NEPOOL Participants Committee Report

Transcription

1 NEPOOL Participants Committee Report July 2017 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 23 Back-Up Detail Page 40 Load Response Page 41 New Generation Page 43 Forward Capacity Market Page 50 Reliability Costs - Net Commitment Period Compensation (NCPC) Operating Costs Page 56 Regional System Plan (RSP) Page 87 Operable Capacity Analysis Summer 2017 Page 116 Operable Capacity Analysis Appendix Page 123 2

3 Highlights Day-Ahead (DA), Real-Time (RT) Prices and Transactions Energy market value was $300M, up $17M from May 2017 and up $43M from June 2016 June natural gas prices over the period were 19% lower than May 2017 average values Average RT Hub Locational Marginal Prices ($23.93/MWh) over the period were 19% lower than May 2017 averages Year-over-year natural gas prices and RT Hub LMPs during the month were up 7% and 13%, respectively, from June 2016 averages Average DA cleared physical energy during the peak hours as percent of forecasted load was 96% during June, down from 97.2% 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 $3.2M over the period, down $2.4M from May 2017 and up $844K from June 2016 First Contingency* payments totaled $2.8M, down $1.7M from May $2.6M paid to internal resources, down $1.4M from May» $685K charged to DALO, $1.3M to RT Deviations, $601K to RTLO $227K paid to resources at external locations, down $335K from May» $70K charged to DALO at external locations, $157K to RT Deviations Second Contingency payments totaled $308K, down $679K from May Voltage payments totaled $90K, up $17K from May NCPC payments over the period as percent of Energy Market value were 1.1% * NCPC types reflected in the First Contingency Amount: Dispatch Lost Opportunity Cost (DLOC) - $217K; Rapid Response Pricing (RRP) Opportunity Cost - $308K; Posturing - $75K; Generator Performance Auditing (GPA) - $2K; 4

5 Highlights, cont Economic Study - NEPOOL Scenario Analysis Phase I observations and key messages are complete, and the draft report is expected to be issued in July Order 1000 implementation The 2017 Planning for Public Policy cycle is complete. Feedback has been received from stakeholders. ISO presented its position at the June PAC meeting that a Public Policy Transmission Study is not required. RSP17 has been posted to the ISO website for stakeholder comment Formal written comments are due by July 24 and all comments will be reviewed at the August 3 PAC meeting RSP17 Public Meeting is scheduled for September 14 in Boston 5

6 Forward Capacity Market (FCM) Highlights CCP #8 ( ) Monthly activities have commenced New, non-commercial resources are attempting to cover in the monthly activities CCP #9 ( ) Second bilateral window was May 1-5, and results were posted on June 9 Second reconfiguration auction will be August 1-3 CCP #10 ( ) First reconfiguration auction was June 5-7, and results were posted on June 21 Second bilateral transaction window will be May 2-4, 2018 Second reconfiguration auction will be August 1-3, 2018 CCP Capacity Commitment Period 6

7 FCM Highlights, cont. CCP #11 ( ) First bilateral transaction window will be April 4-6, 2018 First reconfiguration auction will be June 1-5, 2018 CCP #12 ( ) Retirement and permanent delist bids have been reviewed by the Internal Market Monitor and cost determinations were released on June 22. FERC filing will be made no later than July 21. Existing resource static delist bids were due June 5 Static delist bid finalization window is September 29 October 6 New Resource Qualification Packages were due on June 19. Some resources have already withdrawn from the qualification process. Qualification determination letters will be released no later than September 29. 7

8 FERC Order 1000 Public Policy Tariff revisions to the Public Policy Transmission Study process timeline have been accepted by FERC Public Policy process was initiated on January 11 Stakeholders made presentations regarding Public Policy Requirements at the February 23 PAC meeting Stakeholder input was submitted and it was made available to NESCOE on March 1 NESCOE provided a communication to the ISO regarding Public Policy on May 1 ISO presented its position that a Public Policy Transmission Study is not needed to address any federal, state, or local Public Policy Requirements at the June PAC meeting 8

9 Highlights, cont. The lowest 50/50 and 90/10 Summer Operable Capacity Margins are projected for week beginning July 1,

10 SYSTEM OPERATIONS 10

11 System Operations Weather Patterns Boston Temperature: Above Normal (1.5 F) Max: 95 F, Min: 47 F Precipitation: 4.69 Above Normal Normal: 3.22 Hartford Temperature: Below Normal (-0.3 F) Max: 96 F, Min: 44 F Precipitation: Below Normal Normal: 3.85 Peak Load: 23,708 MW June 13, :00 (ending) MLCC2: None None None OP-4 : None None None NPCC Simultaneous Activation of Reserve Events: Date Area MW 6/8 PJM /12 NYISO 536 6/13 IESO 800 6/16 ISO-NE 726 6/26 NYISO

12 System Operations, cont. Minimum Generation Warnings & Events: Minimum Generation Warnings Minimum Generation Events None None 12

13 2017 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% 13

14 2017 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% 14

15 2017 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

16 2017 System Operations - Load Forecast Accuracy cont. 16

17 Monthly Recorded Net Energy for Load (NEL) and Weather Normalized NEL 14,000 Net Energy for Load (NEL) GR:nel 14,000 Weather Normalized NEL GR:wnnel 13,000 13,000 12,000 12,000 GWh 11,000 GWh 11,000 10,000 10,000 9,000 9,000 8,000 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. 17

18 Monthly Peak Loads and Weather Normalized Seasonal Peak History 28,000 System Peak Load GR:PeakEnergy 29,000 Weather Normalized Seasonal Peaks GR:SeasonalPeak 26,000 28,000 24,000 27,000 26,000 22,000 25,000 MW 20,000 MW 24,000 23,000 18,000 22,000 16,000 21,000 20,000 F F 14,000 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC , Summer Winter *Revenue quality metered value Winter beginning in year displayed Reflects net forecast (i.e., the gross forecast net of passive demand response and behind-the-meter solar demand); F designates forecasted values, updated in April/May of the following year; Forecasted winter peak reflects passive DR sourced from the capacity auction. This may underestimate passive DR performance and overestimate the (forecasted) winter peak 18

19 Wind Power Forecast Error Statistics: Medium and Long Term Forecasts MAE 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 within the yearly performance targets. 19

20 Wind Power Forecast Error Statistics: Medium and Long Term Forecasts Bias Dashboard Indicator Yearly Fleet Performance targets 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 monthly Bias is within yearly performance targets. 20

21 Wind Power Forecast Error Statistics: Short Term Forecast MAE 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 within the yearly performance targets. 21

22 Wind Power Forecast Error Statistics: Short Term Forecast Bias Dashboard Indicator Yearly Fleet Performance targets 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 monthly Bias is within yearly performance targets. 22

23 MARKET OPERATIONS 23

24 Daily Average DA and RT ISO-NE Hub Prices and Input Fuel Prices: June 1-30, 2017 $ GR:Hubwgas $30.00 $ $24.00 Electricity Prices ($/MWh) $90.00 $60.00 Hot weather and high loads $18.00 $12.00 Fuel Price ($/MMBtu) $30.00 $6.00 $0.00 $ /01/17 06/03/17 06/05/17 06/07/17 06/09/17 06/11/17 06/13/17 06/15/17 06/17/17 06/19/17 06/21/17 06/23/17 06/25/17 06/27/17 06/29/17 07/01/17 Underlying natural gas data furnished by: RT LMP DA LMP Natural Gas Average price difference over this period (DA-RT): $1.55 Average price difference over this period ABS(DA-RT): $5.29 Average percentage difference over this period ABS(DA-RT)/RT Average LMP: 22% Gas price is average of Massachusetts delivery points 24

25 DA LMPs Average by Zone & Hub, June 2017 $60 $50 GR:DA_Bar ( 2.7%) ( 1.6%) ( 0.4%) 2.1% ( 0.6%) ( 0.6%) 0.4% ( 0.0%) $40 $30 $/MWh $20 $10 $0 $-10 $-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 25

26 RT LMPs Average by Zone & Hub, June 2017 $60 $50 GR:RT_Bar ( 4.4%) ( 2.0%) ( 1.4%) 3.8% ( 0.5%) ( 0.4%) 0.4% 3.5% $40 $30 $/MWh $20 $10 $0 $-10 $-20 Hub ME NH VT CT RI SEMA WCMA NEMA LMP Congestion Marginal Losses 26

27 Definitions Day-Ahead Concept Day-Ahead Load Obligation (DALO) Day-Ahead Cleared Physical Energy Definition The sum of day-ahead cleared load (including asset load, pump load, exports, and virtual purchases and excluding modeled transmission losses) The sum of day-ahead cleared generation and cleared net imports 27

28 Components of Cleared DA Supply and Demand Last Three Months Supply Demand 22,500 GR:Graph36L 20,000 22,500 GR:Graph36R 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 APR2017 MAY2017 JUN APR2017 MAY2017 JUN2017 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 28

29 Components of RT Supply and Demand Last Three Months Supply Demand 22,500 GR:Graph37L 20,000 22,500 GR:Graph37R 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 APR2017 MAY2017 JUN APR2017 MAY2017 JUN2017 Gen Imports Load Exports DA Fcst Load 29

30 Jun-16 Jul-16 Aug-16 Sep-16 Oct-16 Nov-16 Dec-16 Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 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 % of RT Actual Load % of RT Actual Load DAM Volumes as % of RT Actual Load (Peak Hour) 130% 130% 120% 120% 110% 110% 100% 100% 90% 90% 80% 80% 70% 70% 60% 60% DA Bid Fixed DALO 100% DA Bid Priced 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. DA Bid categories reflect internal load asset bidding behavior (Virtual demand and export bid behavior not reflected). DA Bid Fixed DALO 100% DA Bid Priced DA Phys Clrd Energy 30

31 DA vs. RT Load Obligation: June, This Year vs. Last Year 99.4% Monthly, Last 13 Months GR:Graph26 104% Daily, This Year vs. Last Year GR:Graph27 DA % of RT 99.2% 99.0% 98.8% 98.6% 98.4% 98.2% 98.0% 97.8% 97.6% 97.4% 97.2% 97.0% 96.8% 96.6% JUN2016 JUL2016 AUG2016 SEP2016 OCT2016 NOV2016 DEC2016 JAN2017 FEB2017 MAR2017 APR2017 MAY2017 JUN2017 DA % of RT 103% 102% 101% 100% 99% 98% 97% 96% 95% 94% 93% 92% 91% 6/ 1 6/ 2 6/ 3 6/ 4 6/ 5 6/ 6 6/ 7 6/ 8 6/ 9 6/10 6/12 6/13 6/11 Last_Year 6/14 6/15 6/16 6/17 6/18 6/19 6/20 6/21 This_Year 6/22 6/23 6/24 6/25 6/26 6/27 6/28 6/29 6/30 *Hourly average values 31

32 DA Volumes as % of Forecast in Peak Hour GR:dapce_dalo_pct_fxlo_fpk_mly_small 106% Monthly, Last 13 Months GR:dapce_dalo_pct_fxlo_fpk_dly_small 112% Daily: This Month 104% 108% Percentage of Peak Forecast Load 102% 100% 98.0% 96.0% 94.0% JUN2016 JUL2016 AUG2016 SEP2016 OCT2016 NOV2016 DA Cleared Physical Energy 100% line DEC2016 JAN2017 DALO FEB2017 MAR2017 APR2017 MAY2017 JUN2017 Percentage of Peak Forecast Load 104% 100% 96.0% 92.0% 88.0% 84.0% 80.0% 01JUN17 02JUN17 03JUN17 04JUN17 05JUN17 06JUN17 07JUN17 08JUN17 09JUN17 10JUN17 11JUN17 12JUN17 13JUN17 14JUN17 15JUN17 16JUN17 17JUN17 DA Cleared Physical Energy 100% line 18JUN17 DALO 19JUN17 20JUN17 21JUN17 22JUN17 23JUN17 24JUN17 25JUN17 26JUN17 27JUN17 28JUN17 29JUN17 30JUN17 *Supplemental commitments for capacity during the Reserve Adequacy Assessment (RAA) process during April were zero. 32

33 GR:dapce_delta_fpk_dly_bar DA Higher DA Cleared Physical Energy Difference from RT System Load at Peak Hour* 1,500 1, MWh ,000 DA Lower -1,500-2,000-2,500 01JUN JUN JUN JUN JUN JUN JUN2017-3,000 08JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN2017 *Negative values indicate DA Cleared Physical Energy value below its RT counterpart. Forecast peak hour reflected. 28JUN JUN JUN

34 DA vs. RT Net Interchange June 2017 vs. June ,000 Hourly Average by Day, Last Year GR:Graph32 3,000 GR:Graph33 Hourly Average by Day, This Year 2,500 2,500 Net MWh 2,000 1,500 1,000 Net MWh 2,000 1,500 1, JUN16 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 01JUN17 02JUN17 03JUN17 04JUN17 05JUN17 06JUN17 07JUN17 08JUN17 09JUN17 10JUN17 11JUN17 12JUN17 13JUN17 14JUN17 15JUN17 16JUN17 17JUN17 18JUN17 19JUN17 20JUN17 21JUN17 22JUN17 23JUN17 24JUN17 25JUN17 26JUN17 27JUN17 28JUN17 29JUN17 30JUN17 Day-Ahead Real-Time Net Interchange is the sum of daily imports minus the sum of daily exports Positive values are net imports 34

35 $/MWh Variable Production Cost of Natural Gas: Monthly $160 GR:Var_Cost_Gas_Mly $120 $80 $40 $0 JUN2015 JUL2015 AUG2015 SEP2015 OCT2015 NOV2015 DEC2015 JAN2016 FEB2016 MAR2016 APR2016 MAY2016 JUN2016 JUL2016 AUG2016 SEP2016 OCT2016 NOV2016 DEC2016 JAN2017 FEB2017 MAR2017 APR2017 MAY2017 JUN2017 Var Cost Gas Underlying natural gas data furnished by: Note: Assumes proxy heat rate of 7,800,000 Btu/MWh for natural gas units. 35

36 $/MWh Variable Production Cost of Natural Gas: Daily $160 GR:Var_Cost_Gas_Dly $120 $80 $40 $0 01JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN2017 Var Cost Gas 12JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN JUN2017 Underlying natural gas data furnished by: Note: Assumes proxy heat rate of 7,800,000 Btu/MWh for natural gas units. 36

37 Hourly DA LMPs, June 1-30, 2017 $200 Hourly Day-Ahead LMPs GR:DA_Hrly $175 $150 $125 $100 Binding Western CT import constraint due to the planned outage of the 348 (Haddam-Millstone) line. Elevated loads 20,000-22,500 MW $/MWh $75 $50 $25 $0 $-25 $-50 $-75 $ Hub ME NH VT CT RI SEMA NEMA WCMA 37

38 Hourly RT LMPs, June 1-30, 2017 $200 $175 CT: Binding Western CT import constraint on the due to $150 the planned outage of the 348 (Haddam-Millstone) line. $125 System: Tight capacity with binding reserve constraints $100 over the evening pickup/peak Hourly Real-Time LMPs GR:RT_Hrly Tight capacity with binding reserve constraints over the peak $/MWh $75 $50 $25 $0 $-25 $-50 $-75 $-100 Binding reserve constraints in NEMA due to hot weather (mid-90s) and high loads (23,000+ MW) that ran above the forecast by ~1,000 MW Hub ME NH VT CT RI SEMA NEMA WCMA * No Minimum Generation Emergencies were declared in March. 38

39 System WEAF System Unit Availability Annual/Monthly Weighted Equivalent Availability Factor (WEAF) Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec YTD Data as of 7/6/17 39

40 BACK-UP DETAIL 40

41 LOAD RESPONSE 41

42 Capacity Supply Obligation (CSO) MW by Demand Resource Type for July 2017 Load Zone RTDR* RTEG** On Peak * Real Time Demand Response ** Real Time Emergency Generation NOTE: CSO values include T&D loss factor (8%). Seasonal Peak Total ME NH VT CT RI SEMA WCMA NEMA Total , ,

43 NEW GENERATION 43

44 New Generation Update Based on Queue as of 7/5/17 One new project, with a total rating of 15 MW, has applied for interconnection study since the last update The project consist of a wind facility with an expected in-service date of 2019 No projects withdrew from the queue and two projects went commercial, resulting in a net decrease in new generation projects of 40 MW In total, 76 generation projects are currently being tracked by the ISO, totaling approximately 12,300 MW 44

45 Megawatts (MW) Actual and Projected Annual Capacity Additions By Supply Fuel Type and Demand Resource Type 5,000 4,000 3,000 Demand Response - Passive Demand Reponse - Active Wind/Other Renewables 2,000 Oil 1,000 0 Natural Gas/Oil Natural Gas -1, Total MW % of Total 1 Demand Response - Passive , Demand Response - Active Wind & Other Renewables ,521 1,274 1, , Oil Natural Gas/Oil , , Natural Gas , , Totals 1,313 1,962 4,211 2,364 1, , Sum may not equal 100% due to rounding 2 The projects in this category are dual fuel, w ith either gas or oil as the primary fuel 2017 values include the 73 MW of generation that has gone commercial in 2017 DR reflects changes from the initial FCM Capacity Supply Obligations in

46 Megawatts (MW) Actual and Projected Annual Generator Capacity Additions By State 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1, Vermont Rhode Island New Hampshire Maine Massachusetts Connecticut values reflect the 73 MW of generation that has gone commercial in 2017 Total MW % of Total 1 Vermont Rhode Island , , New Hampshire Maine ,351 1, , Massachusetts , Connecticut 35 1, , Totals 1,020 2,199 4,268 1,899 1, , Sum may not equal 100% due to rounding 46

47 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 12 2, ,123 Natural Gas/Oil 10 2, , ,791 Oil Solar Wind 30 6, ,225 Battery Storage Total 76 12, , ,171 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 47

48 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 15 3, ,121 Peaker 26 2, ,716 Wind Turbine 30 6, ,225 Total 76 12, , ,171 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 48

49 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 12 2, , Natural Gas/Oil 10 2, , Oil Solar Wind 30 6, ,248 Battery Storage Total 76 12, , , ,248 Projects in the Natural Gas/Oil category may have either gas or oil as the primary fuel 49

50 FORWARD CAPACITY MARKET 50

51 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, , , , , ,138 0 * Real-time Emergency Generators (RTEG) CSO not capped at MW ** A resource s CSO may change for a variety of reasons outside ISO-NE administered trading windows. Reasons for CSO changes beyond bilaterals and reconfiguration auction may include terminations or recent declaration of commercial operation. Details of the changes that occurred due to non-annual event purposes are contained in the CCP Month Capacity Supply Obligation Changes report on the ISO New England website. *** Grand Total reflects both CSO Grand Total and the net total of the Change Column. The Grand Total for FCA 8 does not reflect a Supplemental Information filing in March of

52 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, , , * Real-time Emergency Generators (RTEG) CSO not capped at MW ** A resource s CSO may change for a variety of reasons outside ISO-NE administered trading windows. Reasons for CSO changes beyond bilaterals and reconfiguration auction may include terminations or recent declaration of commercial operation. Details of the changes that occurred due to non-annual event purposes are contained in the CCP Month Capacity Supply Obligation Changes report on the ISO New England website. *** Grand Total reflects both CSO Grand Total and the net total of the Change Column. The Grand Total for FCA 8 does not reflect a Supplemental Information filing in March of

53 Capacity Supply Obligation FCA 10 FCA 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 Chang e CSO Change CSO Change CSO Change CSO Change 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, , ***Grand Total 35, , Net ICR (NICR) 34,151 33, * Real-time Emergency Generators (RTEG) CSO not capped at MW ** A resource s CSO may change for a variety of reasons outside ISO-NE administered trading windows. Reasons for CSO changes beyond bilaterals and reconfiguration auction may include terminations or recent declaration of commercial operation. Details of the changes that occurred due to non-annual event purposes are contained in the CCP Month Capacity Supply Obligation Changes report on the ISO New England website. *** Grand Total reflects both CSO Grand Total and the net total of the Change Column. The Grand Total for FCA 8 does not reflect a Supplemental Information filing in March of

54 Capacity Supply Obligation FCA 11 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 3, Generator Non- Intermittent 30,494.8 Intermittent Generator Total 31, Import Total 1,235.4 ***Grand Total 35, Net ICR (NICR) 34,075 * Real-time Emergency Generators (RTEG) CSO not capped at MW ** A resource s CSO may change for a variety of reasons outside ISO-NE administered trading windows. Reasons for CSO changes beyond bilaterals and reconfiguration auction may include terminations or recent declaration of commercial operation. Details of the changes that occurred due to non-annual event purposes are contained in the CCP Month Capacity Supply Obligation Changes report on the ISO New England website. *** Grand Total reflects both CSO Grand Total and the net total of the Change Column. The Grand Total for FCA 8 does not reflect a Supplemental Information filing in March of

55 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 Active Passive Grand Total

56 RELIABILITY COSTS NET COMMITMENT PERIOD COMPENSATION (NCPC) OPERATING COSTS 56

57 What are Daily NCPC Payments? Payments made to resources whose 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 during 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 NCPC payments are intended to make a resource that follows the ISO s operating instructions no worse off financially than the best alternative generation schedule 57

58 Definitions 1 st Contingency NCPC Payments 2 nd Contingency NCPC Payments Voltage NCPC Payments Distribution NCPC Payments 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 Open Access Transmission Tariff 58

59 Charge Allocation Key Allocation Category System 1 st Contingency External DA 1 st Contingency Zonal 2 nd Contingency Market / OATT Market Market Market 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 System Low Voltage OATT (Low) Voltage Support NCPC is allocated to system Regional Network Load and Open Access Same-Time Information Service (OASIS) reservations Zonal High Voltage OATT 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, Economic Generator/DARD Posturing, Dispatch Lost Opportunity Cost (DLOC), and Rapid Response Pricing (RRP) Opportunity Cost NCPC (allocated to RTLO); and Min Generation Emergency NCPC (allocated to RTGO). 59

60 Year-Over-Year Total NCPC Dollars and Energy $80 NCPC Dollars GR:Graph23 1,300 NCPC Energy* GR:Graph23m $70 1,200 1,100 $60 $50 1, Millions $40 $30 $20 GWh $ $0 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC 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 (except for DLOC, RRP, or posturing NCPC), assessed during hours in which they are NCPC-eligible. Scheduled MW for external transactions receiving NCPC are also reflected. All NCPC components (1 st Contingency, 2 nd Contingency, Voltage, and RT Distribution) are reflected. 60

61 DA and RT NCPC Charges JUN-17 Total = $3.18 M GR:Graph01 $50 Last 13 Months GR:Graph02 34% $40 Millions $30 $20 $10 66% $0 JUN2016 JUL2016 AUG2016 SEP2016 OCT2016 NOV2016 DEC2016 JAN2017 FEB2017 MAR2017 APR2017 MAY2017 JUN2017 Day-Ahead Real-Time Day-Ahead Real-Time 61

62 NCPC Charges by Type GR:Graph03 JUN-17 Total = $3.18 M GR:Graph04 $50 Last 13 Months $40 87% 3% Millions $30 $20 10% $10 $0 JUN16 JUL16 AUG16 SEP16 OCT16 NOV16 DEC16 JAN17 FEB17 MAR17 APR17 MAY17 JUN17 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 62

63 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 JUN2017 1st C 2nd C Voltage Distribution 27JUN JUN JUN JUN

64 NCPC Charges by Allocation 0.8% JUN-17 Total = $3.18 M GR:xpie_ncpc_chgs_alloc_cat 66% Last 13 Months GR:xchart_ncpc_chgs_alloc_cat $40.0 $ % Millions $24.0 $ % $ % 1.2% 0.0% 1.5% 2.2% 9.7% 1.4% $0.0 JUN16 JUL16 AUG16 SEP16 OCT16 NOV16 DEC16 JAN17 FEB17 MAR17 APR17 MAY17 JUN17 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 Note: System Other includes, as applicable: Resource Economic Posturing, GPA, Min Gen Emergency, Dispatch Lost Opportunity Cost (DLOC), and Rapid Response Pricing (RRP) Opportunity Cost credits. 64

65 RT First Contingency Charges by Deviation Type GR:pie_firstc_rt_bydev JUN-17 Total = $1.42 M 19.9% 11.9% GR:chart_firstc_rt_bydev_13mo $3 Last 13 Months 8.2% $2 Millions $1 59.9% $0 JUN16 JUL16 AUG16 SEP16 OCT16 NOV16 DEC16 JAN17 FEB17 MAR17 APR17 MAY17 JUN17 Gen Inc Import Load Gen Inc Import Load Gen Generator deviations Inc Increment Offer deviations Imp Import deviations Load Load obligation deviations 65

66 LSCPR Charges by Reliability Region $13.0 GR:lscpr_charges_byzone_13mo $12.0 $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 JUN16 JUL16 AUG16 SEP16 OCT16 NOV16 DEC16 JAN17 FEB17 MAR17 APR17 MAY17 JUN17 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 66

67 NCPC Charges for Voltage Support and High Voltage Control $1,000.0 GR:var_charges_stack_13mo $900.0 $800.0 $700.0 $600.0 Thousand $500.0 $400.0 $300.0 $200.0 $100.0 $0.0 JUN16 JUL16 AUG16 SEP16 OCT16 NOV16 DEC16 JAN17 FEB17 MAR17 APR17 MAY17 JUN17 DA HV NCPC DA LV NCPC RT HV NCPC RT LV NCPC 67

68 NCPC Charges by Type $175 Value of Charges GR:NCPC_Stack $150 $125 $118.1 Millions $100 $75 $73.1 $50 $25 $28.9 $0 $4.4 $7.1 $5.5 $3.1 $5.6 $ JAN2017 FEB2017 MAR2017 APR2017 MAY2017 JUN2017 JUL2017 AUG2017 SEP2017 OCT2017 NOV2017 DEC2017 1st C 2nd C Distr Voltg 68

69 NCPC Charges as Percent of Energy Market 10.0% NCPC By Type as Percent of Energy Market GR:NCPC_pct_Stack 8.0% 6.0% Percent 4.0% 2.0% 2.0% 1.8% 1.4% 1.0% 2.3% 1.4% 1.1% 2.0% 1.1% 0.0% JAN2017 FEB2017 MAR2017 APR2017 MAY2017 JUN2017 JUL2017 AUG2017 SEP2017 OCT2017 NOV2017 DEC2017 1st C 2nd C Distr Voltg 69

70 First Contingency NCPC Charges $140 Value of Charges GR:Graph19 4.0% % of Energy Market Value GR:Graph20 $120 $ % Millions $80 $60 $40 $20 $0 $70.0 $40.5 $ JAN2017 $3.5 $3.0 $3.8 $2.7 $4.5 $2.8 FEB2017 MAR2017 APR2017 MAY2017 JUN2017 JUL2017 AUG2017 SEP2017 OCT2017 NOV2017 DEC % 1.0% 0.0% 1.2% 1.0% 1.0% % 1.0% 0.9% 1.0% 1.6% 0.9% JAN2017 FEB2017 MAR2017 APR2017 MAY2017 JUN2017 JUL2017 AUG2017 SEP2017 OCT2017 NOV2017 DEC2017 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 Second Contingency NCPC Charges $50 Value of Charges GR:Graph21 6.0% % of Energy Market Value GR:Graph22 $42.7 $40 $30 $ % Millions $20 3.0% $10 $ JAN2017 $6.3 $0.9 $3.3 $0.8 FEB2017 MAR2017 $0.0 $1.0 $0.3 MAY2017 JUN2017 APR2017 JUL2017 AUG2017 SEP2017 OCT2017 NOV2017 DEC % 0.0% 0.7% 0.8% 0.3% JAN2017 FEB % 1.1% 0.2% MAR2017 APR2017 MAY2017 JUN % 0.1% JUL2017 AUG2017 SEP2017 OCT2017 NOV2017 DEC2017 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 71

72 Voltage and Distribution NCPC Charges $40 Value of Charges GR:Graph17 4.0% % of Energy Market Value GR:Graph18 $30 3.0% Millions $20 2.0% $10 $0 $5.4 $1.6 $ $0.0 $0.8 $1.0 $0.4 $0.1 $0.1 FEB2017 MAR2017 JAN2017 APR2017 MAY2017 JUN2017 JUL2017 AUG2017 SEP2017 OCT2017 NOV2017 DEC % 0.0% 0.1% 0.0% 0.1% % 0.3% 0.2% JAN2017 FEB2017 MAR2017 APR2017 MAY % 0.0% 0.0% JUN2017 JUL2017 AUG2017 SEP2017 OCT2017 NOV2017 DEC2017 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 72

73 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 73

74 DA vs. RT LMPs ($/MWh) Arithmetic Average 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% Year 2016 NEMA CT ME NH VT RI SEMA WCMA Hub Day-Ahead $30.66 $29.77 $29.07 $29.64 $29.66 $29.66 $29.88 $29.85 $29.78 Real-Time $29.74 $29.00 $27.81 $28.60 $28.49 $28.87 $29.01 $28.98 $28.94 RT Delta % -3.0% -2.6% -4.3% -3.5% -3.9% -2.7% -2.9% -2.9% -2.8% 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% June-17 NEMA CT ME NH VT RI SEMA WCMA Hub Day-Ahead $25.47 $26.02 $24.79 $25.08 $25.39 $25.32 $25.34 $25.59 $25.48 Real-Time $24.78 $24.83 $22.89 $23.44 $23.59 $23.81 $23.85 $24.03 $23.93 RT Delta % -2.7% -4.6% -7.7% -6.5% -7.1% -6.0% -5.9% -6.1% -6.1% Annual Diff. NEMA CT ME NH VT RI SEMA WCMA Hub Yr over Yr DA 10.6% 13.4% 11.3% 10.8% 11.2% 12.9% 12.9% 12.5% 12.7% Yr over Yr RT 14.1% 14.9% 9.8% 10.6% 11.2% 12.9% 12.9% 12.5% 12.7% 74

75 Monthly Average Fuel Price and RT Hub LMP Indexes GR:Graph March 2003= MAR2003 JUN2003 SEP2003 DEC2003 MAR2004 JUN2004 SEP2004 DEC2004 MAR2005 JUN2005 SEP2005 DEC2005 MAR2006 Natural Gas JUN2006 SEP2006 DEC2006 MAR2007 JUN2007 SEP2007 DEC2007 MAR2008 JUN2008 SEP2008 DEC2008 MAR2009 Hub RT LMP JUN2009 SEP2009 DEC2009 MAR2010 JUN2010 SEP2010 DEC2010 MAR2011 JUN2011 SEP2011 DEC2011 MAR2012 JUN2012 SEP2012 DEC2012 MAR2013 JUN2013 SEP2013 DEC2013 MAR2014 JUN2014 SEP2014 DEC2014 MAR2015 JUN2015 SEP2015 DEC2015 MAR2016 JUN2016 SEP2016 DEC2016 MAR2017 JUN2017 SEP2017 Underlying natural gas data furnished by: 75

76 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 $0.00 MAR2003 JUN2003 SEP2003 DEC2003 MAR2004 JUN2004 SEP2004 DEC2004 MAR2005 JUN2005 SEP2005 DEC2005 SEP2006 DEC2006 MAR2007 JUN2007 SEP2007 DEC2007 MAR2008 JUN2008 SEP2008 DEC2008 MAR2009 JUN2009 SEP2009 DEC2009 MAR2010 JUN2010 MAR2006 JUN2006 Natural Gas SEP2010 DEC2010 MAR2011 JUN2011 SEP2011 JUN2012 SEP2012 DEC2012 MAR2013 JUN2013 SEP2013 DEC2013 MAR2014 JUN2014 SEP2014 DEC2014 MAR2015 JUN2015 SEP2015 DEC2015 MAR2016 JUN2016 SEP2016 DEC2011 MAR2012 Hub RT LMP DEC2016 MAR2017 JUN2017 SEP2017 $0.00 Underlying natural gas data furnished by: 76

77 New England, NY, and PJM Hourly Average Real Time Prices by Month $60 Monthly, Last 13 Months GR:three_pools_prices_mly $70 Daily: This Month GR:three_pools_prices_dly Electricity Prices ($/MWh) $50 $40 $30 Electricity Prices ($/MWh) $60 $50 $40 $30 $20 $20 JUN2016 JUL2016 AUG2016 SEP2016 OCT2016 NOV2016 DEC2016 ISO-NE NY-ISO PJM JAN2017 FEB2017 MAR2017 APR2017 MAY2017 JUN2017 $10 01JUN17 02JUN17 03JUN17 04JUN17 07JUN17 08JUN17 09JUN17 10JUN17 11JUN17 12JUN17 13JUN17 05JUN17 06JUN17 14JUN17 15JUN17 16JUN17 17JUN17 18JUN17 19JUN17 20JUN17 ISO-NE NY-ISO PJM 21JUN17 22JUN17 23JUN17 24JUN17 25JUN17 26JUN17 27JUN17 28JUN17 29JUN17 30JUN17 *Note: Hourly average prices are shown. *Note: Hourly average prices are shown. 77

78 New England, NY, and PJM Average Peak Hour Real Time Prices $110 Monthly, Last 13 Months GR:three_pools_prices_fpk_mly $200 Daily: This Month GR:three_pools_prices_fpk_dly Electricity Prices ($/MWh) $100 $90 $80 $70 $60 $50 $40 $30 JUN2016 JUL2016 AUG2016 SEP2016 OCT2016 NOV2016 DEC2016 ISO-NE NY-ISO PJM JAN2017 FEB2017 MAR2017 APR2017 MAY2017 JUN2017 Electricity Prices ($/MWh) $180 $160 $140 $120 $100 $80 $60 $40 $20 $0 01JUN17 02JUN17 03JUN17 04JUN17 07JUN17 08JUN17 09JUN17 10JUN17 11JUN17 12JUN17 13JUN17 14JUN17 15JUN17 16JUN17 17JUN17 18JUN17 19JUN17 20JUN17 21JUN17 22JUN17 23JUN17 24JUN17 25JUN17 26JUN17 27JUN17 05JUN17 06JUN17 ISO-NE NY-ISO PJM 28JUN17 29JUN17 30JUN17 *Forecasted New England daily peak hours reflected 78

79 Reserve Market Results June 2017 Maximum potential Forward Reserve Market payments of $5M were reduced by credit reductions of $155K, failure-to-reserve penalties of $247K and failure-to-activate penalties of $8K, resulting in a net payout of $4.6M or 92% of maximum Rest of System: $1.98M/2.28M (87)% Southwest Connecticut: $0.15M/0.17M (85)% Connecticut: $1.04M/1.05M (99)% NEMA: $1.4M/1.5M (95)% $3.5M total Real-Time credits were reduced by $512K in Forward Reserve Energy Obligation Charges for a net of $3.0M in Real-Time Reserve payments Rest of System: 283 hours, $2.2M Southwest Connecticut: 283 hours, $207K Connecticut: 283 hours, $251K NEMA: 284 hours, $391K * Failure to reserve results in both credit reductions and penalties in the Locational Forward Reserve Market. 79

80 LFRM Charges to Load by Load Zone ($) $7.0 LFRM Charges by Zone, Last 13 Months GR:Graph39 $6.0 $5.0 Millions $4.0 $3.0 $2.0 $1.0 $0.0 JUN16 JUL16 AUG16 SEP16 OCT16 NOV16 DEC16 JAN17 FEB17 MAR17 APR17 MAY17 JUN17 CT ME NEMA NH RI SEMA VT WCMA 80

81 Zonal Increment Offers and Cleared Amounts MWh 200, , , , , , , , , , ,000 90,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10, June Monthly Totals by Zone GR:Graph Hub ME NH VT CT RI SEMA WCMA NEMA Cleared Offered 81

82 Zonal Decrement Bids and Cleared Amounts 100,000 June Monthly Totals by Zone GR:Graph29 90,000 80,000 70,000 60,000 MWh 50,000 40,000 30,000 20,000 10, Hub ME NH VT CT RI SEMA WCMA NEMA Cleared Bid 82

83 Total Increment Offers and Decrement Bids 1,100,000 Zonal Level, Last 13 Months GR:Graph30 1,000, , , ,000 MWh 600, , , , , ,000 0 JUN2016 JUL2016 AUG2016 SEP2016 OCT2016 NOV2016 DEC2016 JAN2017 FEB2017 MAR2017 APR2017 MAY2017 JUN2017 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 83

84 Dispatchable vs. Non-Dispatchable Generation 14,000 Total Monthly Energy; Dispatchable % Shown GR:Graph31 12, % 48.8% GWh 10,000 8, % 47.5% 45.8% 47.5% 48.4% 46.0% 47.1% 45.5% 59.4% 46.0% 46.1% 6,000 4,000 2,000 0 JUN2016 JUL2016 AUG2016 SEP2016 OCT2016 NOV2016 DEC2016 JAN2017 FEB2017 MAR2017 APR2017 MAY2017 JUN2017 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). 84

85 Rolling Average Peak Energy Rent (PER) $0.50 GR:rolling_avg_per_big $0.40 $/KW-Month $0.30 $0.20 $0.10 $0.00 JUN16 JUL16 AUG16 SEP16 OCT16 NOV16 DEC16 JAN17 FEB17 MAR17 APR17 MAY17 JUN17 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. month 85

86 PER Adjustments $5.0 GR:fcm_per_adj_byzone_big $4.0 Millions ($) $3.0 $2.0 $1.0 $0.0 JUN16 JUL16 AUG16 SEP16 OCT16 NOV16 DEC16 JAN17 FEB17 MAR17 APR17 MAY17 JUN17 CT ME NEMA ROP month PER Adjustments are reductions to Forward Capacity Market monthly payments resulting from the rolling average PER. 86

87 REGIONAL SYSTEM PLAN (RSP) 87

88 Planning Advisory Committee (PAC) RSP17 work is proceeding and the draft PAC version was posted on July 7 Comments must be submitted to PACMatters@iso-ne.com on the form posted at Discussions focusing on the comments received are scheduled for the August 3 PAC meeting The RSP public meeting is scheduled for Thursday, September 14, at the Seaport World Trade Center in Boston, MA from 11:00am to 4:00pm The meeting will feature a keynote speaker, discussion of RSP17, and panel on planning for the future hybrid grid: successfully integrating increasing levels of renewable energy, energy storage, and other distributed energy resources Registration for the public meeting will be available through the calendar link on the ISO homepage at 88

89 Planning Advisory Committee, cont. July 6 PAC Meeting is canceled due to lack of agenda items August 3 PAC Meeting Agenda* RSP17 Page Turn 2016 Economic Study Phase 2 - Regulation, Ramping and Reserves Status Update Maine Resource Integration Study * Agenda items are subject to change. Visit for the latest PAC agendas. 89

90 Load, Energy Efficiency, and Photovoltaic Forecast Load Forecast Next Load Forecast Committee meeting is July 21 Enhancing information available to external stakeholders via our website Energy-Efficiency (EE) Forecast Efforts to benchmarking the EE forecasts developed to date to actual reductions have begun. Results to be shared with the Energy-Efficiency Forecast Working Group later this year Data collection for next year s forecast will begin in August Photovoltaic (PV) Forecast Efforts to model the hourly impact of Behind-the Meter PV for the development of Installed Capacity Requirements & Related Values is being discussed with the PSPC. This new methodology is likely to be used for FCA #12. 90