37L 22,500 GR:Graph37R 20,000 20,000 17,500 17,500 Avg Hourly MW 15,000 12,500 10,000 7,500 Avg Hourly MW 15,000 12,500 10,000 7,500 5,000 5,000 2,500 2,500 0 APR2016 MAY2016 JUN APR2016 MAY2016 JUN2016 Gen Imports Load Exports DA Fcst Load 26

27 DAM Volumes as % of RT Actual Load (Peak Hour) 140% 140% 130% 130% 120% 120% 110% 100% 90% 80% 70% 60% Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Jan-16 Feb-16 Mar-16 Apr-16 May-16 % of RT Actual Load Jun-16 % of Actual RT Load 110% 100% 90% 80% 70% 60% 1-Jun 2-Jun 3-Jun 4-Jun 5-Jun 6-Jun 7-Jun 8-Jun 9-Jun 10-Jun 11-Jun 12-Jun 13-Jun 14-Jun 15-Jun 16-Jun 17-Jun 18-Jun 19-Jun 20-Jun 21-Jun 22-Jun 23-Jun 24-Jun 25-Jun 26-Jun 27-Jun 28-Jun 29-Jun 30-Jun DA Bid Fixed DA Bid Price DALO DA Bid Fixed DALO 100% DA Bid Price DA Phys Clrd Energy Note: Percentages were derived for the peak hour of each day (shown on right), then averaged over the month (shown on left). Values at hour of forecasted peak load. 27

28 DA vs. RT Load Obligation: June, This Year vs. Last Year GR:Graph26 Monthly, Last 13 Months GR:Graph27 Daily, This Year vs. Last Year 99.2% 104% 99.0% 103% DA % of RT 98.8% 98.6% 98.4% 98.2% 98.0% 97.8% DA % of RT 102% 101% 100% 99% 98% 97% 96% 97.6% 95% 97.4% 94% 97.2% 97.0% 96.8% 93% 92% 91% JUN2015 JUL2015 AUG2015 SEP2015 OCT2015 NOV2015 DEC2015 JAN2016 FEB2016 MAR2016 APR2016 MAY2016 JUN2016 6/ 1 6/ 2 6/ 3 6/ 4 6/ 5 6/ 6 6/ 7 6/ 8 6/ 9 6/10 6/11 6/12 6/13 6/14 6/15 6/16 6/17 6/18 6/19 6/20 6/21 6/22 6/23 6/24 6/25 6/26 6/27 6/28 6/29 6/30 Last_Year This_Year *Hourly average values 28

29 DA Volumes as % of Forecast (Peak Hour) Monthly, Last 13 Months GR:dapce_dalo_pct_fxlo_fpk_mly_small Daily: This Month GR:dapce_dalo_pct_fxlo_fpk_dly_small 105% 112% Percentage of Peak Forecast Load 103% 101% 99.0% 97.0% 95.0% Percentage of Peak Forecast Load 108% 104% 100% 96.0% 92.0% 88.0% 84.0% 93.0% JUN2015 JUL2015 AUG2015 SEP2015 OCT2015 NOV2015 DEC2015 JAN2016 FEB2016 MAR2016 APR2016 MAY2016 JUN % 01JUN16 02JUN16 19JUN16 20JUN16 29JUN16 30JUN16 DA Cleared Physical Energy 100% line DALO 03JUN16 04JUN16 05JUN16 06JUN16 07JUN16 08JUN16 09JUN16 10JUN16 11JUN16 12JUN16 13JUN16 14JUN16 15JUN16 16JUN16 17JUN16 18JUN16 DA Cleared Physical Energy 100% line DALO 21JUN16 22JUN16 23JUN16 24JUN16 25JUN16 26JUN16 27JUN16 28JUN16 *Forecasted peak hour is reflected. 29

30 DA Cleared Physical Energy Difference from RT System Load at Peak Hour* GR:dapce_delta_fpk_dly_bar 1,500 1, DA Higher MWh ,000 DA Lower -1,500-2,000 01JUN JUN JUN JUN JUN JUN JUN JUN2016-2,500-3,000 09JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN2016 *Negative values indicate DA Cleared Physical Energy value below its RT counterpart. Forecast peak hour reflected. 28JUN JUN JUN

31 DA vs. RT Net Interchange June 2016 vs. June 2015 GR:Graph32 Hourly Average by Day, Last Year GR:Graph33 Hourly Average by Day, This Year 3,000 3,000 2,500 2,500 Net MWh 2,000 1,500 1,000 Net MWh 2,000 1,500 1, JUN15 02JUN15 03JUN15 04JUN15 05JUN15 06JUN15 07JUN15 08JUN15 09JUN15 10JUN15 11JUN15 12JUN15 13JUN15 14JUN15 15JUN15 16JUN15 17JUN15 18JUN15 19JUN15 20JUN15 21JUN15 22JUN15 23JUN15 24JUN15 25JUN15 26JUN15 27JUN15 28JUN15 29JUN15 30JUN15 01JUN16 02JUN16 03JUN16 04JUN16 05JUN16 06JUN16 07JUN16 08JUN16 09JUN16 10JUN16 11JUN16 12JUN16 13JUN16 14JUN16 15JUN16 16JUN16 17JUN16 18JUN16 19JUN16 20JUN16 21JUN16 22JUN16 23JUN16 24JUN16 25JUN16 26JUN16 27JUN16 28JUN16 29JUN16 30JUN16 Day-Ahead Real-Time Day-Ahead Real-Time Net Interchange is the sum of daily imports minus the sum of daily exports Positive values are net imports 31

32 Variable Production Cost of Natural Gas: Monthly GR:Var_Cost_Gas_Mly $160 $120 $80 $40 $0 JUN2014 JUL2014 AUG2014 SEP2014 NOV2014 DEC2014 JAN2015 FEB2015 MAR2015 OCT2014 Var Cost Gas APR2015 MAY2015 JUN2015 JUL2015 AUG2015 SEP2015 NOV2015 DEC2015 JAN2016 FEB2016 MAR2016 OCT2015 APR2016 MAY2016 JUN2016 Underlying natural gas data furnished by: Note: Assumes proxy heat rate of 7,800,000 Btu/MWh for natural gas units. 32

33 Variable Production Cost of Natural Gas: Daily GR:Var_Cost_Gas_Dly $160 $120 $80 $40 $0 01JUN JUN JUN JUN JUN JUN JUN2016 Var Cost Gas 08JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN2016 Underlying natural gas data furnished by: Note: Assumes proxy heat rate of 7,800,000 Btu/MWh for natural gas units. 33

34 Hourly DA LMPs, June 1-30, 2016 $125 $100 $75 $50 GR:DA_Hrly Hourly Day-Ahead LMPs Binding constraint on the New England-Boston Interface due to a planned equipment outage at the Tewksbury substation Binding constraint on the New England-Boston Interface due to the planned outages of the 337 (Sandy Pond- Tewksbury) and 338 (Tewksbury-Woburn) lines $25 $0 $/MWh $-25 $-50 $-75 $-100 $-125 $-150 $-175 $ Hub ME NH VT CT RI SEMA NEMA WCMA 34

35 Hourly RT LMPs, June 1-30, 2016 GR:RT_Hrly Hourly Real-Time LMPs $125 $100 $75 $50 Binding reserve constraint due to the planned outage of the aforementioned 337 line $25 $0 $/MWh $-25 $-50 $-75 $-100 $-125 $-150 $-175 $ Hub ME NH VT CT RI SEMA NEMA WCMA 35

36 System Unit Availability 100 Annual/Monthly Weighted Equivalent Availability Factor (WEAF) System WEAF Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual Year Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec YTD Data as of 7/11/16 36

37 BACK-UP DETAIL 37

38 LOAD RESPONSE 38

39 Capacity Supply Obligation (CSO) MW by Demand Resource Type for July 2016 Load Seasonal Zone RTDR* RTEG** On Peak Peak Total ME NH VT CT RI SEMA WCMA NEMA Total , ,277.3 * Real Time Demand Response ** Real Time Emergency Generation NOTE: CSO values include T&D loss factor (8%) and, as applicable, a reserve margin gross-up of either 14.3% or 16.1%, respectively, for portions of resources that selected a multi-year obligation in the FCA 1 or FCA 2. Otherwise, reserve margin gross-ups were discontinued with FCA 3. 39

40 NEW GENERATION 40

41 New Generation Update Based on Queue as of 7/1/16 No new projects have applied for interconnection study since the last update Three projects went commercial, five projects withdrew from the queue, and two projects had reductions in capacity, resulting in a net decrease in new generation projects of 305 MW In total, 81 generation projects are currently being tracked by the ISO, totaling approximately 11,500 MW 41

42 Actual and Projected Annual Capacity Additions By Supply Fuel Type and Demand Resource Type 6,000 Megawatts (MW) 5,000 4,000 3,000 2,000 1,000 0 Demand Response - Passive Demand Reponse - Active Wind/Other Renewables Oil Natural Gas/Oil Natural Gas -1, Total MW % of Total 1 Demand Response - Passive Demand Response - Active , Wind & Other Renewables , , Oil Natural Gas/Oil , ,695 4, Natural Gas , , Totals ,935 2,361 4,606 2,367 10, Sum may not equal 100% due to rounding 2 The projects in this category are dual fuel, with either gas or oil as the primary fuel 2016 values include the 94 MW of generation that has gone commercial in 2016 DR reflects changes from the initial FCM Capacity Supply Obligations in

43 Actual and Projected Annual Generator Capacity Additions By State Megawatts (MW) 5,000 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1, Vermont Rhode Island New Hampshire Maine Massachusetts Connecticut Total MW % of Total 1 Vermont Rhode Island , , New Hampshire Maine , , Massachusetts , , Connecticut , ,695 3, Totals 275 1,642 2,598 4,663 2,367 11, Sum may not equal 100% due to rounding 2016 values reflect the 94 MW of generation that has gone commercial in

44 New Generation Projection By Fuel Type Fuel Type No. of Projects Total Green Yellow Capacity (MW) No. of Projects Capacity (MW) No. of Projects Capacity (MW) Biomass/Wood Waste Hydro Landfill Gas Natural Gas 15 2, ,293 Natural Gas/Oil 11 4, ,192 Oil Solar Wind 30 4, ,791 Battery Storage Total 81 11, ,147 Projects in the Natural Gas/Oil category may have either gas or oil as the primary fuel Green denotes projects with a high probability of going into service Yellow denotes projects with a lower probability of going into service or new applications 44

45 New Generation Projection By Operating Type Operating Type No. of Projects Total Green Yellow Capacity (MW) No. of Projects Capacity (MW) No. of Projects Capacity (MW) Baseload Intermediate 22 5, ,806 Peaker 23 1, ,365 Wind Turbine 30 4, ,791 Total 81 11, ,147 Green denotes projects with a high probability of going into service Yellow denotes projects with a lower probability of going into service or new applications 45

46 New Generation Projection By Operating Type and Fuel Type Fuel Type No. of Projects Total Capacity (MW) No. of Projects Baseload Intermediate Peaker Capacity (MW) No. of Projects Capacity (MW) No. of Projects Capacity (MW) Wind Turbine No. of Projects Capacity (MW) Biomass/Wood Waste Hydro Landfill Gas Natural Gas 15 2, , Natural Gas/Oil 11 4, , Oil Solar Wind 30 4, ,065 Battery Storage Total 81 11, , , ,065 Projects in the Natural Gas/Oil category may have either gas or oil as the primary fuel 46

47 FORWARD CAPACITY MARKET 47

48 Capacity Supply Obligation FCA 6 Resource Type Resource Type FCA Proration Annual Bilateral for ARA 1 ARA 1 Annual Bilateral for ARA 2 ARA 2 Annual Bilateral for ARA 3 *CSO CSO **Change CSO Change CSO Change CSO Change CSO Change CSO Change CSO Change ARA 3 Demand Active Demand Passive Demand MW MW MW MW MW MW MW MW MW MW MW MW MW MW MW 2, , , , , , , , , , , , , Demand Total 3, , , , , , , , Generator Non- Intermittent 29, , , , , , , , , Intermittent Generator Total 30, , , , , , , , , Import Total 1, , , , , , , , ***Grand Total 36, , , , , , , , , Net ICR (NICR) 33,456 33, , , , , , ,391 0 * Real-time Emergency Generators (RTEG) CSO not capped at MW ** Change columns contain the changes in CSO amount resulting from the specific FCM Event as well as adjustments for Delisted MW released according to MR 1, Section , and changes that occurred (terminations, etc.) prior to the event reported in the column. *** Grand Total reflects both CSO Grand Total and the net total of the Change Column. 48

49 Capacity Supply Obligation FCA 7 FCA Proration Annual Bilateral for ARA 1 ARA 1 Annual Bilateral for ARA 2 ARA 2 Annual Bilateral for ARA 3 ARA 3 Resource Type Resource Type *CSO CSO **Change CSO Change CSO Change CSO Chang e CSO Change CSO Change CSO Change MW MW MW MW MW MW MW MW MW MW MW MW MW MW MW Active Demand 1, , Demand Passive Demand 1, , , , , , , , Demand Total 2, , , , , , , , Generator Non- Intermittent 30, , , , , , , , , Intermittent Generator Total 31, , , , , , , , , Import Total 1, , , , , , , , ***Grand Total 36, , , , , , , , , Net ICR (NICR) 32,968 32, , , , , , ,152 0 * Real-time Emergency Generators (RTEG) CSO not capped at MW ** Change columns contain the changes in CSO amount resulting from the specific FCM Event as well as adjustments for Delisted MW released according to MR 1, Section , and changes that occurred (terminations, etc.) prior to the event reported in the column. *** Grand Total reflects both CSO Grand Total and the net total of the Change Column. 49

50 Capacity Supply Obligation FCA 8 Resource Type Resource Type FCA Annual Bilateral for ARA 1 ARA 1 Annual Bilateral for ARA 2 ARA 2 Annual Bilateral for ARA 3 *CSO CSO Change CSO Change CSO Change CSO Change CSO Change CSO Change ARA 3 MW MW MW MW MW MW MW MW MW MW MW MW MW Active Demand 1, Demand Passive Demand 1, , , Demand Total 3, , , , Generator Non- Intermittent 28, , , , Intermittent Generator Total 29, , , , Import Total 1, , , , ***Grand Total 33, , , , Net ICR (NICR) 33,855 34, , ,061 0 * Real-time Emergency Generators (RTEG) CSO not capped at MW ** Change columns contain the changes in CSO amount resulting from the specific FCM Event as well as adjustments for Delisted MW released according to MR 1, Section , and changes that occurred (terminations, etc.) prior to the event reported in the column. *** Grand Total reflects both CSO Grand Total and the net total of the Change Column. 50

51 Capacity Supply Obligation FCA 9 Resource Type Resource Type FCA Annual Bilateral for ARA 1 ARA 1 Annual Bilateral for ARA 2 ARA 2 Annual Bilateral for ARA 3 *CSO CSO Change CSO Change CSO Change CSO Change CSO Change CSO Change ARA 3 MW MW MW MW MW MW MW MW MW MW MW MW MW Active Demand Demand Passive Demand 2, Demand Total 2, , , Generator Non- Intermittent 29, , , Intermittent Generator Total 30, , , Import Total 1, ***Grand Total 34, , Net ICR (NICR) 34,189 33, ,883 0 * Real-time Emergency Generators (RTEG) CSO not capped at MW ** Change columns contain the changes in CSO amount resulting from the specific FCM Event as well as adjustments for Delisted MW released according to MR 1, Section , and changes that occurred (terminations, etc.) prior to the event reported in the column. *** Grand Total reflects both CSO Grand Total and the net total of the Change Column. 51

52 Capacity Supply Obligation FCA 10 Resource Type Resource Type FCA Annual Bilateral for ARA 1 ARA 1 Annual Bilateral for ARA 2 ARA 2 Annual Bilateral for ARA 3 *CSO CSO Change CSO Change CSO Change CSO Change CSO Change CSO Change ARA 3 MW MW MW MW MW MW MW MW MW MW MW MW MW Active Demand Demand Passive Demand 2, Demand Total 2, Generator Non- Intermittent 30, Intermittent Generator Total 31, Import Total 1,449.8 ***Grand Total 35, Net ICR (NICR) 34,151 * Real-time Emergency Generators (RTEG) CSO not capped at MW ** Change columns contain the changes in CSO amount resulting from the specific FCM Event as well as adjustments for Delisted MW released according to MR 1, Section , and changes that occurred (terminations, etc.) prior to the event reported in the column. *** Grand Total reflects both CSO Grand Total and the net total of the Change Column. 52

53 Active/Passive Demand Response CSO Totals by Commitment Period Commitment Period Active/ Passive Existing New Grand Total Active Passive Grand Total Active Passive Grand Total Active Passive Grand Total Active Passive Grand Total Active Passive Grand Total Active Passive Grand Total Active Passive Grand Total Active Passive Grand Total Active Passive Grand Total Active Passive Grand Total

54 RELIABILITY COSTS NET COMMITMENT PERIOD COMPENSATION (NCPC) OPERATING COSTS 54

55 What are Daily NCPC Payments? Payments made to resources whose hourly commitment and dispatch by ISO-NE resulted in a shortfall between the resource s offered value in the Energy and Regulation Markets and the revenue earned from output over the course of the day Typically, this is the result of some out-of-merit operation of resources occurring in order to protect the overall resource adequacy and transmission security of specific locations or of the entire control area 55

56 Definitions 1 st Contingency NCPC Payments 2 nd Contingency NCPC Payments Voltage NCPC Payments Distribution NCPC Payments Delisted Units OATT Reliability costs paid to eligible resources that are providing first contingency (1stC) protection (including low voltage, system operating reserve, and load serving) either system-wide or locally Reliability costs paid to resources providing capacity in constrained areas to respond to a local second contingency. They are committed based on 2 nd Contingency (2ndC) protocols, and are also known as Local Second Contingency Protection Resources (LSCPR) Reliability costs paid to resources operated by ISO-NE to provide voltage support or control in specific locations Reliability costs paid to units dispatched at the request of local transmission providers for purpose of managing constraints on the low voltage (distribution) system. These requirements are not modeled in the DA Market software Resources within the control area that have requested to be classified as a non-installed capacity (ICAP) resource, and as such, are not required to offer their capacity into the DA Energy Market Open Access Transmission Tariff 56

57 Charge Allocation Key Allocation Category System 1 st Contingency External DA 1 st Contingency Zonal 2 nd Contingency System Low Voltage Zonal High Voltage Market / OATT Market Market Market OATT OATT Allocation DA 1 st C (excluding at external nodes) is allocated to system DALO. RT 1 st C (at all locations) is allocated to System Daily Deviations. Daily Deviations = sum of(generator deviations, load deviations, generation obligation deviations at external nodes, increment offer deviations) DA 1 st C at external nodes (from imports, exports, Incs and Decs) are allocated to activity at the specific external node or interface involved DA and RT 2 nd C NCPC are allocated to load obligation in the Reliability Region (zone) served (Low) Voltage Support NCPC is allocated to system Regional Network Load and Open Access Same-Time Information Service (OASIS) reservations High Voltage Control NCPC is allocated to zonal Regional Network Load Distribution - PTO OATT Distribution NCPC is allocated to the specific Participant Transmission Owner (PTO) requesting the service System Other Market Includes GPA, Min Generation Emergency, and Generator and DARD NCPC 57

58 Year-Over-Year Total NCPC Dollars and Energy GR:Graph23 NCPC Dollars GR:Graph23m NCPC Energy* $80 1,100 $70 $60 1, $ Millions $40 GWh $ $20 $ $0 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC 0 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC * NCPC Energy GWh reflect the DA and/or RT economic minimum loadings of all units receiving DA or RT NCPC credits, assessed during hours in which they are NCPC-eligible. All NCPC components (1 st Contingency, 2 nd Contingency, Voltage, and RT Distribution) are reflected. 58

59 DA and RT NCPC Charges GR:Graph01 JUN-16 Total = $2.74 M GR:Graph02 Last 13 Months $50 $40 49% Millions $30 $20 51% $10 $0 JUN2015 JUL2015 AUG2015 SEP2015 OCT2015 NOV2015 DEC2015 JAN2016 FEB2016 MAR2016 APR2016 MAY2016 JUN2016 Day-Ahead Real-Time Day-Ahead Real-Time 59

60 NCPC Charges by Type GR:Graph03 JUN-16 Total = $2.74 M GR:Graph04 Last 13 Months 54% $50 $40 Millions $30 $20 14% $10 $0 32% JUN15 JUL15 AUG15 SEP15 OCT15 NOV15 DEC15 JAN16 FEB16 MAR16 APR16 MAY16 JUN16 1st C Voltage 2nd C 1st C Voltage 2nd C Distrib 1 st C First Contingency 2 nd C Second Contingency Distrib Distribution Voltage Voltage 60

61 Daily NCPC Charges by Type $600 GR:ncpc_bytype_stack_dly $500 $400 Thousand $300 $200 $100 $0 01JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN2016 1st C 2nd C Voltage Distribution 61

62 NCPC Charges by Allocation 0.8% GR:xpie_ncpc_chgs_alloc_cat JUN-16 Total = $2.74 M 48% GR:xchart_ncpc_chgs_alloc_cat Last 13 Months $40.0 $ % 0.0% 6.7% 9.6% Millions $24.0 $16.0 $8.0 $0.0 32% 4.4% JUN15 JUL15 AUG15 SEP15 OCT15 NOV15 DEC15 JAN16 FEB16 MAR16 APR16 MAY16 JUN16 System 1stC Zonal 2ndC Zonal High V System Other Ext DA 1stC System Low V Dist - PTO System 1stC Zonal 2ndC Zonal High V System Other Ext DA 1stC System Low V Dist - PTO 62

63 RT First Contingency Charges by Deviation Type GR:pie_firstc_rt_bydev JUN-16 Total = $1.26 M GR:chart_firstc_rt_bydev_13mo Last Months 13.7% 14.6% $6 $5 7.9% Millions $4 $3 $2 $1 $0 63.9% JUN15 JUL15 AUG15 SEP15 OCT15 NOV15 DEC15 JAN16 FEB16 MAR16 APR16 MAY16 JUN16 Gen Inc Import Load Gen Inc Import Load Gen Generator deviations Inc Increment Offer deviations Imp Import deviations Load Load obligation deviations 63

64 LSCPR Charges by Zone $12.0 GR:lscpr_charges_byzone_13mo $11.0 $10.0 $9.0 $8.0 Millions $7.0 $6.0 $5.0 $4.0 $3.0 $2.0 $1.0 $0.0 JUN15 JUL15 AUG15 SEP15 OCT15 NOV15 DEC15 JAN16 FEB16 MAR16 APR16 MAY16 JUN16 CT ME NEMA NH RI SEMA VT WCMA CT Connecticut Region ME Maine Region NH New Hampshire Region RI Rhode Island Region VT Vermont Region SEMA Southeast Massachusetts Region WCMA Western/Central Massachusetts Region NEMA Northeast Massachusetts Region EXT External Locations 64

65 NCPC Charges for Voltage Support and High Voltage Control $1.5 GR:var_charges_stack_13mo $1.4 $1.3 $1.2 $1.1 $1.0 $0.9 Millions $0.8 $0.7 $0.6 $0.5 $0.4 $0.3 $0.2 $0.1 $0.0 JUN15 JUL15 AUG15 SEP15 OCT15 NOV15 DEC15 JAN16 FEB16 MAR16 APR16 MAY16 JUN16 DA HV NCPC DA LV NCPC RT HV NCPC RT LV NCPC 65

66 NCPC Charges by Type $175 $174.6 GR:NCPC_Stack Value of Charges $150 $125 $118.1 Millions $100 $75 $50 $25 $ $ $7.3 JAN2016 $2.8 FEB2016 $4.3 MAR2016 $4.0 APR2016 $2.0 MAY2016 $2.7 JUN2016 JUL2016 AUG2016 SEP2016 OCT2016 NOV2016 DEC2016 1st C 2nd C Distr Voltg 66

67 NCPC Charges as Percent of Energy Market 5.0% NCPC By GR:NCPC_pct_Stack Type as Percent of Energy Market 4.0% 3.0% Percent 2.0% 1.0% 1.9% 2.0% 1.3% 1.6% 0.9% 1.9% 1.5% 0.9% 1.1% 0.0% JAN2016 FEB2016 MAR2016 APR2016 MAY2016 JUN2016 JUL2016 AUG2016 SEP2016 OCT2016 NOV2016 DEC2016 1st C 2nd C Distr Voltg 67

68 First Contingency NCPC Charges $140 $135.2 GR:Graph19 Value of Charges 4.0% GR:Graph20 % of Energy Market Value $120 $ % Millions $80 $60 $40 $20 $0 $70.0 $21.0 $7.0 $2.6 $4.2 $3.8 $1.9 $ % 1.0% 0.0% 1.5% 1.2% 1.2% 1.6% 0.8% 1.9% 1.4% 0.9% 0.6% JAN2016 FEB2016 MAR2016 APR2016 MAY2016 JUN2016 JUL2016 AUG2016 SEP2016 OCT2016 NOV2016 DEC JAN2016 FEB2016 MAR2016 APR2016 MAY2016 JUN2016 JUL2016 AUG2016 SEP2016 OCT2016 NOV2016 DEC2016 Note: Energy Market value is the hourly locational product of load obligation and price in the DA Market plus the hourly locational product of price and RT Load Obligation Deviation in the RT Market 68

69 Second Contingency NCPC Charges GR:Graph21 Value of Charges GR:Graph22 % of Energy Market Value $50 $ % $40 $ % Millions $30 $20 2.4% 1.6% $10 $0 $1.1 $0.0 $0.0 $0.0 $0.1 $0.1 $ % 0.0% 0.4% 0.7% 0.1% 0.0% 0.0% 0.1% 0.3% JAN2016 FEB2016 MAR2016 APR2016 MAY2016 JUN2016 JUL2016 AUG2016 SEP2016 OCT2016 NOV2016 DEC JAN2016 FEB2016 MAR2016 APR2016 MAY2016 JUN2016 JUL2016 AUG2016 SEP2016 OCT2016 NOV2016 DEC2016 Note: Energy Market value is the hourly locational product of load obligation and price in the DA Market plus the hourly locational product of price and RT Load Obligation Deviation in the RT Market 69

70 Voltage and Distribution NCPC Charges GR:Graph17 Value of Charges GR:Graph18 % of Energy Market Value $40 4.0% $30 3.0% Millions $20 2.0% $10 $7.0 $ % $0 $1.0 $0.3 $0.1 $0.1 $0.1 $ % 0.1% 0.1% 0.1% 0.1% 0.0% 0.0% 0.0% 0.1% JAN2016 FEB2016 MAR2016 APR2016 MAY2016 JUN2016 JUL2016 AUG2016 SEP2016 OCT2016 NOV2016 DEC JAN2016 FEB2016 MAR2016 APR2016 MAY2016 JUN2016 JUL2016 AUG2016 SEP2016 OCT2016 NOV2016 DEC2016 Note: Energy Market value is the hourly locational product of load obligation and price in the DA Market plus the hourly locational product of price and RT Load Obligation Deviation in the RT Market 70

71 DA vs. RT Pricing The following slides outline: This month vs. prior year s average LMPs and fuel costs Reserve Market results DA cleared load vs. RT load Zonal and total incs and decs Self-schedules DA vs. RT net interchange 71

72 DA vs. RT LMPs ($/MWh) Arithmetic Average Year 2014 NEMA CT ME NH VT RI SEMA WCMA Hub Day-Ahead $64.98 $64.10 $61.95 $64.12 $63.82 $64.98 $64.71 $64.66 $64.57 Real-Time $64.03 $63.11 $59.04 $61.48 $61.60 $63.34 $63.45 $63.29 $63.32 RT Delta % -1.5% -1.5% -4.7% -4.1% -3.5% -2.5% -2.0% -2.1% -1.9% Year 2015 NEMA CT ME NH VT RI SEMA WCMA Hub Day-Ahead $42.56 $41.23 $40.81 $42.11 $41.58 $42.20 $42.23 $41.93 $41.90 Real-Time $41.58 $40.58 $39.23 $40.21 $40.22 $41.03 $41.21 $40.96 $41.00 RT Delta % -2.3% -1.6% -3.9% -4.5% -3.3% -2.8% -2.4% -2.3% -2.2% June-15 NEMA CT ME NH VT RI SEMA WCMA Hub Day-Ahead $21.46 $21.89 $20.83 $21.08 $21.04 $20.95 $21.05 $21.25 $21.16 Real-Time $19.79 $20.13 $19.34 $19.53 $19.39 $19.41 $19.53 $19.66 $19.61 RT Delta % -7.8% -8.1% -7.2% -7.3% -7.9% -7.4% -7.2% -7.5% -7.3% June-16 NEMA CT ME NH VT RI SEMA WCMA Hub Day-Ahead $23.04 $22.94 $22.28 $22.63 $22.83 $22.43 $22.45 $22.75 $22.61 Real-Time $21.71 $21.61 $20.85 $21.20 $21.20 $21.10 $21.13 $21.36 $21.24 RT Delta % -5.8% -5.8% -6.4% -6.3% -7.1% -5.9% -5.9% -6.1% -6.1% Annual Diff. NEMA CT ME NH VT RI SEMA WCMA Hub Yr over Yr DA 7.4% 4.8% 7.0% 7.4% 8.5% 7.0% 6.7% 7.1% 6.9% Yr over Yr RT 9.7% 7.3% 7.8% 8.5% 9.4% 8.7% 8.2% 8.6% 8.3% 72

73 Monthly Average Fuel Price and RT Hub LMP Indexes GR:Graph March 2003= MAR2003 JUN2003 SEP2003 DEC2003 MAR2004 JUN2004 SEP2004 DEC2004 MAR JUN2005 SEP2005 DEC2005 MAR2006 JUN2006 SEP2006 Natural Gas DEC2006 MAR2007 JUN2007 SEP2007 DEC2007 MAR2008 JUN2008 SEP2008 DEC2008 MAR2009 JUN2009 SEP2009 DEC2009 MAR2010 JUN2010 SEP2010 Hub RT LMP DEC2010 MAR2011 JUN2011 SEP2011 DEC2011 MAR2012 JUN2012 SEP2012 DEC2012 MAR2013 JUN2013 SEP2013 DEC2013 MAR2014 JUN2014 SEP2014 DEC2014 MAR2015 JUN2015 SEP2015 DEC2015 MAR2016 JUN2016 SEP2016 Underlying natural gas data furnished by: 73

74 Monthly Average Fuel Price and RT Hub LMP $30.00 $27.00 GR:hubwgas_mly_smd $ $24.00 $ $21.00 $/MMBtu (Fuel) $18.00 $15.00 $12.00 $ $80.00 $/MWh (Electricity) $9.00 $6.00 $40.00 $3.00 MAR2003 JUN2003 SEP2003 DEC2003 MAR2004 JUN2004 SEP2004 DEC2004 MAR2005 JUN2005 $0.00 JUN2006 SEP2006 DEC2006 MAR2007 JUN2007 SEP2007 DEC2007 MAR2008 JUN2008 SEP2008 DEC2008 MAR2009 JUN2009 SEP2009 DEC2009 MAR2010 JUN2010 SEP2005 DEC2005 MAR2006 Natural Gas JUN2011 SEP2011 DEC2011 MAR2012 JUN2012 SEP2012 DEC2012 MAR2013 JUN2013 SEP2013 DEC2013 MAR2014 JUN2014 SEP2014 DEC2014 MAR2015 JUN2015 SEP2010 DEC2010 MAR2011 Hub RT LMP SEP2015 DEC2015 MAR2016 JUN2016 SEP2016 $0.00 Underlying natural gas data furnished by: 74

75 New England, NY, and PJM Real Time Prices GR:three_pools_prices_mly Monthly, Last 13 Months GR:three_pools_prices_dly Daily: This Month $36 $50 $34 Electricity Prices ($/MWh) $32 $30 $28 $26 $24 $22 $20 $18 Electricity Prices ($/MWh) $40 $30 $20 $10 $16 JUN2015 JUL2015 AUG2015 SEP2015 OCT2015 NOV2015 DEC2015 JAN2016 ISO-NE NY-ISO PJM FEB2016 MAR2016 APR2016 MAY2016 JUN2016 $0 01JUN16 02JUN16 03JUN16 04JUN16 05JUN16 09JUN16 10JUN16 11JUN16 12JUN16 13JUN16 14JUN16 15JUN16 16JUN16 17JUN16 18JUN16 19JUN16 20JUN16 21JUN16 22JUN16 23JUN16 24JUN16 25JUN16 26JUN16 06JUN16 07JUN16 08JUN16 ISO-NE NY-ISO PJM 27JUN16 28JUN16 29JUN16 30JUN16 *Note: Hourly average prices are shown. *Note: Hourly average prices are shown. 75

76 New England, NY, and PJM Real Time Prices (Peak Hour) GR:three_pools_prices_fpk_mly Monthly, Last 13 Months GR:three_pools_prices_fpk_dly Daily: This Month $100 $300 $90 Electricity Prices ($/MWh) $80 $70 $60 $50 $40 $30 Electricity Prices ($/MWh) $200 $100 $20 JUN2015 JUL2015 AUG2015 SEP2015 OCT2015 NOV2015 DEC2015 JAN2016 ISO-NE NY-ISO PJM FEB2016 MAR2016 APR2016 MAY2016 JUN2016 $0 01JUN16 02JUN16 03JUN16 04JUN16 05JUN16 09JUN16 10JUN16 11JUN16 12JUN16 13JUN16 14JUN16 15JUN16 16JUN16 17JUN16 18JUN16 19JUN16 20JUN16 21JUN16 22JUN16 23JUN16 24JUN16 25JUN16 26JUN16 06JUN16 07JUN16 08JUN16 ISO-NE NY-ISO PJM 27JUN16 28JUN16 29JUN16 30JUN16 *Forecasted New England peak hour is reflected. 76

77 Reserve Market Results June 2016 Maximum potential Forward Reserve Market payments of $7.2M were reduced by credit reductions of $426K, failure-toreserve penalties of $641K and failure-to-activate penalties of $0, resulting in a net payout of $6.1M or 85% of maximum Rest of System: $1.92M/$1.97M (97%) Southwest Connecticut: $0.70M/$0.71M (98%) Connecticut: $1.55M/$1.67M (93%) NEMA: $1.99M/$2.86M (69%) $379K total Real-Time credits were reduced by $139K in Forward Reserve Energy Obligation Charges for a net of $240K in Real-Time Reserve payments Rest of System: 63 hours, $106K Southwest Connecticut: 63 hours, $9K Connecticut: 63 hours, $7K NEMA: 69 hours, $118K * Failure to reserve results in both credit reductions and penalties in the Locational Forward Reserve Market. 77

78 LFRM Charges to Load by Load Zone ($) $25.0 LFRM Charges GR:Graph39 by Zone, Last 13 Months $20.0 $15.0 Millions $10.0 $5.0 $0.0 JUN15 JUL15 AUG15 SEP15 OCT15 NOV15 DEC15 JAN16 FEB16 MAR16 APR16 MAY16 JUN16 CT ME NEMA NH RI SEMA VT WCMA 78

79 Zonal Increment Offers and Cleared Amounts June Monthly GR:Graph28 Totals by Zone MWh 160, , , , , , ,000 90,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10, Hub ME NH VT CT RI SEMA WCMA NEMA Cleared Offered 79

80 Zonal Decrement Bids and Cleared Amounts 60,000 June Monthly GR:Graph29 Totals by Zone 50,000 40,000 MWh 30,000 20,000 10, Hub ME NH VT CT RI SEMA WCMA NEMA Cleared Bid 80

81 Total Increment Offers and Decrement Bids 1,100,000 1,000, , , ,000 Zonal GR:Graph30 Level, Last 13 Months MWh 600, , , , , ,000 0 JUN2015 JUL2015 AUG2015 SEP2015 OCT2015 NOV2015 DEC2015 JAN2016 FEB2016 MAR2016 APR2016 MAY2016 JUN2016 INC DEC INC DEC INC DEC INC DEC INC DEC INC DEC INC DEC INC DEC INC DEC INC DEC INC DEC INC DEC INC DEC Data excludes nodal offers and bids Cleared Bid/Offered 81

82 Dispatchable vs. Non-Dispatchable Generation 14,000 Total Monthly GR:Graph31 Energy; Dispatchable % Shown 12, % 45.4% 10,000 8, % 45.2% 54.3% 45.4% 43.1% 45.2% 41.1% 40.9% GWh 48.9% 43.2% 43.7% 6,000 4,000 2,000 0 JUN2015 JUL2015 AUG2015 SEP2015 OCT2015 NOV2015 DEC2015 JAN2016 FEB2016 MAR2016 APR2016 MAY2016 JUN2016 Non-Dispatchable Dispatchable * Dispatchable MWh here are defined to be generation output that is not self-scheduled (i.e, not self-committed or must run by the customer). 82

83 Rolling Average Peak Energy Rent (PER) $0.20 GR:rolling_avg_per_big $0.16 $/KW-Month $0.12 $0.08 $0.04 $0.00 JUN15 JUL15 AUG15 SEP15 OCT15 NOV15 DEC15 JAN16 FEB16 MAR16 APR16 MAY16 JUN16 month CT ME NEMA ROP Rolling Average PER is currently calculated as a rolling twelve month average of individual monthly PER values for the twelve months preceding the obligation month. Individual monthly PER values are published to the ISO web site here: Home > Markets > Other Markets Data > Forward Capacity Market > Reports and are subject to resettlement. 83

84 PER Adjustments $6.0 GR:fcm_per_adj_byzone_big $5.0 Millions ($) $4.0 $3.0 $2.0 $1.0 $0.0 JUN15 JUL15 AUG15 SEP15 OCT15 NOV15 DEC15 JAN16 FEB16 MAR16 APR16 MAY16 JUN16 CT ME NEMA ROP month PER Adjustments are reductions to Forward Capacity Market monthly payments resulting from the rolling average PER. 84

85 REGIONAL SYSTEM PLAN (RSP) 85

86 Planning Advisory Committee (PAC) July 13 PAC Meeting Agenda Transmission Planning Process Guide and Technical Guide Updates SEMA/RI 2026 Solution Study Update 1231/ kv Line Clearance Remediation NERC Standard CIP-014 Physical Security 2016 Economic Study Update 86

87 Load, Energy Efficiency and PV Forecast Load Forecast 2016 ten-year load forecast is complete and was published in the 2016 CELT that was posted to the ISO-NE website on May 2 On July 8, the Load Forecast Committee met to kick off development of next year s forecast and discuss the key factors that may impact forecast changes for next year Energy Efficiency (EE) Forecast On July 7, the EEWG discussed the roll-out data collection process that will occur three months earlier than last year Distributed Generation Forecast Working Group (DGFWG) The next DGFWG meeting is scheduled for October to kick off the next forecast cycle 87

88 Environmental Matters EAG meeting held on June 28 discussed regulatory updates including: 2016 Regional Greenhouse Gas Initiative (RGGI) program review (modeling more stringent annual CO2 reduction targets 2.5% annual reductions through 2020, 5% annual reductions post-2020). Extended schedule announced and RGGI review expected to wrap up in early ozone season exceedances (YTD) Follow-up on ISO actions regarding RTEGs after EPA prohibited their use under OP-4 after May 2, 2016 Follow-up from Kain v. MassDEP (May 2016) MassDEP to undertake a round of rulemaking to set greenhouse gas emissions limits for yet-to-be-determined source categories MassDEP Commissioner Suuberg indicated all options, including carbon tax, are under consideration 88

89 Economic Studies The ISO issued draft reports for the three economic studies requested in 2015 Submit comments to By July 27, comments are due on the Draft 2015 Economic Study Evaluation of Increasing the Keene Road Export Limit report and the Draft 2015 Economic Study Evaluation of Offshore Wind Deployment report By August 9, comments are due on the Draft 2015 Economic Study Strategic Transmission Analysis Onshore Wind Integration 2016 Economic Study NEPOOL Scenario Analysis Scope of work and assumptions were discussed with PAC and will be finalized at the July 13 PAC meeting ISO is working towards discussion of preliminary draft Phase I results at the August 18 PAC meeting Overall project remains on schedule to complete Phase I production cost analysis by the end of 2016 and to begin Phase II analysis in 1 st Quarter

90 RSP Project Stage Descriptions Stage Description 1 Planning and Preparation of Project Configuration 2 Pre-construction (e.g., material ordering, project scheduling) 3 Construction in Progress 4 In Service 90

91 Connecticut River Valley Status as of 7/11/16 Project Benefit: Addresses system needs in the Connecticut River Corridor in Vermont Expected Present Upgrade In-Service Stage Rebuild 115 kv line K31, Coolidge-Ascutney May-18 1 Ascutney Substation - Add a +50/-25 MVAR dynamic reactive device May-18 1 Hartford Substation - Split 25 MVAR capacitor bank into two 12.5 MVAR banks April-17 1 Chelsea Station - Rebuild to a three-breaker ring bus Oct-17 1 Note: The above listing focuses on major transmission line construction and rebuilding. 91