NEPOOL Participants Committee Report

Transcription

1 J A N U A R Y 1 2, NEPOOL Participants Committee Report January 2018 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 12 Market Operations Page 25 Back-Up Detail Page 42 Load Response Page 43 New Generation Page 45 Forward Capacity Market Page 52 Reliability Costs - Net Commitment Period Compensation (NCPC) Operating Costs Page 58 Regional System Plan (RSP) Page 89 Operable Capacity Analysis Winter 2017 Page 119 Operable Capacity Analysis Appendix Page 126 2

3 Highlights Day-Ahead (DA), Real-Time (RT) Prices and Transactions Energy market value was $856M, up $507M from November 2017 and up $239M from December 2016 December natural gas prices over the period were 185% higher than November average values Average RT Hub Locational Marginal Prices ($79.89/MWh) over the period were 140% higher than November averages Average December DA Hub LMP: $71.31/MWh Average December 2017 natural gas prices and RT Hub LMPs were up 44% and up 48%, respectively, from December 2016 averages Average DA cleared physical energy during the peak hours as percent of forecasted load was 99.2% during December, up from 98.5% during November* 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) December NCPC payments totaled $7.1M over the period, down $19K from November 2017 and up $447K from December 2016 First Contingency* payments totaled $5.5M, up $2.6M from November $5.4M paid to internal resources, up $2.7M from November» $1.8M charged to DALO, $1.9M to RT Deviations, $1.6M to RTLO $107K paid to resources at external locations, down $84K from November» $0K charged to DALO at external locations, $107K to RT Deviations Second Contingency payments totaled $549K, down $3.7M from November $447K charged to Maine; $101K (combined) charged to SEMA, RI, and NH Voltage payments totaled $1.1M, up $1.0M from November NCPC payments over the period as percent of Energy Market value were 0.8% * NCPC types reflected in the First Contingency Amount: Dispatch Lost Opportunity Cost (DLOC) - $493K; Rapid Response Pricing (RRP) Opportunity Cost - $526K; Posturing - $609K; Generator Performance Auditing (GPA) - $3K; 4

5 Highlights, cont Economic Study - NEPOOL Scenario Analysis Phase II - analysis of regulation, ramping, and reserves was presented to the Planning Advisory Committee on December 20, 2017 Certification of transmission topology for the Capacity Commitment Period (CCP) is nearly complete, and will be presented at the January 17 Reliability Committee meeting The twelfth Forward Capacity Auction (FCA #12) for the May 2021 June 2022 CCP is scheduled to begin on Monday, February 5 The Scobie - Tewksbury 345 kv line was placed in service in December 2017 and has increased overall north/south transfer capability 5

6 Forward Capacity Market (FCM) Highlights CCP #8 ( ) Monthly activities continue New, non-commercial resources are attempting to cover in the monthly activities CCP #9 ( ) Third bilateral transaction window closed on December 8, 2017 and results to be posted by January 12, 2018 Third reconfiguration auction will be March 1-5, 2018, and results to be posted by March 19, 2018 ICR & related values for ARA3 were filed with FERC on December 1, 2017 and accepted by FERC on January 4, 2018 CCP #10 ( ) Second bilateral transaction window will be May 2-4, 2018 Second reconfiguration auction will be August 1-3, 2018 ICR & related values for ARA3 were filed with FERC on December 1, 2017 and accepted by FERC on January 4, 2018 CCP Capacity Commitment Period ARA Annual Reconfiguration Auction ICR Installed Capacity Requirement 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 ICR & related values for ARA3 were filed with FERC on December 1, 2017 and accepted by FERC on January 4, 2018 CCP #12 ( ) FERC Informational Filing was made on November 7, 2017 and FERC has yet to provide an order ICR & related values were filed with FERC on November 7, 2017 and accepted by FERC on December 18, 2017 Auction will commence on February 5, 2018 The Renewable Technology Resource election cap is approximately 514 MW 7

8 FCM Highlights, cont. CCP #13 ( ) Topology certification nearly complete and results to be presented to the RC on January 17 Preliminary capacity zones were discussed at the PAC in November Upcoming Training Existing Capacity Resource Qualification: January 11 Existing Capacity Resource Delist Bids: January 25 Show of Interest for Prospective New Capacity Resources: February 27 New Capacity Qualification Package Submittal: May 1 8

9 Highlights, cont. The lowest 50/50 and 90/10 Winter Operable Capacity Margins are projected for week beginning January 13,

10 2017/18 Winter Reliability Program As of December 1, 2017 (unchanged since last month) Oil Program As of December 1 st, participation from 86 units for a total of million barrels of oil million barrels of the total inventory on December 1 are eligible for compensation per the winter program rules Total oil program cost exposure is expected to be $29.62M (@$10.33/barrel) LNG Program As of December 1 st, no participation DR Program As of December 1 st, participation from 3 assets providing 7.5 MW of interruption capability Total DR program cost exposure is anticipated to be $23.2K 10

11 2017/18 Winter Program Usage Winter Program Oil Inventory Changes: Dec 2017: 548,410 BBLs Winter Program DR Events: Dec 2017: none Please note that the winter program oil inventory will differ from the actual oil burned during the cold weather for the following reasons Not all units that burn oil participate in the Winter Reliability Program Winter program oil participation is capped at stations, so a station that has a winter program participation of 100K barrels, but has burned 150K barrels is still counted at the original number Actual oil burn numbers reflect the total oil burn and include ongoing replenishments at both dual fuel and oil only stations 11

12 SYSTEM OPERATIONS 12

13 System Operations Weather Patterns Boston Temperature: Below Normal (6.1 F) Max: 59 F, Min: 2 F Precipitation: 2.47 Below Normal Normal: 3.73 Snow: 7.16 Hartford Temperature: Below Normal (5.9 F) Max: 59 F, Min: -3 F Precipitation: Below Normal Normal: 3.60 Snow: 8.94 Peak Load: 20,531 MW Dec 28, :00 (ending) MLCC2: None OP-4 : None NPCC Simultaneous Activation of Reserve Events: Date Area MW Dec 7, 2017 NYISO

14 System Operations, cont. Minimum Generation Warnings & Events: None 14

15 2017 System Operations - Load Forecast Accuracy Dashboard Indicator Month J F M A M J J A S O N D 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% 15

16 2017 System Operations - Load Forecast Accuracy cont. Dashboard Indicator Month J F M A M J J A S O N D 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% 16

17 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

18 2017 System Operations - Load Forecast Accuracy cont. 18

19 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 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. 19

20 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 F designates forecasted values, which are updated in April/May of the following year; represents net forecast (i.e., the gross forecast net of passive demand response and behind-the-meter solar demand) 20

21 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. 21

22 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. 22

23 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. 23

24 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. 24

25 MARKET OPERATIONS 25

26 Daily Average DA and RT ISO-NE Hub Prices and Input Fuel Prices: December 1-31, 2017 $ GR:Hubwgas $ Binding reserve constraints, loads above forecast, and lost DA capacity $30.00 $24.00 Electricity Prices ($/MWh) $ $ $50.00 $18.00 $12.00 $6.00 Fuel Price ($/MMBtu) $0.00 $ /01/17 12/03/17 12/05/17 12/07/17 12/09/17 12/11/17 12/13/17 12/15/17 12/17/17 12/19/17 12/21/17 12/23/17 12/25/17 12/27/17 12/29/17 12/31/17 Underlying natural gas data furnished by: RT LMP DA LMP Natural Gas Average price difference over this period (DA-RT): $-8.57 Average price difference over this period ABS(DA-RT): $16.82 Average percentage difference over this period ABS(DA-RT)/RT Average LMP: 21% Gas price is average of Massachusetts delivery points 26

27 DA LMPs Average by Zone & Hub, December 2017 $100 GR:DA_Bar ( 2.4%) ( 0.4%) ( 0.6%) ( 2.4%) ( 0.2%) 0.4% 0.0% 0.4% $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 27

28 RT LMPs Average by Zone & Hub, December 2017 $100 GR:RT_Bar ( 7.0%) ( 2.9%) ( 2.5%) ( 1.9%) ( 0.2%) 0.7% ( 0.1%) 0.9% $80 $60 $/MWh $40 $20 $0 $-20 Hub ME NH VT CT RI SEMA WCMA NEMA LMP Congestion Marginal Losses 28

29 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 29

30 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 OCT2017 NOV2017 DEC OCT2017 NOV2017 DEC2017 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 30

31 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 OCT2017 NOV2017 DEC OCT2017 NOV2017 DEC2017 Gen Imports Load Exports DA Fcst Load 31

32 DAM Volumes as % of RT Actual Load (Forecasted Peak Hour) 130% 130% 120% 120% % of RT Actual Load 110% 100% 90% 80% % of RT Actual Load 110% 100% 90% 80% 70% 60% Dec-16 Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 70% 60% 1-Dec 2-Dec 3-Dec 4-Dec 5-Dec 6-Dec 7-Dec 8-Dec 9-Dec 10-Dec 11-Dec 12-Dec 13-Dec 14-Dec 15-Dec 16-Dec 17-Dec 18-Dec 19-Dec 20-Dec 21-Dec 22-Dec 23-Dec 24-Dec 25-Dec 26-Dec 27-Dec 28-Dec 29-Dec 30-Dec 31-Dec DA Bid Fixed DALO 100% DA Bid Priced DA Phys Clrd Energy 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). 32

33 DA vs. RT Load Obligation: December, This Year vs. Last Year DA % of RT 99.6% 99.4% 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% DEC2016 JAN2017 FEB2017 Monthly, Last 13 Months GR:Graph26 MAR2017 APR2017 MAY2017 JUN2017 JUL2017 AUG2017 SEP2017 OCT2017 NOV2017 DEC2017 DA % of RT 101% 100% 99% 98% 97% 96% 95% 94% 93% 92% 91% 12/ 1 12/ 2 12/ 3 12/ 4 12/ 5 12/ 6 Daily, This Year vs. Last Year 12/ 7 12/ 8 12/ 9 GR:Graph27 12/12 12/13 12/14 12/15 12/10 12/11 Last_Year 12/19 12/20 12/21 12/22 12/16 12/17 12/18 This_Year 12/23 12/24 12/25 12/26 12/27 12/28 12/29 12/30 12/31 *Hourly average values 33

34 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 120% Daily: This Month 104% 116% Percentage of Peak Forecast Load 102% 100% 98.0% 96.0% 94.0% DEC2016 JAN2017 FEB2017 MAR2017 APR2017 MAY2017 DA Cleared Physical Energy 100% line JUN2017 JUL2017 DALO AUG2017 SEP2017 OCT2017 NOV2017 DEC2017 *There were four supplemental commitments required for capacity during the Reserve Adequacy Assessment (RAA) process during December. Percentage of Peak Forecast Load 112% 108% 104% 100% 96.0% 92.0% 88.0% DA Cleared Physical Energy 100% line 01DEC17 02DEC17 03DEC17 04DEC17 05DEC17 06DEC17 07DEC17 08DEC17 09DEC17 10DEC17 11DEC17 12DEC17 13DEC17 14DEC17 15DEC17 16DEC17 17DEC17 18DEC17 19DEC17 DALO 20DEC17 21DEC17 22DEC17 23DEC17 24DEC17 25DEC17 26DEC17 27DEC17 28DEC17 29DEC17 30DEC17 31DEC17 34

35 DA Cleared Physical Energy Difference from RT System Load at Peak Hour* 1,500 GR:dapce_delta_fpk_dly_bar 1, DA Higher MWh ,000 DA Lower -1,500-2,000-2,500 01DEC DEC DEC DEC DEC DEC DEC2017-3,000 08DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC2017 *Negative values indicate DA Cleared Physical Energy value below its RT counterpart. Forecast peak hour reflected. 28DEC DEC DEC DEC

36 DA vs. RT Net Interchange December 2017 vs. December ,000 Hourly Average by Day, Last Year GR:Graph32 4,000 Hourly Average by Day, This Year GR:Graph33 3,500 3,500 3,000 3,000 Net MWh 2,500 2,000 1,500 Net MWh 2,500 2,000 1,500 1,000 1, DEC16 02DEC16 03DEC16 04DEC16 05DEC16 06DEC16 07DEC16 08DEC16 09DEC16 10DEC16 11DEC16 12DEC16 13DEC16 14DEC16 15DEC16 16DEC16 17DEC16 18DEC16 19DEC16 20DEC16 21DEC16 22DEC16 23DEC16 24DEC16 25DEC16 26DEC16 27DEC16 28DEC16 29DEC16 30DEC16 31DEC16 01DEC17 02DEC17 03DEC17 04DEC17 05DEC17 06DEC17 07DEC17 08DEC17 09DEC17 10DEC17 11DEC17 12DEC17 13DEC17 14DEC17 15DEC17 16DEC17 17DEC17 18DEC17 19DEC17 20DEC17 21DEC17 22DEC17 23DEC17 24DEC17 25DEC17 26DEC17 27DEC17 28DEC17 29DEC17 30DEC17 31DEC17 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 36

37 $/MWh Variable Production Cost of Natural Gas: Monthly $160 GR:Var_Cost_Gas_Mly $120 $80 $40 $0 DEC2015 JAN2016 FEB2016 MAR2016 APR2016 MAY2016 JUN2016 JUL2016 AUG2016 SEP2016 OCT2016 NOV2016 DEC2016 JAN2017 FEB2017 MAR2017 APR2017 MAY2017 JUN2017 JUL2017 AUG2017 SEP2017 OCT2017 NOV2017 DEC2017 Var Cost Gas Underlying natural gas data furnished by: Note: Assumes proxy heat rate of 7,800,000 Btu/MWh for natural gas units. 37

38 $/MWh Variable Production Cost of Natural Gas: Daily $160 GR:Var_Cost_Gas_Dly $120 $80 $40 $0 01DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC2017 Var Cost Gas 12DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC2017 Underlying natural gas data furnished by: Note: Assumes proxy heat rate of 7,800,000 Btu/MWh for natural gas units. 38

39 Hourly DA LMPs, December 1-31, 2017 $350 Hourly Day-Ahead LMPs GR:DA_Hrly $300 Colder temps, higher loads, and elevated natural gas prices $250 $200 $/MWh $150 $100 $50 $0 $-50 $ * * Hub ME NH VT CT RI SEMA NEMA WCMA 39

40 Hourly RT LMPs, December 1-31, 2017 $/MWh $350 $300 $250 Binding New Hampshire- Maine constraint due to the $200 outage of the 337 (Sandy Pond-Tewksbury) line $150 $100 Hourly Real-Time LMPs Binding reserve constraints with loads above forecast over the evening peak GR:RT_Hrly Colder temps, higher loads, and elevated natural gas prices $50 $0 $-50 $-100 Binding constraint on the Seabrook South Interface due to the planned outage of the 326 (Scobie-Sandy Pond) line * * Hub ME NH VT CT RI SEMA NEMA WCMA * No Minimum Generation Emergencies were declared in December. 40

41 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 1/8/18 41

42 BACK-UP DETAIL 42

43 LOAD RESPONSE 43

44 Capacity Supply Obligation (CSO) MW by Demand Resource Type for January 2018 Load Zone RTDR* RTEG** On Peak * Real Time Demand Response ** Real Time Emergency Generation 1 Negative CSO resulting from reconfiguration auction activity Seasonal Peak Total ME NH VT CT RI SEMA WCMA NEMA Total , ,726.1 NOTE: CSO values include T&D loss factor (8%) 44

45 NEW GENERATION 45

46 New Generation Update Based on Queue as of 12/29/17 Five new projects totaling over 1,300 MW, have applied for interconnection study since the last update 2 Wind (1,220 MW Total) in MA COD 2021/23 1 Battery (75 MW) in MA COD Solar PV (14 MW Total) in MA COD 2018 No withdrawals from the queue and one commercial, resulting in a net increase in new generation projects of 1,280 MW In total, 93 generation projects are currently being tracked by the ISO, totaling approximately 15,000 MW 46

47 Actual and Projected Annual Capacity Additions By Supply Fuel Type and Demand Resource Type Megawatts (MW) 5,000 4,000 3,000 2,000 1,000 0 Demand Response - Passive Demand Response - Active Wind & Other Renewables Oil Natural Gas/Oil2 Natural Gas -1, Demand Response - Passive , Demand Response - Active Wind & Other Renewables ,791 1,141 2, , , Oil Natural Gas/Oil , , Natural Gas , , Totals 1,144 1,192 3,723 2,231 3, , , 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 Total MW % of Total values include the 159 MW of generation that has gone commercial in 2017 DR reflects changes from the initial FCM Capacity Supply Obligations in

48 Actual and Projected Annual Generator Capacity Additions By State values reflect the 159 MW of generation that has gone commercial in 2017 Total MW % of Total 1 Vermont Rhode Island , , New Hampshire Maine ,460 1, , Massachusetts , , , Connecticut 33 1, , Totals 851 1,429 3,780 1,766 3, , , Sum may not equal 100% due to rounding 48

49 New Generation Projection By Fuel Type Total Green Yellow Fuel Type No. of Projects Capacity (MW) No. of Projects Capacity (MW) No. of Projects Capacity (MW) Biomass/wood waste Bituminous Hydro Landfill Gas Natural gas 9 2, ,348 Natural gas/oil 8 2, , ,492 Nuclear uprates Oil Solar 31 1, ,156 Wind 34 8, ,504 Battery storage Total 93 15, , ,188 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 49

50 New Generation Projection By Operating Type Operating Type No. of Projects Total Capacity (MW) Green No. of Projects Capacity (MW) No. of Projects Yellow Capacity (MW) Baseload Intermediate 11 3, , ,285 Peaker 45 2, ,294 Wind Turbine 34 8, ,504 Total 93 15, , ,188 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 50

51 New Generation Projection By Operating Type and Fuel Type Total Baseload Intermediate Peaker Wind Turbine Fuel Type No. of Projects Capacity (MW) No. of Projects Capacity (MW) No. of Projects Capacity (MW) No. of Projects Capacity (MW) No. of Projects Capacity (MW) Biomass/wood waste Bituminous Hydro Landfill Gas Natural gas 9 2, , Natural gas/oil 8 2, , Nuclear uprates Oil Solar 31 1, , Wind 34 8, ,504 Battery storage Total 93 15, , , ,504 Projects in the Natural Gas/Oil category may have either gas or oil as the primary fuel 51

52 FORWARD CAPACITY MARKET 52

53 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

54 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 1,449 1, , , ,449 0 ***Grand Total 34, , , , , Net ICR (NICR) 34,189 33, , , ,421 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. 54

55 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, , , ***Grand Total 35, , , Net ICR (NICR) 34,151 33, ,755 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. 55

56 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. 56

57 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

58 RELIABILITY COSTS NET COMMITMENT PERIOD COMPENSATION (NCPC) OPERATING COSTS 58

59 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 59

60 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 60

61 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). 61

62 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. 62

63 DA and RT NCPC Charges DEC-17 Total = $7.06 M GR:Graph01 $20 Last 13 Months GR:Graph02 $16 47% Millions $12 $8 53% $4 $0 DEC2016 JAN2017 FEB2017 MAR2017 APR2017 MAY2017 JUN2017 JUL2017 AUG2017 SEP2017 OCT2017 NOV2017 DEC2017 Day-Ahead Real-Time Day-Ahead Real-Time 63

64 NCPC Charges by Type GR:Graph03 DEC-17 Total = $7.06 M GR:Graph04 $20 Last 13 Months $16 77% Millions $12 $8 15% $4 8% 0% $0 DEC16 JAN17 FEB17 MAR17 APR17 MAY17 JUN17 JUL17 AUG17 SEP17 OCT17 NOV17 DEC17 1st C Distrib 2nd C Voltage 1st C Voltage 2nd C Distrib 1 st C First Contingency 2 nd C Second Contingency Distrib Distribution Voltage Voltage 64

65 Daily NCPC Charges by Type $600 GR:ncpc_bytype_stack_dly $500 $400 Thousand $300 $200 $100 $0 01DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC2017 1st C 2nd C Voltage Distribution 28DEC DEC DEC DEC

66 NCPC Charges by Allocation 0.8% DEC-17 Total = $7.06 M GR:xpie_ncpc_chgs_alloc_cat 54% GR:xchart_ncpc_chgs_alloc_cat $20.0 Last 13 Months $16.0 Millions $12.0 $ % 7.8% 0.9% 14% 0.0% 0.8% 23% 0.8% $4.0 $0.0 DEC16 JAN17 FEB17 MAR17 APR17 MAY17 JUN17 JUL17 AUG17 SEP17 OCT17 NOV17 DEC17 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. 66

67 RT First Contingency Charges by Deviation Type DEC-17 Total = $2.00 M GR:pie_firstc_rt_bydev 10.1% 6.6% GR:chart_firstc_rt_bydev_13mo $3 Last 13 Months 16.2% $2 Millions $1 67.1% $0 DEC16 JAN17 FEB17 MAR17 APR17 MAY17 JUN17 JUL17 AUG17 SEP17 OCT17 NOV17 DEC17 Gen Inc Import Load Gen Inc Import Load Gen Generator deviations Inc Increment Offer deviations Import Import deviations Load Load obligation deviations 67

68 LSCPR Charges by Reliability Region $5.0 GR:lscpr_charges_byzone_13mo $4.0 $3.0 Millions $2.0 $1.0 $0.0 DEC16 JAN17 FEB17 MAR17 APR17 MAY17 JUN17 JUL17 AUG17 SEP17 OCT17 NOV17 DEC17 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 68

69 NCPC Charges for Voltage Support and High Voltage Control $1.1 GR:var_charges_stack_13mo $1.0 $0.9 $0.8 $0.7 Millions $0.6 $0.5 $0.4 $0.3 $0.2 $0.1 $0.0 DEC16 JAN17 FEB17 MAR17 APR17 MAY17 JUN17 JUL17 AUG17 SEP17 OCT17 NOV17 DEC17 DA HV NCPC DA LV NCPC RT HV NCPC RT LV NCPC 69

70 NCPC Charges by Type $125 $118.1 Value of Charges GR:NCPC_Stack $100 $75 $73.1 Millions $50 $51.8 $25 $0 $4.4 $7.1 $5.2 $2.9 $5.2 $3.0 $1.2 $1.2 $3.7 $3.8 $7.1 $ JAN2017 FEB2017 MAR2017 APR2017 MAY2017 JUN2017 JUL2017 AUG2017 SEP2017 OCT2017 NOV2017 DEC2017 1st C 2nd C Distr Voltg 70

71 NCPC Charges as Percent of Energy Market 4.0% NCPC By Type as Percent of Energy Market GR:NCPC_pct_Stack 3.0% Percent 2.0% 2.0% 1.8% 1.0% 1.9% 0.3% 0.4% 2.0% 1.2% 1.0% 1.3% 1.0% 1.0% 1.3% 2.3% 1.2% 0.8% 0.0% JAN2017 FEB2017 MAR2017 APR2017 MAY2017 JUN2017 JUL2017 AUG2017 SEP2017 OCT2017 NOV2017 DEC2017 1st C 2nd C Distr Voltg 71

72 First Contingency NCPC Charges $80 $70.0 Value of Charges GR:Graph19 4.0% % of Energy Market Value GR:Graph20 $60 3.0% Millions $40 $20 $0 $40.5 $ JAN2017 FEB2017 $3.5 $3.0 $3.4 $2.6 $4.2 $2.6 MAR2017 APR2017 MAY2017 JUN2017 JUL2017 AUG2017 $1.1 $1.1 $2.6 $3.4 $2.9 $5.5 SEP2017 OCT2017 NOV2017 DEC % 1.0% 0.0% 1.2% 1.0% 0.8% % 1.0% 0.8% 0.9% 1.5% 0.9% JAN2017 FEB2017 MAR2017 APR2017 MAY2017 JUN % 0.4% 0.9% 1.1% 0.8% JUL2017 AUG2017 SEP2017 OCT2017 NOV % 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 Second Contingency NCPC Charges $50 Value of Charges GR:Graph21 3.0% % of Energy Market Value GR:Graph22 $42.7 $40 $30 $ % Millions $20 $ % 0.7% 0.8% 1.1% 1.2% $10 $ JAN2017 $0.9 $3.3 $0.8 $0.0 $1.0 $0.3 FEB2017 MAR2017 MAY2017 JUN2017 APR2017 $0.0 $0.0 $1.0 $0.3 $4.2 $0.5 JUL2017 AUG2017 SEP2017 OCT2017 NOV2017 DEC % % 0.2% JAN2017 FEB % MAR2017 APR2017 MAY2017 JUN % 0.1% 0.0% 0.0% JUL2017 AUG % 0.1% SEP2017 OCT2017 NOV % 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 73

74 Voltage and Distribution NCPC Charges $6 $5.4 Value of Charges GR:Graph17 3.0% % of Energy Market Value GR:Graph18 $5 $4 $ % Millions $3 $2 $ % $1 $ JAN2017 $0.0 $0.8 $1.0 FEB2017 MAR2017 APR2017 MAY2017 $0.4 $0.1 $0.1 JUN2017 $0.0 JUL2017 AUG2017 $0.0 $0.0 $0.0 $1.1 SEP2017 OCT2017 NOV2017 DEC % 0.1% 0.0% 0.1% % 0.3% 0.2% JAN2017 FEB2017 MAR2017 APR2017 MAY % 0.0% 0.0% JUN % JUL2017 AUG % 0.0% 0.0% SEP2017 OCT2017 NOV % 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 74

75 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 75

76 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% December-16 NEMA CT ME NH VT RI SEMA WCMA Hub Day-Ahead $53.23 $52.78 $52.42 $52.96 $52.81 $53.12 $53.53 $53.29 $53.28 Real-Time $53.94 $53.34 $52.00 $53.38 $52.53 $53.68 $53.98 $53.79 $53.83 RT Delta % 1.3% 1.1% -0.8% 0.8% -0.5% 1.0% 0.8% 0.9% 1.0% December-17 NEMA CT ME NH VT RI SEMA WCMA Hub Day-Ahead $71.60 $69.59 $69.63 $71.06 $70.89 $71.15 $71.63 $71.33 $71.31 Real-Time $80.61 $78.39 $74.27 $77.57 $77.93 $79.73 $80.44 $79.77 $79.89 RT Delta % 12.6% 12.7% 6.7% 9.2% 9.9% 12.1% 12.3% 11.8% 12.0% Annual Diff. NEMA CT ME NH VT RI SEMA WCMA Hub Yr over Yr DA 34.5% 31.8% 32.8% 34.2% 34.2% 33.9% 33.8% 33.8% 33.9% Yr over Yr RT 49.4% 47.0% 42.8% 45.3% 48.3% 48.5% 49.0% 48.3% 48.4% 76

77 Monthly Average Fuel Price and RT Hub LMP Indexes GR:Graph March 2003= MAR2003 SEP2003 MAR2004 SEP2004 MAR2005 SEP2005 MAR2006 SEP2006 Natural Gas MAR2007 SEP2007 MAR2008 SEP2008 MAR2009 SEP2009 Hub RT LMP MAR2010 SEP2010 MAR2011 SEP2011 MAR2012 SEP2012 MAR2013 SEP2013 MAR2014 SEP2014 MAR2015 SEP2015 MAR2016 SEP2016 MAR2017 SEP2017 MAR2018 Underlying natural gas data furnished by: 77

78 Monthly Average Fuel Price and RT Hub LMP $30 $27 GR:hubwgas_mly_smd $200 $24 $160 $21 $/MMBtu (Fuel) $18 $15 $12 $120 $80 $/MWh (Electricity) $9 $6 $40 $3 $0 MAR2003 SEP2003 MAR2004 SEP2004 MAR2005 SEP2005 MAR2006 SEP2006 MAR2007 SEP2007 MAR2008 SEP2008 MAR2009 Natural Gas SEP2009 MAR2010 SEP2010 MAR2011 SEP2011 MAR2012 SEP2012 MAR2013 SEP2013 MAR2014 SEP2014 MAR2015 Hub RT LMP SEP2015 MAR2016 SEP2016 MAR2017 SEP2017 MAR2018 $0 Underlying natural gas data furnished by: 78

79 New England, NY, and PJM Hourly Average Real Time Prices by Month $80 Monthly, Last 13 Months GR:three_pools_prices_mly $220 Daily: This Month GR:three_pools_prices_dly Electricity Prices ($/MWh) $70 $60 $50 $40 $30 Electricity Prices ($/MWh) $200 $180 $160 $140 $120 $100 $80 $60 $40 $20 DEC2016 JAN2017 FEB2017 MAR2017 APR2017 MAY2017 JUN2017 ISO-NE NY-ISO PJM JUL2017 AUG2017 SEP2017 OCT2017 NOV2017 DEC2017 $20 $0 01DEC17 02DEC17 03DEC17 04DEC17 07DEC17 08DEC17 09DEC17 10DEC17 11DEC17 12DEC17 13DEC17 14DEC17 15DEC17 16DEC17 17DEC17 18DEC17 19DEC17 20DEC17 21DEC17 22DEC17 23DEC17 24DEC17 25DEC17 26DEC17 27DEC17 05DEC17 06DEC17 ISO-NE NY-ISO PJM 28DEC17 29DEC17 30DEC17 31DEC17 *Note: Hourly average prices are shown. *Note: Hourly average prices are shown. 79

80 New England, NY, and PJM Average Peak Hour Real Time Prices $110 Monthly, Last 13 Months GR:three_pools_prices_fpk_mly $300 Daily: This Month GR:three_pools_prices_fpk_dly $100 Electricity Prices ($/MWh) $90 $80 $70 $60 $50 Electricity Prices ($/MWh) $200 $100 $40 $30 DEC2016 JAN2017 FEB2017 MAR2017 APR2017 MAY2017 JUN2017 ISO-NE NY-ISO PJM JUL2017 AUG2017 SEP2017 OCT2017 NOV2017 DEC2017 $0 01DEC17 02DEC17 03DEC17 04DEC17 07DEC17 08DEC17 09DEC17 10DEC17 11DEC17 12DEC17 13DEC17 14DEC17 15DEC17 16DEC17 17DEC17 18DEC17 19DEC17 20DEC17 21DEC17 22DEC17 23DEC17 24DEC17 25DEC17 26DEC17 27DEC17 05DEC17 06DEC17 ISO-NE NY-ISO PJM 28DEC17 29DEC17 30DEC17 31DEC17 *Forecasted New England daily peak hours reflected 80

81 Reserve Market Results December 2017 Maximum potential Forward Reserve Market payments of $3.6M were reduced by credit reductions of $195K, failure-toreserve penalties of $292K and failure-to-activate penalties of zero, resulting in a net payout of $3.1M or 86% of maximum Rest of System: $1.16M/1.26M (92%) Southwest Connecticut: $0.05M/0.16M (31%) Connecticut: $0.53M/0.55M (97%) NEMA: $1.4M/1.6M (84%) $2.3M total Real-Time credits were not reduced by any Forward Reserve Energy Obligation Charges, resulting in a net of $2.3M in Real-Time Reserve payments Rest of System: 259 hours, $1783K Southwest Connecticut: 259 hours, $161K Connecticut: 259 hours, $174K NEMA: 259 hours, $136K * Failure to reserve results in both credit reductions and penalties in the Locational Forward Reserve Market. 81

82 LFRM Charges to Load by Load Zone ($) $5.0 LFRM Charges by Zone, Last 13 Months GR:Graph39 $4.0 $3.0 Millions $2.0 $1.0 $0.0 DEC16 JAN17 FEB17 MAR17 APR17 MAY17 JUN17 JUL17 AUG17 SEP17 OCT17 NOV17 DEC17 CT ME NEMA NH RI SEMA VT WCMA 82

83 Zonal Increment Offers and Cleared Amounts MWh 140, , , , ,000 90,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10, December Monthly Totals by Zone GR:Graph Hub ME NH VT CT RI SEMA WCMA NEMA Cleared Offered 83

84 Zonal Decrement Bids and Cleared Amounts MWh 180, , , , , , , , ,000 90,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10,000 0 December Monthly Totals by Zone GR:Graph Hub ME NH VT CT RI SEMA WCMA NEMA Cleared Bid 84

85 Total Increment Offers and Decrement Bids 1,100,000 Zonal Level, Last 13 Months GR:Graph30 1,000, , , ,000 MWh 600, , , , , ,000 0 DEC2016 JAN2017 FEB2017 MAR2017 APR2017 MAY2017 JUN2017 JUL2017 AUG2017 SEP2017 OCT2017 NOV2017 DEC2017 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 85

86 Dispatchable vs. Non-Dispatchable Generation 14,000 Total Monthly Energy; Dispatchable % Shown GR:Graph31 12,000 GWh 10,000 8, % 46.0% 47.1% 45.5% 59.4% 46.0% 46.1% 50.2% 49.9% 51.0% 54.4% 51.7% 46.2% 6,000 4,000 2,000 0 DEC2016 JAN2017 FEB2017 MAR2017 APR2017 MAY2017 JUN2017 JUL2017 AUG2017 SEP2017 OCT2017 NOV2017 DEC2017 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). 86

87 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 DEC16 JAN17 FEB17 MAR17 APR17 MAY17 JUN17 JUL17 AUG17 SEP17 OCT17 NOV17 DEC17 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 87

88 PER Adjustments $5.0 GR:fcm_per_adj_byzone_big $4.0 Millions ($) $3.0 $2.0 $1.0 $0.0 DEC16 JAN17 FEB17 MAR17 APR17 MAY17 JUN17 JUL17 AUG17 SEP17 OCT17 NOV17 DEC17 CT ME NEMA ROP month PER Adjustments are reductions to Forward Capacity Market monthly payments resulting from the rolling average PER. 88

89 REGIONAL SYSTEM PLAN (RSP) 89

90 Planning Advisory Committee (PAC) January 18 PAC Meeting Agenda Topics* 2017 Interface Flow and Other System Performance Summaries Western and Central MA 2027 Needs Assessment Scope of Work Critical Load Level and Need-by-Date Determination * Agenda items are subject to change. Visit for the latest PAC agendas. 90