MPRP Northern Route Alternatives N5 versus N1 NEPOOL Reliability Committee March 17, 2009

Agenda Provide a recap of primary northern route alternatives for the MPRP Describe basis for selected route N5 Overview of analyses performed Description of process followed Respond to questions from recent RC and TCA Stakeholders Meetings, including a Present Value analysis comparing N1 and N5

MPRP Northern Routes Alternatives Assessment Developed 5 Northern Solutions (N1 thru N5) Dropped N4 - Weakest Electrical Performance; Highest Cost Analyzed 4 Solutions (N1, N2, N3, N5) in detail Performance Evaluation Compliance with reliability criteria for N-1 and N-1-1 Year 2017 Summer 90/10 peak load 18 base cases (6 dispatches, with 3 transfer conditions) Electrical performance evaluation based on: Longevity 115-kV Operability Loss Savings Transfer Capability

Assessment Criteria (Cost & Performance) Electrical Performance Ranking based on: Longevity Evaluation Reliability assessment analyzed 15- and 20-year N-1 analysis for each alternative and compared both voltage and thermal reliability criteria violations 115 kV Operability Evaluation Evaluated N1 & N5 alternatives with a limited number of single 115 kV line outages Loss Savings Evaluation Average of the loss savings for the 18 cases for each alternative Transfer Capability Evaluation Analyzed steady-state thermal transfer capability of Orrington-south interface in north-to-south direction Other considerations: Renewable integration Design factors to mitigate the risk of Extreme Contingencies & Conditions

MPRP Transmission Alternatives Assessment Longevity Analysis – Thermal Results N-1 (First Contingency)

MPRP Transmission Alternatives Assessment Longevity Analysis – Voltage Results N-1 (First Contingency)

Western Area – Post-Contingent Thermal Loading MPRP Transmission Alternatives Assessment Longevity Analysis (N-1) – Local Area Review Western Area – Post-Contingent Thermal Loading N1, N2 and N3 show overloads for line and / or autotransformer contingencies N5 shows overload for autotransformer contingency only Location of autotransformer at Gulf Island (N5) is preferred over Kimball Rd (N1 and N2) or Livermore Falls (N3) to reduce loading concerns on Section 62 and to eliminate need for new 115 kV line into the Lewiston area Central Area – Post-Contingent Thermal Loading Alternative N1 shows overload for Section 67 contingencies before the 15-year time frame Alternative N1 shows overload on Section 84 for several contingencies before the 20-year time frame Alternative N5 displayed reliable thermal performance at the 20-year time frame due to the Albion Rd. 345/115 kV autotransformer Autotransformer Longevity All Alternatives provide 12 to 16 years beyond 2017 before the outage of the Western autotransformer caused overload on Surowiec autotransformer Alternatives N1 and N5 provide the best longevity overall

MPRP Transmission Alternatives Assessment Longevity Analysis Summary Voltage Performance (N-1) Fifteen Year # of Violations 23 13 11 Twenty Year # of Violations 79 65 74 34 Voltage Ranking 4 2 3 1 Thermal Performance (N-1) Western Area Auto Contingency Ranking Western Area Line Contingency Ranking Central Area Contingency Ranking Southern/Central Line Contingency Ranking Thermal Ranking Auto Transformer Loading Overloads on Existing Autotransformers

MPRP Transmission Alternatives Assessment Longevity N-1 Analysis Conclusions Alternative N5 Provides the best longevity solution Only option with no violations in 2022 (15 yrs) Option with the fewest violations in 2027 (20 yrs) Alternative N5 requires only limited upgrades for 20-Year Solution N5 Alternative only requires 2nd autotransformer at new Larrabee Road Substation N1 Alternative likely requires addition of new 115 kV lines in both Central and Western Maine, along with other reinforcements Overall, Alternative N5 moves the next Year of Need out about 5 years While not studied, it was clear that there would be significant added costs to expand Alternative N1 to provide comparable longevity to Alternative N5

In Central region, several 115 kV outages were analyzed MPRP Transmission Alternatives Assessment N1 vs. N5 Operability Analysis Scope Operability is defined as the ability to operate the system under various scenarios Operability comparison conducted on N1 vs. N5 in Central and Western Maine regions N1 Autos are at Maxcys (Coopers Mills) and Kimball Road N5 Autos are at Benton (Albion Rd) and Gulf Island (Larrabee Rd) In Central region, several 115 kV outages were analyzed Section 67, Section 83, and Section 84 In Western region, several 115 kV outages were analyzed Section 62, Section 64, and Section 87

MPRP Transmission Alternatives Assessment N1 vs MPRP Transmission Alternatives Assessment N1 vs. N5 Operability Analysis Results Central Area - N5 provides more support with Benton (Albion Rd) autotransformer for both N-1 and N-1-1 Section 67, Section 83, and Section 84 Under N-1-1 conditions, voltage collapse and severe overloads for Alternative N1. Under N-1-1 conditions, no violations of reliability criteria for Alternative N5 Recommend new 115 kV transmission line (26 miles) from Maxcys to Winslow for equivalent Operability Western Area - N5 provides more support to load pocket with Gulf Island (Larrabee Rd) autotransformer for both N-1 and N-1-1 Section 62, Section 64, and Section 87 Recommend eliminating 345 kV line from Gulf Island to Kimball Road and moving autotransformer to Gulf Island for equivalent Operability

MPRP Transmission Alternatives Assessment N1 vs MPRP Transmission Alternatives Assessment N1 vs. N5 Operability Analysis Conclusion Both N1 and N5 meet reliability standards per MPRP scope. However, there is a major difference in how these alternatives perform under N-1 and N-1-1 conditions. In many cases, local area voltage collapse in N1 following the second contingency reinforces the conclusion that N5 is more robust electrically and will serve the load in the Western and Central Maine areas the longest during both normal and emergency conditions. The effect of moving the N1 autotransformer location and additional 115 kV reinforcement is an additional $27M.

Reduction in losses due solely to changes in Maine MPRP Transmission Alternatives Assessment N1 vs. N5 System Loss Savings All dispatch scenarios and transmission alternatives were compared against the base system without upgrades in 2017 Reduction in losses due solely to changes in Maine N5 had the highest average loss savings of 21.8 MW The average loss savings of N1 is 20.6 MW N5 average loss savings are 1.2 MW greater than N1 14

N5 (and N2) had the highest thermal transfer capability at 1975 MW MPRP Transmission Alternatives Assessment N1 vs. N5 Transfer Capability Analysis Summer Peak load assessment of first contingency thermal transfer limit on Orrington-South interface Existing limit is 1200 MW due to loss-of-source limit for single contingency N5 (and N2) had the highest thermal transfer capability at 1975 MW N1 was the next highest at 1925 MW. 50 MW incremental transfer limit for N5 over N1 15

MPRP Transmission Alternatives Assessment Comparison Summary ROUTE ALTERNATIVES N1 N2 N3 N5 Electrical Performance 3 2 4 1 Longevity Loss Savings 20.6 MW 21.3 MW 19.8 MW 21.8 MW Thermal Transfer Capability 1925 MW 1975 MW 1725 MW Total Estimated Cost $905M $1,037M $979M $1,001M Estimate to Achieve Similar Operability $27 M Estimated Cost for Similar Operability $932 M $1,001 M

MPRP Transmission Alternatives Assessment Selected Alternative: N5 MPRP Northern Alternative N5 Best Electrical Performance Best Longevity Best Operability Best Loss Savings Highest Thermal Transfer Capability Additional 345 kV Transmission Corridors Fewer 345 kV lines in common Rights-of-Way and more 345 kV substation reinforcements at different locations Stronger Reinforcement of Central Maine – 345 kV transformation closer to major generation & load centers Relies on fewest static capacitors to achieve reliable performance Better integration of wind and/or Canadian resources to the north Concurrence from ISO-NE The above advantages of N5 over N1 were not quantified in a Net Present Value (“NPV”) analysis as part of CMP’s selection process

Process for Alternatives Assessment & Choice N1 vs. N5 Evaluation CMP MPRP project team met several times in fall 2007 with ISO-NE technical staff & senior management to review alternative analysis and basis for decision CMP & ISO reached consensus on N5 vs. N1 performance difference and N5 as the best choice for MPRP ISO-TO System Planning Group reviewed the N5 vs. N1 analysis & decision and accepted it subject to TCA review N5 was presented as CMP’s choice to PAC in January 2008 N5 was studied and reviewed with the NEPOOL Reliability Committee task forces through the PPA process The selection of northern route N5 has been thoroughly vetted with ISO-NE and stakeholder groups No opposition to the selection from any stakeholders

Questions from Recent Meetings After the January 29th TCA Stakeholders Meeting, ISO-NE asked CMP for an “NPV analysis of N5 versus N1” CMP’s Approach Express the Costs of N1 and N5 in NPV Revenue Requirements Longevity – The entire scope of added projects & costs of N1 are unknown Operability – Estimate the Added Costs to Provide Comparable Operability Losses – Estimate the impact on regional LMP cost to load Transfer Capability – LMP effects included in the estimate on Losses CMP and ISO original decision making process Recognized these benefits qualitatively Only Operability costs were estimated at that time

MPRP N1 vs. N5 NPV Analysis Costs of N5 versus N1 Base N5 costs $96 million more than N1 (in 2012$) That difference decreases to $69 million with equivalent operability Multiply by annual carrying charge factor and add O&M costs to estimate incremental revenue requirements NPV in 2008$ of incremental revenue requirements for N5 is $52 million

Energy market simulations performed assuming N1 instead of N5 MPRP N1 vs. N5 NPV Analysis Evaluated Benefits of Losses and Transfer Capability N5 has 50 MW higher transfer capability for Orrington-South interface, compared to N1, based upon thermal analysis N5 has higher loss savings (21.8 MW) than N1 (20.6 MW) at the peak hour, based upon an average of all dispatch and transfer scenarios. Energy market simulations performed assuming N1 instead of N5 NPV of Benefits in 2008$ With N5, NPV of regional energy costs are $11 million to $63 million lower than with N1 Above NPV savings exclude benefits from N5’s greater longevity and superior operability

MPRP N1 vs. N5 NPV Analysis La Capra Northeast Market Model Based upon the PROSYM simulation software NE system representation based upon latest CELT and RSP databases Benchmarked against latest year of historical LMP data Renewable energy build-outs assumed to comply with RPS Convention build-outs when necessary to achieve resource adequacy Maine modeled as three energy zones BHE, central Maine, southern Maine

MPRP N1 vs. N5 NPV Analysis NPV Summary ROUTE ALTERNATIVES N1 N5 N5 – N1 Total Estimated Capital Cost, 2012 $905M $1,001M $96M Estimate to Achieve Similar Operability, 2012 $27M ($27 M) Total NPV of Revenue Requirements, 2008$ $698M $750M $52M Estimate of Energy Cost difference due to Losses & Thermal Transfer Capability, 2008$ $11 - $60M ($11 - $60M) Total Estimated Net Cost NPV, 2008$ $709 - 758M $41M - ($8M)