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| ©2006 Synapse Energy Economics Inc. All rights reserved. Electricity Cost Highlights of Avoided Energy Supply Costs in New England 2007 Final Report Briefing to Vermont Public Service Board November 27, 2007
2 | ©2006 Synapse Energy Economics Inc. All rights reserved. AGENDA Overview AESC Study Group Prior Reports Avoided Cost Components 2007 AESC Results Projections Avoided Electric Energy Costs –Electric System representation –Major Uncertainties – Gas prices, Carbon Regulation Avoided Electric Capacity Costs
3 | ©2006 Synapse Energy Economics Inc. All rights reserved. Background AESC Study Group Berkshire Gas Company KeySpan Energy Delivery New England (Boston Gas Company, Essex Gas Company, Colonial Gas Company, and EnergyNorth Natural Gas, Inc.) Cape Light Compact National Grid USA New England Gas Company NSTAR Electric & Gas Company New Hampshire Electric Co-op Bay State Gas and Northern Utilities, Northeast Utilities (Connecticut Light and Power, Western Massachusetts Electric Company, Public Service Company of New Hampshire, and Yankee Gas) Unitil (Fitchburg Gas and Electric Light Company and Unitil Energy Systems, Inc.) United Illuminating Southern Connecticut Gas and Connecticut Natural Gas, State of Maine State of Vermont Connecticut Energy Conservation Management Board Massachusetts Department of Public Utilities Massachusetts Division of Energy Resources Massachusetts Low-Income Energy Affordability Network (LEAN) New Hampshire Public Utilities Commission Rhode Island Division of Public Utilities and Carriers.
4 | ©2006 Synapse Energy Economics Inc. All rights reserved. Background Prior Reports YEARConsultantScope 1999Resource Insight & Synapse Direct avoided wholesale costs of electricity and natural gas 2001Resource Insight & Synapse New - Retail adder. 2003ICFNew - Avoided costs of other fuels. 2005ICFNew – Locational Installed Capacity Prices (LICAP), Demand Reduction Induced Price Effect (DRIPE) 2007Synapse, Resource Insight & Swanson Energy Group. New – Forward Capacity Market (FCM), CO2 environmental factor.
5 | ©2006 Synapse Energy Economics Inc. All rights reserved. Background Avoided Electricity Cost Components Avoided energy costs = (wholesale energy + Renewable Portfolio Standard or RPS compliance) adjusted for risk/retail adder Avoided capacity costs = (wholesale capacity) adjusted for losses on ISO-NE and risk risk/retail adder Other potential adders –DRIPE-energy and DRIPE-capacity –CO2 environmental cost factors program administrators –can set RPS compliance costs, risk/retail adder and losses on ISO-NE –should calculate and adjust for losses from the ISO delivery points to the end use for their specific system –should calculate and adjust for avoided transmission and distribution costs for their specific system
6 | ©2006 Synapse Energy Economics Inc. All rights reserved. Background AESC 2007 Results (cents/kwh) – Vermont Average annual price for electricity service (generation energy and capacity, transmission, distribution) to residential customers in Vermont in 2006 per U.S. Energy Information Administration – 13.4 cents/kwh AESC 2007 Results, Vermont, Summer Peak Hours (15 year levelized, constant 2007$), before adders Avoided generation energy costs 9.0 cents/kwh Avoided generation capacity costs ($ 95.6 per 55% LF) 2.0 (cumulative 11.0)
7 | ©2006 Synapse Energy Economics Inc. All rights reserved. Projections Avoided Electric Energy Costs Avoided Electric Capacity Costs
8 | ©2006 Synapse Energy Economics Inc. All rights reserved. Modeling Framework Electric supply price forecasting was done using Market Analytics, a simulation and database management module developed and licensed by Global Energy Decisions, a leading industry information and solutions company. Market Analytics is based on the PROSYM simulation engine. Market Analytics is licensed with Global Energys NERC database which includes detailed data for generation, load and transmission components of the electricity generation system for North America.
9 | ©2006 Synapse Energy Economics Inc. All rights reserved. Electric System Representation Topology Load Thermal Unit Characteristics Conventional Hydro and Pumped Storage Units Fuel Price Forecasts Transmission System Representation Environmental Regulations Demand Response Resources Market Model Assumptions
10 | ©2006 Synapse Energy Economics Inc. All rights reserved. Topology Based on the topology used for ISO-NE RSP 2006 with two exceptions: 1.SME and ME combined to form CMP 2.Norwalk included in the rest of SWCT
11 | ©2006 Synapse Energy Economics Inc. All rights reserved. Generator Representation Unit type (steam-cycle, combined-cycle, simple-cycle, cogeneration, etc) Heat rate values and curve Seasonal capacity ratings (maximum and minimum) Variable operation and maintenance costs Fixed operation and maintenance costs Forced and planned outage rates Minimum up and down times Quick start and spinning reserves capabilities Startup costs Ramp rates Emission rates (SO2, NOx, CO2, and mercury)
12 | ©2006 Synapse Energy Economics Inc. All rights reserved. Key Input Categories Load New resource additions Emission price forecasts Fuel Prices
13 | ©2006 Synapse Energy Economics Inc. All rights reserved. Load Based on 2007 ISO-NE CELT Forecast ISO-NE load forecast does not include any incremental DSM savings after 2006 Consistent with the purpose of this study which is to estimate avoided costs of DSM programs
14 | ©2006 Synapse Energy Economics Inc. All rights reserved. New Resources Planned AdditionsNear-term proposed new additions and uprates to existing plants that are in development or advanced stages of permitting and have a high likelihood of reaching commercial operation; RPS AdditionsRenewable generators that are added to meet existing or anticipated renewable portfolio standards (RPS) in each state; and, Generic AdditionsNew generic conventional resources that are added to meet the residual capacity need after adding planned and RPS additions.
15 | ©2006 Synapse Energy Economics Inc. All rights reserved. New Resources (contd) – RPS Additions RPS resources distributed throughout the region consistently with geographic distribution of proposed renewable projects in the ISO-NE queue. RPS resource mix is 65% wind, 33% biomass, 1% LFG, and 1% solar PV.
16 | ©2006 Synapse Energy Economics Inc. All rights reserved. New Resources (contd) - Generic Additions Generic additions are added to meet a system-wide reserve margin target of 14.3% Generic additions are gas/oil CCs and CTs Dispersed geographically based on distribution of proposed CC and CT projects in the ISO-NE queue.
17 | ©2006 Synapse Energy Economics Inc. All rights reserved. Emissions Allowance Price Forecasts Modeling include price forecasts for SO 2, NO x, Hg and CO 2 Price forecasts for SO 2, NO x and Hg are based upon experience with existing regulations Price forecast for CO 2 assumes Regional Greenhouse Gas Initiative (RGGI) will be in effect in 2009 and will be replaced by national regulations for CO 2 in 2012.Price forecast for CO 2 assumes Regional Greenhouse Gas Initiative (RGGI) will be in effect in 2009 and will be replaced by national regulations for CO 2 in 2012.
18 | ©2006 Synapse Energy Economics Inc. All rights reserved. Emission Allownace Price Forecasts (contd)
19 | ©2006 Synapse Energy Economics Inc. All rights reserved. Natural Gas Price Forecast Price of Gas For Electric Generation = Henry Hub + basis differential + lateral charge –Henry Hub forecast of annual prices 2007 to 2012 – NYMEX (as of May 2) – AEO 2007 reference + Swanson adjustment –Henry Hub forecast of monthly prices derived from forecast of annual price based on analysis of historical relationship between monthly and annual prices –Basis Differential - based on analysis of historical relationship between monthly HH prices and monthly prices of spot gas delivered in New England –Lateral Charge -$0.07/MMBtu (per 2005 AESC)
20 | ©2006 Synapse Energy Economics Inc. All rights reserved. Avoided Natural Gas Costs – Electric Generation in New England
21 | ©2006 Synapse Energy Economics Inc. All rights reserved. Wholesale Electric Energy Price Forecast - Benchmarking
22 | ©2006 Synapse Energy Economics Inc. All rights reserved. Wholesale Electric Energy Price Forecast - Benchmarking
23 | ©2006 Synapse Energy Economics Inc. All rights reserved. Results – Comparison to 2005 AESC Report
24 | ©2006 Synapse Energy Economics Inc. All rights reserved vs – Key Drivers
25 | ©2006 Synapse Energy Economics Inc. All rights reserved. Key Sources of Uncertainty
26 | ©2006 Synapse Energy Economics Inc. All rights reserved. AVOIDED ELECTRICITY COSTS - RPS
27 | ©2006 Synapse Energy Economics Inc. All rights reserved. AVOIDED ELECTRICITY COSTS - Capacity Transition Period (2006 to May 2010) –ICAP values ranging from $36/kw-yr to $48/kw-yr: not avoidable Forward Capacity Market (June 2010 onward) –Values assume no new DSM –Values based on Cost of New Entry (CONE) –Marginal new entrant is a gas peaker Levelized fixed cost of $130/kw-yr Less net energy revenues of $30/kw-yr Net fixed cost of $100/kw-yr Plus reserve margin of 14.3% Proposed value $114/kw-yr (2007$) –Due to early surge of demand resources bid into FCM, assume 20% reduction in 2010, 10% reduction in AESC Avoided Capacity Costs (2005$, pre-reserve margin) –Boston $72/kw-yr –Other zones $68/kw-yr
28 | ©2006 Synapse Energy Economics Inc. All rights reserved. AVOIDED ELECTRICITY COSTS - Capacity Exhibit 6-3. Illustrative FCM Price with No DSM Bids
29 | ©2006 Synapse Energy Economics Inc. All rights reserved. Wrap-Up Rick Hornby x 243 Mike Drunsic x 231
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