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1 Illustrative Results Based on E3’s Avoided Cost Model Thursday, April 19, 2012 Marginal Generation Costs

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2 Portfolio Modification PG&E's 2011 GRC Phase 2 settlement, D , adopted December 15, 2011, calls for a workshop prior to May 1, 2012, to identify and discuss publicly available models and data bases covering generation marginal costs. PG&E’s marginal generation costs are for retail rate design and allocating revenue requirements among PG&E’s bundled electric customer classes to reflect cost causation and promote economic efficiency. Marginal generation costs are estimates of the changes in PG&E’s electric procurement costs caused by small changes in customers’ energy usage and peak demand and do not reflect PG&E’s actual electric procurement costs. Background

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3 Portfolio Modification Marginal Energy Cost (MEC) ¢/kWh. Average forecast hourly power price for northern California, January 1, 2014 through December 31, For five time of use (TOU) rate periods and three voltage levels. Marginal Generation Capacity Cost (MGCC) $/kW-year. Marginal generation resource’s residual capacity value—going-forward fixed costs minus market revenues—levelized over six year period, January 1, 2014 through December 31, For three voltage levels. Marginal Generation Costs Components

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4 Portfolio Modification Avoided cost model created by Energy and Environmental Economics Inc. (E3) for the CPUC. In response to Administrative Law Judge Farrar’s October 5, 2011 “Administrative Law Judge’s Ruling on Updates and Adjustments to Energy Efficiency Avoided Cost Inputs and Methodology” in Rulemaking R E3’s Distributed Electric Resources Avoided Cost Model, version 3.9: oidedCostModel_v3.9_2011%20v4b%20CA%20Avg.zip oidedCostModel_v3.9_2011%20v4b%20CA%20Avg.zip Public Source of Data and Calculation

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5 Portfolio Modification Marginal Cost Changes from 2011 GRC Phase 2 Data Source and Calculation Methodology Function 2011 GRC Phase 2 Methodology Methodology Based on E3 Modeling Marginal Energy Cost (MEC): Data Source Proprietary forward market price quotes and internal historical hourly price profile. Public forward market price quotes and CAISO historical hourly price profile from E3 Avoided Cost Model. Marginal Generation Capacity Cost (MGCC): Costing Methodology Using an internal model with an existing combined cycle unit for and a new combined cycle gas turbine for 2014 – Using E3 Avoided Cost Model beginning in 2014 with short- term capacity cost escalating up to long-run capacity cost in

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6 Portfolio Modification “For the period after the available forward market prices, the method interpolates between the last available NYMEX market price and the long-run energy market price.” “The long-run energy market price is used for the resource balance and all subsequent years.” “The annual long-run energy market price is set so that the [combined cycle gas turbine] CCGT’s energy market revenues plus the capacity market payment equal the fixed and variable costs of the CCGT...” “The long-run energy market price begins with the 2010 MRTU day- ahead market price escalated by the natural gas burner tip forecast. “ E3 Energy Price Forecast Methodology

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7 Portfolio Modification “…the annual energy avoided costs are converted to hourly values by multiplying the annual value by 8760 hourly market shapes.” “…the hourly shape is derived from day-ahead LMPs at load- aggregation points in northern and southern California obtained from the California ISO’s MRTU OASIS.” “…the hourly market prices are adjusted by the average daily gas price in California. The resulting hourly market heat rate curve is integrated into the avoided cost calculator, where, in combination with a monthly natural gas price forecast, it yields an hourly shape for wholesale market energy prices in California.” E3 Hourly Load Shape Methodology

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8 Portfolio Modification Marginal Energy Cost (MEC) E Price Ratios by Rate Period Relative to Summer Off-Peak Period TOU Rate PeriodJanFebMarAprMayJunJulAugSepOctNovDec2010 Summer Peak Summer Partial-Peak Summer Off- Peak Winter Partial-Peak Winter Off- Peak Summer Off-Peak price = $42.85/MWh and Annual Average price = $49.49/MWh

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9 Portfolio Modification Marginal Energy Cost (MEC) E Updated Price Ratios by Rate Period Using Same Methodology TOU Rate PeriodJanFebMarAprMayJunJulAugSepOctNovDec2011 Summer Peak Summer Partial-Peak Summer Off- Peak Winter Partial-Peak Winter Off- Peak Summer Off-Peak price = $42.30/MWh and Annual Average price = $49.49/MWh

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10 Portfolio Modification Start with PG&E’s DLAP Day-ahead LMP from CAISO Divide by average of PG&E Citygate and Socal Border natural gas price from ICE. Calculate average using methodology from MPR model. Before averaging PG&E Citygate and Socal Border prices, each is increased for a) gas distribution rate, b) municipal rate surcharge, c) gas transportation escalation rate, and c) gas hedging transaction cost. The resulting hourly market heat rates are divided by the annual average market heat rate to generate an hourly price shape. E3 Hourly Price Shape Methodology

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11 Portfolio Modification Marginal Energy Cost (MEC) For 2013 By Time of Use Rate Period and Voltage Level (¢/KWh) TOU Rate Period Transmission MEC (based on E3’s 2014 hourly market price forecast) Multiplied by Primary Distribution Energy Loss Factor Primary Distribution MEC Multiplied by Secondary Distribution Energy Loss Factor Secondary Distribution MEC Summer Peak 6.229x =6.346x =6.660 Summer Partial-Peak 5.493x =5.597x =5.874 Summer Off-Peak 4.285x =4.366x =4.582 Winter-Partial 5.472x =5.575x =5.851 Winter-Off 4.764x =4.853x =5.093

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12 Portfolio Modification T&D Loss Factors Energy Loss Factors Sources: Transmission Losses from May 14, 2010 "Transmission Loss Factors" Distribution losses from "Distribution Loss Values for the TO-8 Filing" Percent Loss Factor Energy Loss Factor Cumulative Loss Factor Meter to Generation Generation to Meter Location From Source Documents 1 / ( 1 - Percent Loss Factor ) Product of Loss Factors at each Level Inverse of Cumulative Loss Factors Generator Bus Bar0.000% Generation Tie0.185% High Voltage Transmission1.777% Low Voltage Transmission1.544% Primary Distribution Output1.847% Secondary Distribution4.715%

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13 Portfolio Modification “…in the resource balance year and beyond, the value of capacity will equal the fixed cost of a new CT less the net revenues that the CT would attain from the selling to the real-time energy and ancillary service markets.” “…prior to resource balance, the capacity value is interpolated from the resource adequacy value of $28.07/kW-yr in 2008 to the residual capacity value in the resource balance year.” For example, the 2014 value of $101.91/kW-yr is calculated with the formula: $ (2014 – 2008) * ($ $28.07) / (2017 – 2008) “E3 has set the resource balance year [of 2017] to reflect the recent Joint IOU July 1, 2011 filing in the LTPP proceeding (R track 1)…” The 2017 value is $138.83/kW-year. E3 Capacity Price Forecast Methodology Resource Balance Year

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14 Portfolio Modification “In each hour that it operates, the unit earns the difference between the market price and its operating costs.” “To determine the long-run value of capacity, the avoided cost model performs an hourly dispatch of a new CT to determine energy market net revenues. The CT’s net margin is calculated assuming that the unit dispatches at full capacity in each hour that the real-time price exceeds its operating cost (the sum of fuel costs and variable O&M) plus a bid adder of 10%.” “The dispatch uses the 2010 MRTU real-time market shape (not the day- ahead market shape), and adjusts for temperature performance degradation using average monthly 9am – 10pm temperatures…” E3 Capacity Price Forecast Methodology Energy Market Net Revenues, a.k.a. Gross Margin or Net Energy Benefit

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15 Portfolio Modification Combustion Turbine Cost In E3 Avoided Cost Model (2009$) Component UnitAmount Combustion Turbine (CT) Installed Cost$/kW$1, Effective Real Economic Carrying Charge%11.82% Annualized CT Installed Cost$/kW-year$ Fixed O&M$/kW-year$17.40 Insurance$/kW-year$8.03 Property Tax$/kW-year$10.16 Full CT Proxy Cost $/kW-year$ Source: E3 Avoided Cost Model, “CT Pro Forma" tab, cells J4:L12 and California Energy Commission Staff 2009 Final Report: “Comparative Cost of California Central Station Electricity Generation Technologies” CEC SD 2009 Market Price Referent resolution: E 4298

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16 Portfolio Modification Residual Capacity Value In Resource Balance Year (2017$) Component UnitAmount Full Combustion Turbine Proxy Cost (2009$)$/kW-year$ Escalation, 2% per year, 2009 to 2017multiplier1.17 Full Combustion Turbine Proxy Cost (2017$)$/kW-year$ Operating Cost$/kW-year$37.17 Real-Time Dispatch Revenue$/kW-year($113.88) Ancillary Services Revenue$/kW-year($8.65) Subtotal Residual Capacity Value $/kW-year$ Percentage Adjustment for Temperature-caused Degradation of Heat Rate Efficiency %92.6% Residual Capacity Value $/kW-year$ Source: E3 Avoided Cost Model, "Market Dynamics" tab, cells K188:K194

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17 Portfolio Modification Marginal Generation Capacity Cost (MGCC) Calculation of Levelized Cost over ($/kW-year) Year Residual Capacity Value 2014$ $ $ $ $ $ PG&E After-tax Weighted Average Cost of Capital 7.6% Net Present Value of six year sum $ MGCC, Levelized Cost for 6 years at 7.6% $ Source: E3 Avoided Cost Model, "Market Dynamics" tab, columns G through L, row 199

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18 Portfolio Modification Marginal Generation Capacity Cost (MGCC) Levelized For By Voltage Level ($/KW-year) Period Transmission MGCC (based on E3’s capacity forecast) Multiplied by Primary Distribution Demand Loss Factor Primary Distribution MGCC Multiplied by Secondary Distribution Demand Loss Factor Secondary Distribution MGCC Levelized Cost $125.53x =$129.21x =$136.95

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19 Portfolio Modification T&D Loss Factors Demand Loss Factors Sources: Transmission Losses from May 14, 2010 "Transmission Loss Factors" Distribution losses from "Distribution Loss Values for the TO-8 Filing" Percent Loss Factor Demand Loss Factor Cumulative Loss Factor Meter to Generation Generation to Meter Location From Source Documents 1 / ( 1 - Percent Loss Factor ) Product of Loss Factors at each Level Inverse of Cumulative Loss Factors Generator Bus Bar0.000% Generation Tie0.211% High Voltage Transmission2.061% Low Voltage Transmission1.946% Primary Distribution Output2.852% Secondary Distribution5.651%

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20 Portfolio Modification Summer is from May 1 through October 31 and Winter is from November 1 through April 30. The summer peak period is from noon to 6:00 p.m., Monday through Friday, except holidays; the summer partial-peak period is from 8:30 a.m. to noon and 6:00 p.m. to 9:30 p.m., Monday through Friday, except holidays; and, the summer off-peak period is 9:30 p.m. to 8:30 a.m., Monday through Friday, except holidays, and all day Saturday, Sunday and holidays. The winter partial-peak period is from 8:30 am to 9:30 p.m., Monday through Friday, except holidays; and, the winter off-peak period is 9:30 p.m. to 8:30 a.m., Monday through Friday, except holidays, and all day Saturday, Sunday and holidays. Holidays for rate making purposes are the legally observed dates for New Year’s Day, President’s Day, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving Day and Christmas Day. The three voltage levels are transmission (60 kilovolt (kV) and above); primary distribution (between 4 kV and 50 kV); and, secondary distribution (below 4 kV). TOU Rate Periods and Voltage Levels

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