AESC 2005 VERMONT Result

Avoided Costs of Energy in New England Due to Energy Efficiency Programs: 

Avoided Costs of Energy in New England Due to Energy Efficiency Programs Presented to: State of Vermont Department of Public Service August 2006

Outline: 

Outline Purpose of the Report Background on DSM in New England Key Natural Gas Issues Key Electric Power Issues Natural Gas, Oil and Other Fuels Avoided Costs Electric Power Avoided Costs

Purpose of the Study: 

Purpose of the Study Develop forecast of the avoided cost of supplying natural gas, other fuels, and electricity Includes forecasts of other key New England fuels: distillate fuel oil, residual fuel oil, kerosene, propane, and wood. Also includes method for transmission and distribution capacity. Output used for regulatory filings and for energy efficiency and demand side management (DSM) program design and assessment. Natural gas avoided costs: Costs to LDCs of not having to purchase more gas and capacity to meet peak load Includes both avoided commodity and capacity costs Winter peaks defined as 3, 5, 6 and 7 month winters Electric system avoided costs: Costs savings for LSE based on demand reductions Includes Energy and Capacity Payments

Why Value Demand Reductions at Avoided Costs?: 

Why Value Demand Reductions at Avoided Costs? Customer incentives to reduce demand are not aligned with market realities. Regulated customer rates are based on average embedded cost of service (declining block rates) Utilities make investment decisions based on marginal cost, influenced by rate-based regulation Integrated resource planning has been implemented in many jurisdictions to help develop a common basis for analyzing supply side and demand side options to meet long term objectives Avoided costs of supply represent the correct comparison for comparing DSM options with supply side options.

Background on DSM : 

Background on DSM Marginal Cost Average Cost $/Q Q

New England Avoided Cost Issues: 

New England Avoided Cost Issues Natural Gas Issues New England is at the end of the continental pipeline network for its gas supply. Pipeline capacity expansions or LNG will be needed to meet growing peak demand behind LDC city gates. Gas costs and pipeline, storage, and LNG tariffs determine the avoided costs of natural gas supply. Electric Power Issues New England is relatively isolated from other regional power markets. Several internal transmission constraints exist in New England. Structural changes are actively occurring in the market place including a movement towards locational capacity markets. ICF approach shows significant savings can exist from demand side management programs, particularly those affecting peak hour load.

Natural Gas, Oil and Other Fuels Avoided CostsTasks 1, 2, and 5: 

Natural Gas, Oil and Other Fuels Avoided Costs Tasks 1, 2, and 5

Key Drivers of Gas Prices and Avoided Cost: 

Key Drivers of Gas Prices and Avoided Cost Constrained supply deliverability limits short term response to demand and prices New supply is from more distant and costly settings Growing use of gas in power generation drives demand Local infrastructure constraints contributes to wild swings in prices away from Henry Hub Current capacity into New England is about 4.1 Bcf/d Gas prices will remain volatile and markets tight

Surplus Production Capacity has Vanished: 

Surplus Production Capacity has Vanished 0 20 40 60 80 100 Jan-85 Jan-87 Jan-89 Jan-91 Jan-93 Jan-95 Jan-97 Jan-99 Jan-01 Jan-03 Bcf/d 0 20 40 60 80 100 Capacity Utilization (%) Drilled Well Production Capacity Source: Energy Information Administration

North American Gas Markets have been Dominated by Government Policies: 

Source: EIA Historical Natural Gas Annual 1930 Through 2003. Arab Oil Embargo (‘73) NYMEX (‘90) Order 636 (‘92) Gas Price ($/Mcf) LNG Projects Distrigas ’71 Elba, Cove Point ’78 Lake Charles ’82 Reactivation ‘03 North American Gas Markets have been Dominated by Government Policies Phillips Decision (’52) NGPA (‘78) Curtailments Spot Market Order 380 (‘84) Order 436 (’85) Order 500 (’87) Wellhead Price Decontrol, FTA (‘89) California Crisis (’00) Halloween Agreement (’85) Hackberry Decision (’02)

North American Gas Flows and New England: 

North American Gas Flows and New England

Six Bcf/d Proposed for Northeast LNG : 

Six Bcf/d Proposed for Northeast LNG Rabaska, Levis-Beaumont, QU: 0.5 Bcf/d (Gaz Métro, Gaz de France, Enbridge) Gros Cacouna, QU: 0.5 Bcf/d (TransCanada, Petro-Canada) Canaport LNG, St. John, NB: 0.5 Bcf/d (Irving Oil, Repsol) Bear Head LNG, Point Tupper, NS: 0.75 to 1 Bcf/d (Anadarko) Goldboro, NS: (Keltic Petrochemicals) Pleasant Point, ME: 0.5 Bcf/d (Quoddy Bay LLC) Off Cape Ann, MA: 0.4 Bcf/d (Excelerate Energy) Somerset, MA: 0.65 Bcf/d (Somerset LNG) Weaver’s Cove LNG, Fall River, MA: 0.4 to 0.8 Bcf/d (Hess LNG) KeySpan LNG, Providence, RI: 0.5 Bcf/d (KeySpan & BG LNG) Broadwater Energy, offshore Long Island, NY: 1 Bcf/d (TransCanada and Shell US Gas & Power) Crown Landing LNG, Logan Township, NJ: 1.2 Bcf/d (BP) Existing Import LNG, Everett, MA: 0.7 to 1 Bcf/d (Tractebel LNG) 3 5 6 2 7 8 9 10 12 NEWFOUNDLAND QUEBEC Map source: U.S. FERC; Updated by Northeast Gas Association based on public information as of 11-9-04 MARYLAND 4 1 11

New England Consumption is Seasonal: 

New England Consumption is Seasonal

Basis Volatility at Hubs Feeding New England : 

Basis Volatility at Hubs Feeding New England Source: Gas Daily

Natural Gas Avoided Cost Methodology: 

Natural Gas Avoided Cost Methodology FERC’s Order 636 (1992) Unbundled gas sales from transportation services Straight fixed variable rate design allocates all fixed costs to demand charges, giving better pricing signals for capacity purchases Deregulated gas prices signal commodity scarcity and surplus Secondary market in capacity allows capacity holders to resell unused capacity Avoided cost is defined as the total change in cost resulting from not having to serve the incremental customer demand Alternatively: What would a LDC have to pay in order serve incremental load? LDCs buy capacity to meet peak demand Changing demand in the peak heating season has different cost implications from changing demand in the off peak season

Natural Gas Avoided Cost Methodology: 

Natural Gas Avoided Cost Methodology We have used Long Run Avoided Cost concept Assumes fixed costs can be avoided for decrements of demand Includes incremental fixed cost for avoided expansions Our calculations involve developing a forward estimate of the cost of gas plus the cost of acquiring pipeline capacity, storage, and LNG services to serve that incremental use Components of cost The cost of the physical gas (Henry Hub Price) Transportation costs Winter Storage costs Winter LNG peaking

Steps in the Methodology: 

Steps in the Methodology Step 1: Forecast base Henry Hub price to 2025 Step 2: Establish seasonal variation for forecast years Step 3: Establish base pipeline transportation, storage, LNG costs Step 4: Allocate pipeline, storage, LNG use to seasons based on LDC use Step 5: Allocate costs to the seasons using the shares Step 6: Estimate wholesale avoided cost at the city gate Step 7: Estimate retail avoided costs using LDC margins

Cost of Physical Gas: 

Cost of Physical Gas We constructed a gas forecast using a combination of modeled long term gas prices, futures, EIA short term forecast, and a pessimistic LNG supply assessment. Short term gas prices were taken from the NYMEX futures market curve. Long term gas prices were forecasted using ICF’s North American Natural Gas Analysis System (NANGAS®) Adjustment was made from a separate ICF low supply run, based on lower LNG imports. Late in the study we made an adjustment for Hurricane Katrina effects. This resulted in increases to the forecast for the 2005 – 2009 period. Unless noted, values presented herein reflect the post-Katrina adjustments. Seasonality was estimated using historical price swings from five years of daily spot price data The average seasonality in prices over the past five years was then used for all of the years in our forecast Seasonality was mapped to the different winter month/summer month definitions

ICF Long Term Forecast: 

ICF Long Term Forecast Gas prices will decline from current levels as supply increases Prices stay high enough in Midwest to attract Alaskan Gas in 2011 At 4.5 Bcf/d, Alaska will have major impact on prices After 2011, prices gradually increase until 2018 when new supplies from enter the market and reduce prices again Gulf off shore Deep onshore gas Rockies Coal bed methane At the end of the period, strong gas demand again drives up prices

North American Gas Supply Outlook: 

North American Gas Supply Outlook Current estimates of technically recoverable resource in the US is 1,280 Tcf, 535 Tcf in Canada Producers have more than replaced production with reserves additions since 2000 Canadian conventional production in decline, but Coal bed methane resource is huge, but un-tapped so far Frontiers gas is substantial Alaska and Mackenzie Delta can contribute up to 6 bcf/d More of the resource base is in deep, tight, remote settings Technology improvements will lower cost and increase access to these resources

Long Term Forecast Comparison: AESC Studies Compared to Annual Energy Outlook (EIA): 

Long Term Forecast Comparison: AESC Studies Compared to Annual Energy Outlook (EIA)

Henry Hub Price Forecast: 

Henry Hub Price Forecast

Transportation Costs: 

Transportation Costs Estimating transportation costs involved using tariffs for Firm Transportation (FT) of the relevant pipelines In Northern and Central New England El Paso’s Tennessee Gas Pipeline (TGP) is the dominant pipeline In Southern New England Duke Energy’s Texas Eastern Transmission Company (TETCO) and Algonquin Gas Transmission (AGT) constitutes the primary system For purposes of identifying the relevant rates, we used the Gulf Coast to New England zoned charges Costs include Annualized demand charges (for pipeline capacity) expressed as $/MMBtu of contract demand (monthly demand x12) Unit commodity charges for variable costs of throughput ($/MMBtu) Fuel cost (% of gas throughput)

Storage & LNG: 

Storage & LNG We assumed the storage contracts for each of the regions are tied to the relevant pipelines – TGP and TETCO/AGT The relevant tariffs for these storage services were used to estimate storage costs Costs included storage, injection and withdrawal charges, plus fuel LNG peaking services were assumed to be equal to the cost of incremental service from Distrigas LNG. Costs included the LNG capacity service and LNG charge itself (set at a Gulf Coast price per the tariff)

Non-Gas Costs Summary: 

Non-Gas Costs Summary * Commodity rate is the price of gas.

Supply Source Weightings: 

Supply Source Weightings The next step was to determine the appropriate mix of services that a typical LDC would use to fulfill their customer’s demand. Using actual data from KeySpan and NSTAR we arrived at a set of weightings for the appropriate mix of supply sources(Transportation, LNG and Storage) during each season.

Supply Source Weightings: 

Supply Source Weightings

Allocating Costs to Seasons: 

Allocating Costs to Seasons The final step for determining the avoided costs of natural gas demand reductions LDCs must reserve capacity in transportation, storage and LNG services for the entire year just to meet demand during the peak winter demand season Thus, demand reducing strategies that are focused on the peak demand months will save LDCs the most money We divide the annual avoided cost by the number of months in various definitions of winter This assumes that the avoided cost – demand reduction – occurs during the entire winter season (as defined)

Results: 

Results Show winter and summer avoided costs for different seasonal configurations Winter costs include all fixed costs, allocated to winter and divided by months/winter Summer costs include only gas, plus variable costs Capacity costs are flat in real terms reflecting current policy of pipelines eschewing rate cases Higher costs of TETCO/AGT reflects tariff differences

Southern NE Wholesale Avoided Costs (2005$/MMBtu): 

Southern NE Wholesale Avoided Costs (2005$/MMBtu)

Northern & Central NE Wholesale Avoided Costs (2005$/MMBtu): 

Northern & Central NE Wholesale Avoided Costs (2005$/MMBtu)

Vermont Wholesale Avoided Costs (2005$/MMBtu): 

Vermont Wholesale Avoided Costs (2005$/MMBtu)

Estimating Retail Avoided Costs: 

Estimating Retail Avoided Costs Involved mapping winter types to retail sectors Commercial and industrial non-heating – Annual Commercial and industrial heating -- 5 Month Existing residential heating -- 3 Month New residential heating -- 5 Month Residential domestic hot water -- Annual All commercial and industrial -- 6 Month All residential -- 6 Month All retail end uses -- 5 Month Allocating LDC avoidable costs to end use sectors Used average retail markups from EIA Assumed 50 percent of retail markup is avoidable

Southern NE Retail Avoided Costs (2005$/MMBtu): 

Southern NE Retail Avoided Costs (2005$/MMBtu)

Northern & Central NE Retail Avoided Costs (2005$/MMBtu): 

Northern & Central NE Retail Avoided Costs (2005$/MMBtu)

Vermont Retail Avoided Cost (2005$/MMBtu): 

Vermont Retail Avoided Cost (2005$/MMBtu)

Uncertainties about Future Costs: 

Uncertainties about Future Costs North American gas prices Supply and demand response to current market Long term gas supply response in U.S. and Canada Availability of LNG Climate change regulation and future of gas for power generation Shifting capacity towards Dawn away from the Gulf Coast Recent NEGM contracting has tapped Dawn Hub in southwestern Ontario

Comparison With Previous Study for 2010 – Wholesale Avoided Cost: 

Comparison With Previous Study for 2010 – Wholesale Avoided Cost

Other Fuels Forecasts: 

Other Fuels Forecasts Other fuels forecasts, except for wood, derive generally from oil prices Oil price forecast based on analysis of futures and fundamentals Near term oil markets will remain tight, with an initial decline from recent highs After 2010, new supplies will emerge to meet demand, bringing down oil prices Overall world demand will increase and gradually raise prices Oil prices are notoriously susceptible to short term thinking about supply security and episodic disruptions and contain a risk premium not related to fundamentals

Crude Oil Price Forecast: 

Crude Oil Price Forecast

Katrina Impacts on Oil Were Small: 

Katrina Impacts on Oil Were Small

Oil and Product Prices (National): 

Oil and Product Prices (National)

Electric Power Avoided CostsTasks 3 and 4: 

Electric Power Avoided Costs Tasks 3 and 4

The Analysis Of Electric Power Avoided Costs Incorporated Several Key Steps: 

The Analysis Of Electric Power Avoided Costs Incorporated Several Key Steps Start Wholesale Price Forecast Agree on Assumptions and Methodology Perform Analysis to Determine Wholesale Average Hourly Price and Producer Cost Forecast Address Comments on Results DRIPE Forecast Agree on Assumptions and Methodology Perform Analysis to Determine DRIPE effect on wholesale prices Include DRIPE in the Avoided Cost Estimates Retail Cost Components Transmission and Distribution Develop an approach to include transmission and distribution avoidable capacity costs End Avoided Cost Forecast Present Results and Collect Comments for Final Report Finalize Report Task 3 Task 3K Task 3L Task 4

Key Drivers of Power Prices and Avoided Cost: 

Key Drivers of Power Prices and Avoided Cost Spot market energy prices are impacted by fossil fuel prices and availability, particularly natural gas, and by transmission congestion charges. Environmental allowance also have a significant impact on energy prices. Local infrastructure (transmission) constraints can contribute to high degree of price differentiation across sub-zones. Capacity value is dependent on the supply of MW available to serve the peak demand requirements. Capacity value is subject to similar infrastructure issues to energy prices. Capacity prices are subject to an uncertain future in terms of the structure which will be implemented for capacity markets going forward. Dependent on the market design, the value of capacity may not be apparent from the price signal only. Pure capacity value in an equilibrium market is reflective of the return of and on capital that a unit serving the marginal demand need has. The individual energy and capacity price drivers are discussed in further detail in the following slides.

Vermont Energy Avoided Costs ($/kWh): 

Vermont Energy Avoided Costs ($/kWh)

Vermont Energy Avoided Costs (Real 2005 $/kWh): 

Vermont Energy Avoided Costs (Real 2005 $/kWh)

Vermont Capacity Avoided Costs ($/kWh): 

Vermont Capacity Avoided Costs ($/kWh)

Annuity All-in Avoided Costs by State ($/kWh): 

Annuity All-in Avoided Costs by State ($/kWh)

Annual Energy Avoided Costs for Select Years By State (2005$/kWh): 

Annual Energy Avoided Costs for Select Years By State (2005$/kWh) Levelized at a 2.03 percent real discount rate.

Annual Capacity Avoided Costs for Select Years By State (2005$/kW-yr): 

Annual Capacity Avoided Costs for Select Years By State (2005$/kW-yr) Levelized at a 2.03 percent real discount rate.

Annual Energy Avoided Costs for Select Years By State (nominal$/kWh): 

Annual Energy Avoided Costs for Select Years By State (nominal$/kWh) Levelized at a 4.33 percent nominal discount rate.

Annual Capacity Avoided Costs for Select Years By State (nominal$/kW-yr): 

Annual Capacity Avoided Costs for Select Years By State (nominal$/kW-yr) Levelized at a 4.33 percent nominal discount rate.

Wholesale Power Market Prices Form the Basis for Avoided Costs Task 3 a-d: 

Wholesale Power Market Prices Form the Basis for Avoided Costs Task 3 a-d Energy Zones (determined by transmission constraints) Capacity Zones (as per LICAP proposal)

Wholesale Energy Prices Reflect Market Fundamentals: 

Wholesale Energy Prices Reflect Market Fundamentals Fuel prices Growth in energy demand Transmission constraints (energy prices include congestion costs and transmission losses) Environmental costs New unit operating costs

Load Growth Assumptions are a Key Driver of Potential Avoided Costs: 

Load Growth Assumptions are a Key Driver of Potential Avoided Costs Demand and load growth in New England has historically been below the national average growth level. Energy and peak demand are both expected to grow slightly less than two percent per year throughout the forecast horizon. The long-term growth rate (post 2014) in New England is roughly 1.5% annually. The U.S. average is approximately 2.5% per year. This study accounted for sub-regional differences in growth rates. Some of the faster growing zones include New Hampshire, Southwest Connecticut and Rhode Island. Some of the slower growing regions include Western Massachusetts and Norwalk. The New England RTEP study was used to derive regional growth expectations.

Transmission Constraints Also Play a Key Role: 

Transmission Constraints Also Play a Key Role Source: New England RTEP 2004.

Transmission Constraints Also Play a Key Role: 

This study considered all 13 RTEP sub-regions as individual zones. This characterization captures a reasonable set of constraints and transfer potential across areas and as well as major pricing or dispatch differentials across these areas. The sub-regions are also interconnected with external power regions including Hydro Quebec and New Brunswick and New York. Transmission flows between these regions will be solved for endogenously. In this analysis ICF also considered future transmission developments in the New England region. Some of the major upgrades considered include Phase 1 and Phase 11 of the Southwest Connecticut Reliability Project, the Southern New England Reinforcement Project, the NSTAR 345kV Transmission Reliability Project and the Northeast Reliability Interconnect Project. Transmission Constraints Also Play a Key Role

Environmental Regulations will Affect Prices - States Affected by the CAIR and Hg Rulings: 

Environmental Regulations will Affect Prices - States Affected by the CAIR and Hg Rulings

Final CAIR and Hg Rule Comparison – NOx Market Outlook: 

Final CAIR and Hg Rule Comparison – NOx Market Outlook The Clean Air Interstate Rule is modeled in this analysis. Under CAIR NOx limitations are imposed on most eastern states under a cap and trade program. NOx caps will exist on an annual and seasonal basis. NOx caps will begin in 2009 and tighten in 2015.

Final CAIR and Hg Rule Comparison – SO2 and Hg Market Outlook: 

Final CAIR and Hg Rule Comparison – SO2 and Hg Market Outlook SO2, similar to NOx, is controlled under the CAIR rule affecting most eastern states. This implementation affects the allowance trading ratios in the eastern states under Title IV of the Clean Air Act. The Clean Air Mercury Rule implements a national tradable tonnage cap for Mercury at 38 tons in 2010 and reducing to 15 tons in 2018.

Environmental Regulations will Affect Prices -CO2 Market Outlook: 

Environmental Regulations will Affect Prices -CO2 Market Outlook In addition to the national expected case, a northeast regional CO2 program was considered to be in place as a precursor to the national program.

Slide63: 

Summary of Northeast/Mid-Atlantic (NEMA) RPS Policies impacting New Renewable Generation All renewable market assumptions have been normalized to reflect state requirements for new renewable generation. Actual state renewable standards are well above those presented above. For instance, Connecticut, New Jersey, and Maryland have Class II renewable requirements. All states allow wind, landfill gas, biomass gasification, fuel cells, geothermal, solar, small hydro, and tidal renewables. Note that the PA RPS is prorated by 50% to account for Midwest ISO and existing renewable expected contribution to meeting RPS standard. In addition, the requirement has been prorated to take into account the solar tier component. The resultant RPS begins at 0.75% in 2006 and grows to 3.75% in 2020 and thereafter.

New Unit Performance and Operating Costs will Affect Future Energy Prices: 

New Unit Performance and Operating Costs will Affect Future Energy Prices Over-time, technological improvements are anticipated such that new units coming on will be more efficient than prior vintages of similar unit types. As units come on, these newer units will tend to reduce overall energy prices.

Post-Katrina Natural Gas Price Forecast Update Moves Energy Price Projections Up 28 Percent: 

Post-Katrina Natural Gas Price Forecast Update Moves Energy Price Projections Up 28 Percent A near-term adjustment was made to the energy price forecast to account for the affect of the hurricane Katrina on natural gas production and distribution in the gulf. This adjustment affected the near-term only. The adjustment was an off-line adjustment from the existing modeling runs holding the implied heat rate flat. An off-line adjustment was used as the report was near completion at the time of the meeting. Note, the changes were made regionally and by time of day; Rhode Island is shown for explicative purposes. Levelized at a 2.03 percent real discount rate.

Annual Wholesale Energy Price for Select Years By State (2005$/kWh): 

Annual Wholesale Energy Price for Select Years By State (2005$/kWh) Levelized at a 2.03 percent real discount rate.

Annual Wholesale Energy Prices By State (continued): 

Annual Wholesale Energy Prices By State (continued) The energy price forecast is very closely tied to the gas price forecast. The energy prices are very strong throughout the forecast given the dominance of oil and gas fired generation in the New England region. The near-term prices in particular are very strongly tied to the gas price forecast. New unit efficiency and environmental policies only play a role in the mid to long-term as new units come online to meet growing demand and environmental polices become more stringent. On a zonal level, in the near-term, energy prices are higher in the import constrained regions of Norwalk, Southwest Connecticut and Norwalk. Overall, prices also tend to be higher in zones west of the East/West constraint.

Wholesale Capacity Prices Also Reflect Market Fundamentals: 

Wholesale Capacity Prices Also Reflect Market Fundamentals Market design (ICAP / LICAP / Bundled or others) – this analysis assumes that a LICAP market structure will exist going forward. Transmission constraints – under LICAP, locational value is created due to transmission constraints. In the most extreme cases, constraints will strand megawatts or will isolate load resulting in very low or very high capacity value respectively. Growth in peak demand New unit costs

New England ISO Proposed Demand Curve: 

New England ISO Proposed Demand Curve The newly proposed capacity demand curves are intended to allow the markets to settle at a reliability level consistent with the willingness to pay for reliability. Maine, Connecticut, NEMA/Boston, Southwest Connecticut, and Rest-of-Pool NEPOOL have a proposed locational ICAP market with a demand curve price mechanism. This analysis included the use of demand curves in January 2006. The latest FERC decision to delay the implementation of LICAP until no earlier than October 1, 2006, came toward the end of this study. We do not believe this decision would have significant impact on the total avoided capacity payments. EBCC = Estimated Benchmark Capacity Cost C = Capacity OC = Objective Capability CMax = The Capacity at which price equals 2 * EBCC CTarget = Target long-run average capacity CK = Capacity at the kink in the demand curve d = Ck - OC

Peak Demand Growth Assumptions: 

Peak Demand Growth Assumptions Demand growth in New England has historically been below the national average growth level. The long-term growth rate (post 2014) in New England is roughly 1.5% annually. The U.S. average is approximately 2.5% per year. This study accounted for sub-regional differences in growth rates. Some of the faster growing zones include New Hampshire, Southwest Connecticut and Rhode Island. Some of the slower growing regions include Western Massachusetts and Norwalk. The New England RTEP study was used to derive regional growth expectations.

Technology Costs will Drive Both Capacity and Energy Value: 

Technology Costs will Drive Both Capacity and Energy Value

Technology Costs will Drive Both Capacity and Energy Value: 

Technology Costs will Drive Both Capacity and Energy Value Average New England capital costs start at over $800/kW (real 2005$) for combined cycles and cogeneration facilities, at roughly $564/kW (real 2005$) for combustion turbines and at roughly $1000/kW (real 2005$) for LM 6000s. These capital costs remain flat over the forecast period. Costs vary regionally within New England based on labor and site costs as well as temperature and altitude adjustments. In particular, costs are highest in Connecticut and Boston and lowest in Maine. The build mix will be determined through economics for units allowed. New coal facilities are not permitted in the New England marketplace.

Annual Wholesale Market Capacity Prices for Select Years By State (2005$/kW-yr): 

Annual Wholesale Market Capacity Prices for Select Years By State (2005$/kW-yr) Levelized at a 2.03 percent real discount rate.

Annual Realized Out of Market Cost for Select Years By State (2005$/kW-yr): 

Annual Realized Out of Market Cost for Select Years By State (2005$/kW-yr) Levelized at a 2.03 percent real discount rate. Rest of Pool out of Market Costs are distributed equally across the RTEP zones.

Annual Wholesale Capacity Value and Out-of-Market Costs Comprise the Avoided Capacity Value: 

Annual Wholesale Capacity Value and Out-of-Market Costs Comprise the Avoided Capacity Value As discussed earlier, the capacity price in this forecast is reflected under the locational ICAP zones as per the current LICAP proposal. These zonal prices (Maine, Boston, Southwest Connecticut, Rest of Connecticut, and Rest of Pool) have been aggregated to the state level for presentation purposes. This analysis projected that several units, despite receiving LICAP revenues, would not earn significant capacity compensation to allow those units to continue operation. ICF did not do a full determination of need assessment or voltage support / reliability; however, based on public information, ICF determined which of those margin units would be eligible for a cost-of-service recovery and included these costs in the avoided cost forecast as “out-of-market” costs. These units were located in primarily in Southwest Connecticut and Boston, and additionally in SEMA and Western Massachusetts. Note, only those units eligible for cost recovery were considered to have costs which could be avoided. The LICAP status has stalled somewhat since the inception of this project. Ultimately LICAP may take an alternate for to that proposed. However, as the all-in avoided cost forecast allows for cost-recovery for both new and existing units, it is reflective of the value one would expect under a competitive market design.

Costs of Serving Retail Load above the Wholesale Power Costs are not Considered as Avoidable: 

Costs of Serving Retail Load above the Wholesale Power Costs are not Considered as Avoidable In this analysis, other costs typically considered as the costs of serving load, are not considered avoidable. The full exclusion of these costs is conservative, however, it is expected that typical DSM savings programs will not result in significant reductions. Customer Account Expenses and Customer Service Expenses – it is anticipated that the number of customers will not be affected, rather the load per customer. Hence customer expenses are excluded. Sales Costs – Sales costs include advertising expenses were assumed not to change with reductions in peak demand. General Managerial and Administrative Expenses – G&A expenses include office supplies, insurance, franchise fees, pension and benefit costs, etc.. which are assumed not to change with reductions in peak demand. Line Maintenance Expense – Transmission and distribution line maintenance costs are assumed to include items such as vehicles, employee wages, and equipment such as line monitoring equipment. These costs are also considered to be independent of the avoidance of peak load for existing lines. Additional items such as stranded costs recovery and fixed costs or retail operations are not considered in the avoided costs presented although they would be considered in retail rates.

Massachusetts Retail Multiple - Task 3K: 

Massachusetts Retail Multiple - Task 3K Task 3k under the original AESC RFP included a calculation for the retail adder in Massachusetts. ICF utilized information reported on the EIA form 826 and the FERC Form 1 to estimate the retail adder for Massachusetts only. This resulted in an estimate of 1.7x the wholesale price.

Costing Periods Tasks 3e and 3f: 

Costing Periods Tasks 3e and 3f The costing periods used in this analysis varied slightly from the ICF recommendation. Instead the costing period used in the 2003 study was maintained as it was determined that the implementation barriers outweighed the slight variations between costing periods. The Costing periods used for this analysis are shown in the table to the left. ICF’s costing period recommendation analyzed 2005 forecast data. Historical data was also analyzed in reviewing costing period. A hour of the day was considered to be peak if more than 50 percent of the prices that occurred over for that hour of the day were greater than the annual mean. This resulted in slight deviations in hour type definitions than what was used for the analysis. To determine the seasonal characterization, ICF examined the monthly average prices and volatility across regions. While the summer months typically had lower average prices, they tended to have twice as much volatility as the winter months. ICF used this criteria to determine the seasonal characterization.

Electric Demand Reduction Induced Price Effects (DRIPE) Task 3L - Demand Savings Programs May Reflect Alternate Savings: 

Electric Demand Reduction Induced Price Effects (DRIPE) Task 3L - Demand Savings Programs May Reflect Alternate Savings Initially the DRIPE was considered under multiple scenarios examining alternate reductions (or increases) in the Reference Case load projection due to demand response. It was determined that the scenario most relevant to consider was a case with 0.75% peak load reduction. Peak capacity price shifts only were measured using this scenario. The levelized savings over multiple year periods are shown. Demand Today Supply Avoided cost $/MWh 2% Demand Savings 5% Demand Savings Load (MW)

Annual DRIPE for Select Years By State (2005$/kW-yr): 

Annual DRIPE for Select Years By State (2005$/kW-yr) Levelized at a 2.03 percent real discount rate.

Annual Alternative DRIPE for Select Years By State (2005$/kW-yr): 

Annual Alternative DRIPE for Select Years By State (2005$/kW-yr) The Alternate DRIPE scenario considers that demand reductions will only impact capacity traded in the spot markets. This is estimated to be approximately 10 percent of the capacity transactions based on historical activity in the ISO-NE ICAP market and activity in the NY-ISO existing LICAP market. Levelized at a 2.03 percent real discount rate.

Transmission and Distribution Avoided Capacity Cost Methodology Task 4: 

Transmission and Distribution Avoided Capacity Cost Methodology Task 4 The avoided cost is reflected in the savings associated with deferred T&D investment. $ ∑[Capex - Capex * (1 + esc) ∆n] * Capital Charge Rate = (1+d)n (1+d)n+∆n ICF has provided an adaptable spreadsheet methodology for determining transmission and distribution avoided costs.

Comparison of New England Retail Avoided Electricity Levelized Cost Estimates: 

Comparison of New England Retail Avoided Electricity Levelized Cost Estimates Notes: Levelized (annuity) values were calculated using a 2.03 percent discount rate as per the Massachusetts Regulatory Agency standard. Previous analysis inflated to 2005 dollars from 2004 dollars using a 2.25% annual inflation rate assumption. Retail Avoided Costs do not include Transmission and Distribution, note, the previous analysis included some costs in addition to wholesale market costs while the current analysis does not (the additional costs were the equivalent of a multiple of 1.23 above the wholesale costs for all of New England). DRIPE is not included in the values shown.

Comparison of New England Retail Avoided Electricity Levelized Cost Estimates Excluding Retail Adder: 

Comparison of New England Retail Avoided Electricity Levelized Cost Estimates Excluding Retail Adder Notes: Levelized (annuity) values were calculated using a 2.03 percent discount rate as per the Massachusetts Regulatory Agency standard. Previous analysis inflated to 2005 dollars from 2004 dollars using a 2.25% annual inflation rate assumption. Retail Avoided Costs do not include Transmission and Distribution or retail cost adder. DRIPE is not included in the values shown.

Comparison of New England Retail Avoided Electricity Cost Estimates: 

Comparison of New England Retail Avoided Electricity Cost Estimates Notes: Levelized (annuity) values were calculated using a 2.03 percent discount rate as per the Massachusetts Regulatory Agency standard. Previous analysis inflated to 2005 dollars from 2004 dollars using a 2.25% annual inflation rate assumption. Retail Avoided Costs do not include Transmission and Distribution, note, the previous analysis included some costs in addition to wholesale market costs while the current analysis does not (the additional costs were the equivalent of a multiple of 1.23 above the wholesale costs for all of New England). DRIPE is not included in the values shown.

Seasonal Comparison of New England Retail Avoided Electricity Cost Estimates: 

Seasonal Comparison of New England Retail Avoided Electricity Cost Estimates Notes: Levelized (annuity) values were calculated using a 2.03 percent discount rate as per the Massachusetts Regulatory Agency standard. Previous analysis inflated to 2005 dollars from 2004 dollars using a 2.25% annual inflation rate assumption. Retail Avoided Costs do not include Transmission and Distribution, note, the previous analysis included some costs in addition to wholesale market costs while the current analysis does not (the additional costs were the equivalent of a multiple of 1.23 above the wholesale costs for all of New England). DRIPE is not included in the values shown.

Why do the studies differ?: 

Why do the studies differ? Near-term energy market prices differ largely due to gas price assumptions. Capacity prices in the current analysis reflect the LICAP market design unlike the prior analysis. Retail cost items are not included as avoidable in the current analysis. The previous analysis considered some share of the costs as avoidable.

For More Information: 

For More Information Please Contact: Maria Scheller, Vice President 1.703.934.3372, mscheller@icfconsulting.com Leonard Crook, Vice President 1.703.934.3856, lcrook@icfconsulting.com Michael Mernick, Vice President 1.401.737.9881, mmernick@icfconsulting.com