1. Copyright © 2013 The Brattle Group, Inc. PRESENTED TO PRESENTED BY Net CONE for the ISO-NE Demand Curve 3 rd Response to Stakeholder Comments and Draft Proposal NEPOOL Markets Committee Samuel Newell, Brattle Chris Ungate, Sargent & Lundy February 27, 2014

2. | brattle.com1 Agenda Responses to Stakeholder Questions and Comments Principles for Selecting the Reference Technology Capital and FOM Cost Estimates CONE Calculation E&AS Revenue Offset PER/PFP Review of Reference Technologies Draft Recommendation Next Steps

3. | brattle.com2 Principles for Selecting the Reference Technology Can you clarify the wording of the Principles? Slide 3 Can a Frame CT unit be permitted in New England? Slide 4

4. | brattle.com3 Principles for Selecting a Reference Technology Objective Estimate Net CONE that supports prices just high enough to attract sufficient new investment to meet resource adequacy objectives Criteria for selecting the Reference Technology to meet the objective Reliably able to help meet load when installed capacity is scarce Complies with all environmental regulations Dispatchable technology that is available to generate during system peaks Likely to be economic Available as a utility-scale commercial plant Lowest or near-lowest estimated Net CONE Demonstrated commercial interest by developers, as evidenced by projects recently completed, under construction, or in the queue in New England or the rest of U.S. Can estimate Net CONE with low uncertainty Cost estimates based on established technologies Less E&AS uncertainty relative to other technologies

5. | brattle.com4 Permitting of F-Class Frame CT Based on stakeholder input, we investigated further whether a frame CT with a lower efficiency (and higher CO 2 emissions) relative to aeroderivatives would be able to receive an air permit As no F-class frame-type CT has been proposed recently in New England, there is no record of a Frame CT being approved or refused an air permit We discussed permitting a Frame CT with MA and Connecticut environmental officials, who said that the permit would not be denied solely based on technology Recent Footprint/CLF settlement may raise perceived risks of getting a Frame CT permit in MA, although capacity factor is much lower than CC Although permitting risks appear to exist (especially in MA), we do not believe that these risks should disqualify the Frame CT as the Reference Technology There has not yet been a permit refused The plant could be located in other states

6. | brattle.com5 Capital and FOM Cost Estimates What are the estimated electrical interconnection costs? Slide 6 Can you show how a brownfield plant would impact the costs? Slide 8 Should we assume the CC has dual-fuel capabilities? Slide 9 Can you estimate CONE for an LM6000, and how do the costs depend on configuration (e.g., 4x0 vs. 2x0)? Slide 10 Can you compare LMS100 and LM6000 cost estimates to actual units? Slide 11

7. | brattle.com6 Electrical Interconnection Assumptions We completed our estimate of electrical interconnection costs Assume no network upgrades needed, consistent with recent projects Conducted a bottom-up analysis of direct interconnection costs Determined that direct interconnection needs would be the same for all reference technologies Assumptions on direct interconnection needs for all technologies: 345 kV interconnection sized for 200 – 700 MW generating plant Point of interconnection is existing 345 kV open air substation 0.5 mile transmission line between plant and expanded substation A position is available in the existing switchyard for connection of the line from the plant Adequate space is available in the existing control building for the additional panels Battery and charger have sufficient capacity for the additional load Modifications at two remote switchyards for a new relay panel for line protection Based on input from ISO-NE, S&L established a list of necessary equipment Items include disconnect switches, circuit breakers, capacitance voltage transformers, relay and metering panels, steel and supporting structure, foundations, aluminum bus and supports, insulators, power and control cables for connecting the equipment, panel wiring, conduit, high voltage jumpers, hardware, and connections to the ground grid

8. | brattle.com7 Electrical Interconnection Costs S&L estimated the direct interconnection costs Switchyard modifications at $6.0 million 0.5 mile transmission line at $1.1 million Total is $7.1 million for all reference technologies We added these costs into our analysis, replacing the placeholder values previously included, which had the following impact on CONE TechnologyInitial Value (2013$) Updated Value (2013$) CONE Impact (2018$/kW-mo) LMS100$7.0m$7.1m+$0.01 Frame CT$10.0m$7.1m-$0.09 CC$14.0m$7.1m-$0.14

9. | brattle.com8 Effects of Greenfield Assumptions Stakeholders asked how costs would differ for a brownfield unit We estimate capital costs would be 3-6% lower for a brownfield location by assuming the following infrastructure is in place, requiring no or limited modifications: Water well infrastructure Fire pumps Fire/makeup water storage tanks CO 2 bulk gas storage Raw water and fire protection piping and piping components Buildings: Control, Warehouse, Admin Sanitary sewer system and waste treatment system Various site works (fencing, roads, etc.) Actual savings is very site specificcould be lower or higher However, we continue to assume a greenfield site due to the generic nature of the reference resource and because brownfield sites could be limited

10. | brattle.com9 CC Dual-Fuel Specification Stakeholders asked whether it was necessary for dual-fuel capability to be included on a CC Ensuring enough guaranteed fuel supply to meet reliability objectives during cold snaps is a major concern for ISO-NE ISO-NE sponsored a separate analysis which indicated that the proposed PI incentives would justify the costs of dual-fuel capability We include dual-fuel capability on all plants The incremental cost is about $17.5 million (2013$) for the CC Includes equipment, labor, and materials, indirect costs, and fuel inventory Dual-fuel costs contribute $0.5/kW-mo to the Net CONE

11. | brattle.com10 LM6000 Cost Estimate In response to stakeholder requests, we completed a cost estimate for an LM6000 assuming a 4x0 configuration (174 MW) to take advantage of economies of scale Cost of many common facilities does not increase or increase significantly with extra units, such as buildings, water treatment, site works, interconnections, etc. There could also be discounts on higher volume orders of turbines, but our estimate does not include this The LM6000 has higher Gross CONE than the LMS100 and will be expected to have E&AS margins less than the LMS100 due to its higher heat rate Component (2018$)LM6000LMS100 Overnight Cost$1,962/kW$1,705/kW Capital Carrying Cost$17.9/kW-mo$15.5/kW-mo Fixed O&M$3.3/kW-mo$2.9/kW-mo Gross CONE$21.1/kW-mo$18.4/kW-mo

12. | brattle.com11 Comparison to Actual Plant Costs Based on stakeholder requests, we compared our aeroderivative CT cost estimates to the actual costs of the turbines in Connecticuts peaker solicitation One single unit LMS100 bid @ $1,449/kW Seven 2-10 unit LM6000 bids ranging from $1,046/kW to $1,292/kW An apples-apples comparison is not straight-forward, due to : Escalation to 2013 dollars Brownfield sites and Number of units Chillers and Gas/electrical interconnection costs Lack of detail on equipment pricing, owners cost, fuel inventory, spare parts, working capital, financing fees, etc. Outside of items for which no detail was available, the biggest reasons for the lower costs of the CT peakers are economies of scale, escalation, and brownfield After accounting for all of those differences, the adjusted costs are comparable, but we are slightly higher Hence we reduced some of our soft costs that are based on judgment and calibration

13. | brattle.com12 Capital Cost Adjustments Based on those comparisons, we made the following changes to our capital cost assumptions Reduced EPC Contingency from 12% to 10% Reduced Owners Costs (Services) from 7% of EPC Costs to 6% Reduced Owners Contingency from 10% to 8% Adjusted method of escalating costs from 2013$ to 2018$ to better account for when costs are incurred in the drawdown schedule These changes have the following impacts on Overnight Costs (2018$/kW) and Net CONE (2018$/kW-mo) TechnologyInitial Capital Costs Final Capital Costs Impact on Net CONE LMS100$1,754/kW$1,705/kW-$0.79/kW-mo Frame CT$908/kW$874/kW-$0.41/kW-mo CC$1,196/kW$1,143/kW-$0.82/kW-mo

14. | brattle.com13 CONE Calculations Would a higher ATWACC be more appropriate based on discussion with local developers? Slide 14 Is a 20-year economic life appropriate for the Demand Curve? Slide 15 How would the lumpy addition of a CC impact FCM prices and the CC CONE? Slide 16

15. | brattle.com14 Cost of Capital Adjustments Based on conversations with stakeholders, we adjusted the assumed capital structure to better reflect typical projects and their associated COE and COD Yet we are maintaining the 8.0% ATWACC we already established using multiple reference points, hence CONE will not change = DF×COD×(1-T) + (1-DF)×COE We were also asked to clarify the treatment of taxes corresponding to our cost of capital. We use a very standard approach Apply the ATWACC to cash flows after deducting corporate income taxes (after accounting for depreciation deductions) Treat these cash flows as all-equity cash flows, such that interest on debt and the debt tax shield are accounted for through the ATWACC, not the cash flows Our cost of capital will appear lower than equivalent costs expressed in pre-tax terms ComponentInitial ValueFinal Value Debt Fraction (DF)50%60% Cost of Debt (COD)7.0% Cost of Equity (COE)11.9%13.8% Tax Rate (T)40.5% ATWACC8.0%

16. | brattle.com15 Economic Life Stakeholder asked that we consider a longer economic life for the reference technologies After reviewing the economic life for calculating Net CONE, we will maintain the assumption at 20 years for all technologies Reasons for longer economic life Stakeholders view power generation plants as 30+ year assets Longer economic life is consistent with our assumptions for O&M costs No major equipment replacements are required until rotor replacement at 25 years or later (depending on hours of operation) Reasons for shorter economic life in financial modeling Market risks, including lower cost capacity resources entering market Risk of market interventions that depress prices

17. | brattle.com16 Impact of Lumpy New Entrants We initially assumed CONE based on a level-real assumption (total revenues increase at inflation) Some stakeholders said CONE should recognize that new entrants will opt for the 5-year lock-in and depress the price other resources receive To account for the lumpiness effect, we estimated future capacity prices as % of Net CONE, assuming: Lock-in keeps prices constant nominally for 5 years NICR increases 381 MW/yr due to load growth New entry from 715 MW CCs when capacity prices rise above CC Net CONE For an entrant to earn its required return, it would have to offer $0.64/kW-mo above level-real Net CONE The impact could be smaller if retirements absorb the overhang, if entrants are smaller, or if E&AS revenues increase; but other factors such as energy efficiency or new renewables or transmission could go the other way. Overall, we believe the adder is justified. Cash Flows with Lumpy Investments and 5-yr Lock-In

18. | brattle.com17 E&AS Revenue Offset CC E&AS margins should not be zero in some months. Slide 18 Do CC E&AS margins account for improvement in heat rate relative to existing units? Slide 19 Can you compare the CC E&AS margins you calculated to CC margins in PJM? Slide 20 Are New England peaker operations properly accounted for in the E&AS revenues? Slides 21-22 What is the impact of using futures prices that extend beyond 12 months? Slide 23 How is the PER expected to impact future E&AS revenues? Slide 24 Has PFP been considered in the E&AS estimates? Slide 25 Should E&AS be deducted on an ex-post basis instead of from a Net CONE estimate? Slide 26

19. | brattle.com18 CC Historical E&AS with Daily Fuel Costs Stakeholders expressed concerned that our analysis of historical CC E&AS margins included very low or zero margins in Winter 2012/2013 We revised fuel costs based on daily historical fuel burn and daily Algonquin Citygate (ACG) gas prices instead of monthly averages We eliminated plants with firm gas arrangements, as their fuel costs likely differ from the daily ACG prices This decreases projected 2018/2019 E&AS margins by $0.12/kW-mo E&AS Margins ($/kW-mo) Initial Analysis Adjusted Fuel Cost Net CONE Impact CC$3.40$3.28+$0.12 CC Historical E&AS Margins

20. | brattle.com19 CC E&AS Projections with Improved Performance Based on stakeholder concerns that CC E&AS are too low, we assessed whether we should: Adjust for heat rate improvement in the technology Remove any poor performing plants from our sample of representative units CC heat rates have improved by ~200 Btu/kWh over the past 10 years; including improvement increases CC E&AS margins by $0.43/kW-mo We removed plants with very high heat rate or low capacity factor, which increases CC E&AS margins by an additional $0.94/kW-mo E&AS Margins (2018$/kW-mo) Adjusted Fuel Cost Improved Performance Net CONE Impact CC$3.28$4.65-$1.37

21. | brattle.com20 Comparison to PJM E&AS Margins Stakeholders asked us to compare CC E&AS margins to those in PJM To do an apples-apples comparison, we used a virtual dispatch model with: Heat rate = 7,350 Btu/kWh Min Up and Down Time = 4 hrs VOM = $2.35/kWh Forced Outage = 2.5% The results show that PJM margins are in fact significantly higher than ISO-NE Note: Virtual dispatch results for ISO-NE appear higher than historical actuals we are using for E&AS; this appears to be because of idealizations in the virtual dispatch, as indicated by the 73% modeled capacity factors vs. 62% actual in our sample. Monthly CC E&AS Margins Annual Average CC E&AS Margins Note: PJM gas correspond to Transco Zone-6 Non-NY (Ventyx), and PJM electricity prices correspond to the PSEG zone (Ventyx)

22. | brattle.com21 Representative Peaker Operations Stakeholders noted that units providing FRM would generate rarely, only in real-time, and then primarily with oil due to difficulties getting gas with no notice We agree and changed our sample of representative units to the new peakers providing FRM in Connecticut E&AS Net Revenues for Representative CTs

23. | brattle.com22 We updated CT E&AS analysis accordingly Similar to the CC, we averaged their historical revenues over a three year period (Oct 2010 – Sept 2013) to capture all recent revenues This includes a few months of the more recent higher FRM prices (but not the earlier Connecticut-specific LFRM) The updated CT E&AS margin is $2.72/kW-mo, incl. $1.22/kW-mo FRM We applied this margin to both the LMS100 and Frame CT due to their ability to provide fast-start Peaker E&AS Margins E&AS Margins (2018$/kW-mo) Initial Analysis Updated Analysis Net CONE Impact LMS100$3.36$2.72+$0.64 Frame CT$2.65$2.72-$0.07

24. | brattle.com23 Electricity Futures At stakeholder request, we reviewed longer- term electricity and gas futures Using NYMEX futures and OTC trades (Ventyx) through 2019, we found significantly lower gas & electric prices in winter than the extended near-term futures projection we had been using We updated our analysis using the average electricity prices from the other sources as the basis of our E&AS projections, resulting in a reduction of average 2018/2019 prices from $77.5/MWh to $52.5/MWh The change in electricity futures reduces E&AS margins by 0.77 to 1.28 $/kW-mo depending on the technology E&AS Margins (2018$/kW-mo) Extended Near-Term Futures NYMEX/ OTC Average Net CONE Impact CTs$2.72$1.95+$0.77 CC$4.65$3.37+$1.28

25. | brattle.com24 Peak Energy Rent (PER) Deduction Stakeholders asked us to quantify the impact of PER on Net CONE PER depends on number of scarcity hours We made use of ISO-NEs analysis conducted for PI; scarcity hours depend on assumptions about ties and DR dispatch We chose an intermediate value of 10.9 because forward prices used to calculate the E&AS offset do not seem to be pricing in 21 hours of shortages per year At H = 10.9, the PER deduction will be expected to be $0.87/kW-mo for all technologies, which will result in a net increase of Net CONE (see the appendix for a detailed calculation of PER)

26. | brattle.com25 Pay for Performance (PFP) Net CONE Impact Stakeholders also requested that we present an analysis of how new entrants would be impacted by PFP Our analysis of PFP shows: Each of the new technologies would expect small performance payments on net, reducing Net CONE slightly At H = 10.9, we calculate PFP will result in net performance payments of $0.09/kW-mo for both CCs and CTs See appendix for details

27. | brattle.com26 Should the Demand Curve be Based on Gross CONE with an E&AS Adjustment Made on an Ex-post Basis? There are several possible ways to make ex-post E&AS adjustments, but all are problematic: Approach 1: Deduct Asset-Specific E&AS Actually Earned by Each Resource: This is the most problematic approach, since its effect is to pay a different capacity price to each resource (for providing the same product). It also nullifies day-ahead and real-time signals from the energy and AS markets to operate and invest in such a way that provides those products at least cost. For asset classes whose gross CONE exceeds the reference units gross CONE (e.g. baseload units with high CONE and high E&A/S) the unworkable effect could be a negative capacity payment for an entire asset class. Approach 2: Deduct Generic E&A/S Offset Based on Asset-Class Proxy Units: The second most distortive approach is to deduct a different amount for each type of technology, based on estimated E&AS margins for proxy units with the same fuel type and generic asset characteristics. This has similar problems but distorts only investment decisions, not operational ones. Approach 3: Uniform E&A/S Deduction for All Resources: Therefore, any ex-poste deduction would have to be uniform, with the E&AS margins for a single reference technology applied to all resources with a CSO. In this case, however, the deduction poses risks for any other technology whose E&AS margins may be lower (e.g., higher in the merit order, such as DR or super- peakers) or weakly correlated (e.g., existing coal plants) to those of the reference unit. All suppliers would have to add their estimates of the reference technologys E&AS margin to their capacity market offers, with the disproportionate risks faced by units dissimilar to the reference resource needing to inflate their offers even higher. If actual market conditions differed from their expectations, they could earn much less than their reservation price. Finally, even an ex-post administrative calculation of EAS margins may deviate substantially from the margins received by a unit similar to the reference unit due to locational issues, dispatch in DA vs RT markets, location-specific and time-specific fuel costs, and assumed unit parameters. We remain convinced that the best approach is to deduct E&AS margins from the demand curve Net CONE on a forward basis, based on a technology that fits the Principles weve outlined

28. | brattle.com27 Summary of Impacts on Net CONE AdjustmentsLMS100Frame CTCC Feb 11 Net CONE$15.80$7.33$11.22 Updated Electrical Interconnection Costs+0.01-0.09-0.14 Lower Owners and Contingency Costs-0.79-0.41-0.82 Lumpiness Impact+0.64 Updated E&AS Fuel Costs and Representative Units+0.64-0.07-1.25 Lower Electricity Prices of Long-Term Futures+0.77 +1.28 Net PER/PFP Adjustments+0.78 New Net CONE ($2018/kW-mo)$17.85$8.95$11.71

29. | brattle.com28 Net CONE Summary Table Net CONE Summary ($2018)

30. | brattle.com29 Criteria: 1. Reliably able to help meet load during scarcity 2. Likely economic 3. Estimate with limited uncertainty Technology Meets Environ. RegulationsDispatchable Recently Built or Proposed Net CONE Estimate Accuracy of Capital and FOM Cost Estimates Accuracy of E&AS Estimate 2x0 LMS100 188 MW Yes Limited$17.85/ kW-mo Well established technology Similar magnitude, uncertainties exist 2x0 Frame CT 417 MW Yes Very limited $8.95/ kW-mo Well established technology Similar magnitude, uncertainties exist 2x1 CC 715 MW Yes $11.71/ kW-mo Well established technology Similar magnitude, uncertainties exist Review of Reference Technologies

31. | brattle.com30 Draft Proposal Our current thinking is to propose the 2x1 CC as the Reference Technology Clear signals from developers that CCs are economic and will be a part of the future capacity mix – so how wrong could choosing it be? Near-lowest Net CONE Not demonstrably higher E&AS uncertainty than CTs The concept of averaging more than one reference technology is compelling, but only if both technologies are good reference technologies The lack of Frame CT projects suggests the possibility of risks or costs that are not captured in our analysis Averaging in the Frame CT would be betting the market/reliability on a technology with little commercial demonstration; our demand curve analysis showed that the reliability risks of understating True Net CONE are much more serious than over-procurement risks of overstating True Net CONE The aeroderivative peakers Net CONE is too high be considered economic Choosing the CC would set the Net CONE at $11.71/kW-mo

32. | brattle.com31 Next Steps Additional feedback must be submitted right away to be considered in our final Net CONE analysis and proposal March 6: we will post materials for the Mar 12/13 meeting March 12/13: we will present our proposal for Net CONE March 21: MC will vote on sloped demand curve and Net CONE

33. | brattle.com32 Appendix

34. | brattle.com33 ISO-NE Analysis of Scarcity Hours Source: ISO-NE Memo to Markets Committee, Operating Reserve Deficiency Information – At Criteria And Extended Results, July 5, 2013.

35. | brattle.com34 PER: H = 10.9 Case

36. | brattle.com35 PFP: H = 10.9 Case