avoided costs of energy in vermont due to energy efficiency programs developed by the aesc study...

Avoided Costs of Energy in Avoided Costs of Energy in Vermont Due to Energy Vermont Due to Energy

Efficiency ProgramsEfficiency Programs

Developed by theDeveloped by the

AESC Study GroupAESC Study Group

September 2005September 2005

OutlineOutline

• Purpose of the Report

• Background on Costs in New England– Key Natural Gas Issues– Key Electric Power Issues

• Natural Gas, Oil and Other Fuels Avoided Costs

• Electric Power Avoided Costs

• Comparison to Existing ACs in Screening Tool

Purpose of the AESCPurpose of the AESC

• Collaboration of New England States and Load Serving Entities LSEs– Avoided Costs for program design and regulatory filings.

• Electric• Gas• Other Fuels

– Including various end use sectors– Look at costing periods and make recommendations– Examine savings resulting from a lower clearing price for

remaining electric supply due to DSM (DRIPE)– Develop a T&D avoided cost methodology

Provide a basis for a Vermont filing per Docket 5980 MOU to update avoided costs used in DSM program and measure screening

Results and Anticipated Changes to Current Results and Anticipated Changes to Current Avoided CostsAvoided Costs

• Energy– Update avoided Energy costs– Revised price “bins” resulting from new costing periods– Revise savings “bins” to reflect new costing periods

• Capacity– Move from current Peak, shoulder and off peak avoided costs to

Summer peak and rest of year– Locational value set at LICAP. Reserves?

• Marginal Losses– Revise to reflect new energy bins

• Avoided T&D– Implement proposed methodology

• Environmental and Risk adders– No change proposed

• DRIPE– Evaluate

RESULTSRESULTS15 year Levelized3 (2006-2020)

Winter Peak

Winter

Off Peak

Summer Peak

Summer Off Peak

Summer

Capacity

Fall/Spring

Winter T&D

Screen tool 0.059 0.045 0.058 0.044 40.22 20.03 26.36

AESC 0.0646 0.0525 0.061 0.044 67.92

ProcessProcess

• RFP Developed by stakeholders• Numerous Stakeholder conference calls and

meetings– Agreement or compromise on key

assumptions for avoided costs– In depth explanation of inputs and results– Review of report by stakeholder group

• What does Vermont need?

New England Avoided Cost IssuesNew 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.– Four components (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.

Key Drivers of Gas Prices and Key Drivers of Gas Prices and Avoided CostAvoided 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 Surplus Production Capacity has Vanishedhas 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

Cap

acity

Util

izat

ion

(%)

Drilled Well Production Capacity

Actual Production History

Utilization of Well Capacity> 90% Utilization

Nom

inal

Wel

lhea

d P

rice

($/M

MB

tu)

$2

$4

$6

$8

$10

Source: Energy Information Administration

Six Bcf/d Proposed for Northeast LNGSix Bcf/d Proposed for Northeast LNG

1. Rabaska, Levis-Beaumont, QU: 0.5 Bcf/d (Gaz Métro, Gaz de France, Enbridge)

2. Gros Cacouna, QU: 0.5 Bcf/d (TransCanada, Petro-Canada)3. Canaport LNG, St. John, NB: 0.5 Bcf/d (Irving Oil, Repsol)4. Bear Head LNG, Point Tupper, NS: 0.75 to 1 Bcf/d (Anadarko)5. Goldboro, NS: (Keltic Petrochemicals)6. Pleasant Point, ME: 0.5 Bcf/d (Quoddy Bay LLC)7. Off Cape Ann, MA: 0.4 Bcf/d (Excelerate Energy)8. Somerset, MA: 0.65 Bcf/d (Somerset LNG)9. Weaver’s Cove LNG, Fall River, MA: 0.4 to 0.8 Bcf/d (Hess

LNG)10. KeySpan LNG, Providence, RI: 0.5 Bcf/d (KeySpan & BG LNG)11. Broadwater Energy, offshore Long Island, NY: 1 Bcf/d

(TransCanada and Shell US Gas & Power)12. 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

89

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

Basis Volatility at Hubs Feeding New England

-1.000

0.000

1.000

2.000

3.000

4.000

5.000

6.000

7.000

$/M

MB

tu

Daw n Chicago City Gate Waddington Niagara Tetco M3 TRANSCO Zone 6 NYC

Source: Gas Daily

Natural Gas Avoided Cost Natural Gas Avoided Cost MethodologyMethodology

• 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 Natural Gas Avoided Cost MethodologyMethodology

• Long Run Avoided Cost concept

– Assumes fixed costs can be avoided for decrements of demand

– Includes incremental fixed cost for avoided expansions

• 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 MethodologySteps 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 GasCost of Physical Gas• Gas forecast was developed 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 ForecastICF 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

Long Term Forecast Comparison: AESC Long Term Forecast Comparison: AESC Studies Compared to Annual Energy Studies Compared to Annual Energy

Outlook (EIA)Outlook (EIA)

ResultsResults• 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

Estimating Retail Avoided CostsEstimating 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

Vermont Wholesale Avoided Costs (2005$/MMBtu)

YearAnnual Avg.

3 Month Winter

9 Month Summer

5 Month Winter

7 Month Summer

6 Month Winter

6 Month Summer

7 Month Winter

5 Month Summer Peak Day

2005 9.66 11.26 7.34 9.95 7.30 9.61 7.28 9.29 7.24 247.01

2006 10.17 11.49 7.53 10.17 7.49 9.83 7.47 9.50 7.42 248.182007 9.81 10.20 6.45 8.93 6.42 8.61 6.40 8.30 6.36 247.352008 7.71 8.98 5.44 7.76 5.41 7.45 5.39 7.16 5.36 242.542009 6.68 8.47 5.01 7.27 4.98 6.97 4.97 6.69 4.94 240.172010 5.89 8.30 4.87 7.12 4.85 6.82 4.83 6.54 4.81 238.36

2011 5.95 8.38 4.93 7.19 4.91 6.88 4.89 6.60 4.87 238.512012 6.17 8.62 5.14 7.42 5.11 7.11 5.10 6.83 5.07 239.012013 6.37 8.85 5.33 7.64 5.30 7.33 5.28 7.04 5.25 239.482014 6.98 9.52 5.89 8.28 5.86 7.96 5.84 7.67 5.81 240.862015 6.55 9.04 5.49 7.82 5.46 7.51 5.44 7.22 5.41 239.87

2016 6.57 9.07 5.51 7.85 5.48 7.54 5.47 7.25 5.43 239.932017 6.54 9.03 5.48 7.82 5.46 7.51 5.44 7.22 5.41 239.862018 6.70 9.21 5.63 7.99 5.60 7.67 5.58 7.38 5.55 240.222019 6.89 9.42 5.81 8.19 5.78 7.88 5.76 7.58 5.73 240.662020 7.03 9.58 5.94 8.34 5.91 8.02 5.89 7.72 5.85 240.98

2021 7.34 9.93 6.23 8.67 6.20 8.35 6.18 8.05 6.14 241.702022 7.44 10.04 6.32 8.78 6.29 8.45 6.27 8.15 6.23 241.922023 7.82 10.45 6.67 9.18 6.63 8.85 6.61 8.54 6.57 242.782024 7.92 10.57 6.76 9.28 6.73 8.96 6.71 8.64 6.67 243.012025 8.42 11.13 7.23 9.83 7.20 9.49 7.17 9.17 7.13 244.17

Vermont Retail Avoided Cost (2005$/MMBtu)

Residential Commercial & Industrial

Year Existing Heating

New Heating

Hot Water

All Non Heating Heating All

All Retail

2005 11.50 11.42 11.32 11.41 10.29 10.38 10.34 10.93 2006 11.98 11.90 11.80 11.89 10.77 10.87 10.82 11.41 2007 11.64 11.56 11.46 11.55 10.43 10.52 10.48 11.07 2008 9.65 9.58 9.50 9.58 8.46 8.55 8.51 9.10 2009 8.67 8.60 8.53 8.60 7.49 7.57 7.53 8.12 2010 7.93 7.86 7.79 7.86 6.75 6.83 6.79 7.38 2011 7.99 7.92 7.85 7.92 6.81 6.89 6.85 7.44 2012 8.19 8.13 8.05 8.13 7.02 7.09 7.06 7.64 2013 8.39 8.32 8.24 8.32 7.21 7.29 7.25 7.84 2014 8.96 8.89 8.81 8.88 7.77 7.85 7.81 8.40 2015 8.55 8.48 8.41 8.48 7.37 7.45 7.41 8.00 2016 8.57 8.51 8.43 8.50 7.40 7.47 7.43 8.02 2017 8.55 8.48 8.40 8.48 7.37 7.44 7.41 7.99 2018 8.69 8.63 8.55 8.62 7.51 7.59 7.55 8.14 2019 8.88 8.81 8.73 8.80 7.70 7.77 7.73 8.32 2020 9.01 8.94 8.86 8.93 7.82 7.90 7.86 8.45 2021 9.30 9.23 9.15 9.23 8.12 8.20 8.16 8.75 2022 9.40 9.32 9.24 9.32 8.21 8.29 8.25 8.84 2023 9.75 9.68 9.59 9.67 8.56 8.64 8.60 9.19 2024 9.85 9.77 9.69 9.77 8.65 8.74 8.70 9.29 2025 10.32 10.25 10.16 10.25 9.13 9.22 9.17 9.76

2026-40 10.32 10.25 10.16 10.25 9.13 9.22 9.17 9.76

Levelized 2.03% 9.68 9.61 9.52 9.60 8.49 8.57 8.53 9.12

Comparison With Previous Study for 2010 – Wholesale

Avoided Cost

AESC 2003 AESC 2005 2010

South NE North/Central

NE South NE North/Central

NE Annual Average $5.15 $5.02 $5.90 $5.86 3 Month Winter $6.74 $6.49 $8.30 $7.75

9 Month Summer $4.33 $4.30 $4.87 $4.82 5 Month Winter $6.42 $6.16 $7.39 $7.03

7 Month Summer $4.23 $4.21 $4.86 $4.80 7 Month Winter $6.19 $5.95 $6.92 $6.64

5 Month Summer $4.09 $4.11 $4.82 $4.76

Other Fuels ForecastsOther 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

Katrina Impacts on Oil Were Small

Oil and Product Prices (National)Year

US Composite

RAC Oil Price

US Composite

RAC Oil Price

US Average (Base) No.2 Distillate

US Average (Base) No. 6 Resid <

1% S

U.S. Propane

(Consumer Grade)

Wholesale Price

U.S. Refiners Price of

Kerosene

$/bbl $/MMBtu $/MMBtu $/MMBtu $/MMBtu $/MMBtu

2005 45.60 7.86 9.39 7.25 9.39 9.89

2006 46.40 8.01 9.54 7.40 9.54 10.04 2007 44.40 7.65 9.19 7.05 9.19 9.68 2008 43.30 7.47 9.01 6.87 9.01 9.51 2009 44.50 7.67 9.21 7.07 9.21 9.71 2010 47.20 8.14 9.68 7.54 9.68 10.17

2011 45.50 7.84 9.38 7.24 9.38 9.88 2012 43.80 7.55 9.09 6.95 9.09 9.59 2013 42.10 7.26 8.80 6.66 8.80 9.29 2014 40.40 6.97 8.51 6.37 8.51 9.00 2015 38.60 6.66 8.20 6.06 8.20 8.69

2016 38.90 6.71 8.25 6.10 8.24 8.74 2017 39.60 6.83 8.37 6.23 8.37 8.86 2018 40.30 6.95 8.49 6.35 8.49 8.99 2019 41.00 7.07 8.61 6.47 8.61 9.11 2020 41.70 7.19 8.73 6.59 8.73 9.23

2021 42.40 7.32 8.85 6.71 8.85 9.35 2022 43.10 7.44 8.98 6.84 8.97 9.47 2023 43.80 7.56 9.10 6.96 9.10 9.59 2024 44.60 7.68 9.22 7.08 9.22 9.72 2025 45.30 7.80 9.34 7.20 9.34 9.84

Electric Power Avoided Electric Power Avoided CostsCosts

Key Drivers of Power Prices Key Drivers of Power Prices and Avoided Costand Avoided Cost

• Factors– Fossil fuel prices, particularly natural gas, – Transmission congestion – Environmental allowance

• Capacity value - – Supply-Demand balance.

– Congestion– Uncertain future structure of prices. – Pure capacity value in an equilibrium market is

reflective of the return on capital of the unit serving the marginal demand.

Basic Concept of the Price Basic Concept of the Price ForecastForecast

• The energy market tends toward equilibrium• In practice, the market never reaches equilibrium due to external

events (fuel prices, overbuild). • As load grows, more expensive peaking plants are dispatched

more frequently, thus increasing prices paid for energy • When prices are sufficiently high for a new entrant to construct a

plant and earn a return on an investment, that investment will occur

• Long term prices will tend to converge to the total (variable plus fixed) cost of a new unit

• The future is rarely, if ever, what we think it will be.

Components of Avoided CostComponents of Avoided Cost• Energy• Capacity (LICAP?? plus reserve)• Out of Market Costs• DRIPE• Losses• Avoided T&D• Externalities• Risk adjustmentComponents in blue were addressed in this study

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

Year CT MA ME NH RI VT

2005 0.071 0.065 0.063 0.064 0.065 0.068

2006 0.084 0.076 0.073 0.074 0.076 0.078

2007 0.089 0.081 0.077 0.079 0.081 0.082

2008 0.073 0.069 0.065 0.068 0.069 0.070

2009 0.060 0.057 0.053 0.055 0.057 0.058

2012 0.058 0.057 0.055 0.056 0.057 0.057

2016 0.065 0.065 0.062 0.064 0.064 0.065

2020 0.082 0.081 0.078 0.080 0.081 0.082

2030 0.113 0.113 0.109 0.112 0.113 0.114

2040 0.142 0.141 0.138 0.139 0.140 0.142

Levelized 2005-2040

0.084 0.082 0.079 0.081 0.082 0.083

Levelized 2006-2010

0.074 0.068 0.065 0.067 0.069 0.070

Levelized 2006-2020

0.069 0.067 0.063 0.065 0.066 0.067

Levelized at a 4.33 percent nominal discount rate.

Annual Capacity Avoided Costs for Select Years Annual Capacity Avoided Costs for Select Years

By State (nominal$/kW-yrBy State (nominal$/kW-yr))Year CT MA ME NH RI VT

2005 20.332 6.637 0.000 3.616 3.616 3.616

2006 53.419 41.841 23.828 37.167 37.167 37.167

2007 56.941 47.128 21.089 43.161 43.161 43.161

2008 72.253 67.485 20.805 66.958 66.958 66.958

2009 78.723 73.779 19.561 73.196 73.196 73.196

2012 94.002 89.689 78.070 88.926 88.926 88.926

2016 101.645 103.106 87.151 98.594 98.594 98.594

2020 106.659 109.111 82.231 105.089 105.089 105.089

2030 136.067 138.733 133.371 137.432 137.432 137.432

2040 78.633 80.200 77.822 79.437 79.437 79.437

Levelized 2005-2040

93.349 91.551 71.348 89.130 89.130 89.130

Levelized 2006-2010

68.277 60.943 23.159 58.768 58.768 58.768

Levelized 2006-2020

86.543 83.158 56.339 80.560 80.560 80.560

Levelized at a 4.33 percent nominal discount rate.

Wholesale Energy Prices Wholesale Energy Prices Reflect Market FundamentalsReflect 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 Load Growth Assumptions are a Key Driver of Potential Avoided Costsof 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.

ParameterNew

England Boston

Rest of Connectic

ut SWCTRest of

Pool Maine

2005 Weather Normalized Net Energy Load (GWh) 126,495 25,139 16,080 16,148 57,182 11,947

Annual Energy Growth

2005-2006 AAGR 2.0 2.0 2.0 2.1 2.0 1.8

2007-2010 AAGR 1.5 1.5 1.5 1.6 1.6 1.4

2011-2020 AAGR 1.5 1.5 1.5 1.6 1.5 1.3

2021 – forward AAGR 1.6 1.5 1.5 1.7 1.6 1.4

Source: ISO-NE Capacity, Energy Loads and Transmission (CELT) Report April 2005 adjusted to reflect load prior to savings from incremental demand side savings programs.

• Considered all 13 RTEP sub-regions as individual zones.

• Transmission flows between regions were input endogenously.

• Considered future transmission developments in the New England region. – including 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 Transmission Constraints Also Play a Key RolePlay a Key Role

• NOx caps – begin in 2009 and tighten in 2015.

• SO2, (similar to NOx), – controlled under the CAIR rule affecting most

eastern states.

• The Clean Air Mercury Rule – National tradable tonnage cap for Mercury at 38

tons in 2010 and reducing to 15 tons in 2018.

Future Air Emission Regulations were also Future Air Emission Regulations were also ConsideredConsidered

• A northeast regional CO2 program was considered to be in place as a precursor to the national program. (RGGI)

• Renewable market assumptions – normalized to reflect state requirements for

new renewable generation.

Future Air Emission Regulations were also Future Air Emission Regulations were also ConsideredConsidered

New Unit Performance and Operating Costs will Affect Future Energy Prices

On-line YearCombined

Cycle CogenCombustion Turbine LM 6000

2010 6,800 6,144 10,547 9,265

2015 6,672 5,976 10,321 9,066

2020 6,553 5,813 10,100 8,872

2025 6,447 5,653 10,100 8,719

2030 6,342 5,653 10,100 8,719

• 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.

Annual Wholesale Energy Annual Wholesale Energy Prices By StatePrices By State

• Very closely tied to the gas price forecast.

• Near-term prices – very strongly tied to the gas price forecast. – New unit efficiency and environmental policies only play a role in the mid to

long-term – On a zonal level, in the near-term, energy prices are higher in the import

constrained regions of Norwalk, Southwest Connecticut and Boston.

– Overall, prices tend to be higher in zones west of the East/West constraint.

Wholesale Capacity Prices Also Wholesale Capacity Prices Also Reflect Market FundamentalsReflect 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.

• Growth in peak demand• New unit costs

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

Year

Initial Forecast Revised ForecastPercent Change

Gas Price (2005$/ mmbtu)

Implied Heat Rate

(btu/kWh)Energy Price (2005$ /MWh)

Gas Price (2005$/ mmbtu)

Energy Price (2005$ /MWh)

Gas and Energy Price

2005 6.89 8,259 56.9 7.88 65.1 14%

2006 6.50 8,935 58.1 8.33 74.5 28%

2007 5.38 9,645 51.8 8.02 77.3 49%

2008 4.44 10,489 46.6 6.16 64.7 39%

2009 4.39 9,904 43.5 5.25 52.0 20%

2010 4.55 9,926 45.2 4.55 45.2 0%

Levelized 2006-2010

5.07 NA 49.2 6.50 63.1 28%

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

ValueValue• The capacity price in this forecast is reflected under the locational ICAP

zones as per the current LICAP proposal.

• The analysis projected that several units, despite receiving LICAP revenues, would not earn significant capacity compensation to allow those units to continue operation. 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.

• The LICAP status has stalled somewhat since the inception of this project.. However, it is reflective of the value one would expect under a competitive market design.

Costing PeriodsCosting Periods• 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.

States Season Peak Period

CT Summer – June through September; Winter – All other months

7 a.m. to 10 p.m. weekdays

All other states

Summer – June through August; Winter – All other months

7 a.m. to 10 p.m. weekdays

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

Year CT MA ME NH RI VTLevelized 2005-2040

185.6 245.8 134.9 320.0 320.0 320.0

Levelized 2006-2010

219.2 446.3 450.2 595.6 595.6 595.6

Levelized 2006-2015

236.2 315.2 237.1 424.6 424.6 424.6

Levelized 2006-2020

249.9 308.4 166.5 416.9 416.9 416.9

Levelized at a 2.03 percent real discount rate.

Using Avoided Costs from:

Current VT 2005 AESC % Difference

Commercial Lighting Measure

Measure Life 5

Full load hours 4000

Coincidence Factor 70%

For 1 kWh:

NPV Energy Avoided Costs $0.20 $0.27 31%

NPV Capacity Avoided Costs $0.06 $0.05 -16%

NPV of Total Avoided Cost $0.26 $0.31 20%

Levelized Total Avoided Costs $0.06 $0.08 20%

Measure Life 10



For 1 kWh:


NPV Capacity Avoided Costs $0.10 $0.10 -2%



Measure Life 15



For 1 kWh:


NPV Capacity Avoided Costs $0.13 $0.13 3%



Using Avoided Costs from:

Current VT 2005 AESC % Difference

Commercial Cooling Measure

Measure Life 5



For 1 kWh:





Measure Life 10



For 1 kWh:





Measure Life 15



For 1 kWh:





Transmission and Distribution Avoided Capacity Cost Methodology

• The avoided cost is reflected in the savings associated with deferred T&D investment.

Change in Load (kW)

$ ∑[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.

Additional Tasks to Prepare Additional Tasks to Prepare Avoided Costs for UseAvoided Costs for Use

• Recharacterize Measures into Revised Costing Bins

• Recompute Seasonal Marginal Losses to reflect Revised Bins

• Input Vermont Data into Avoided T&D Spreadsheet

• Decide on DRIPE

• Prepare a Filing for the Board

• The End

avoided costs of energy in vermont due to energy efficiency programs developed by the aesc study...

Documents

peak avoided costs

avoided costs of energy

energy costs

components gas costs

electric gas

costs electric power

prices new supply

costs comparison