Portfolio Modification

Report
1
Marginal Generation Costs
Illustrative Results Based on
E3’s Avoided Cost Model
Thursday, April 19, 2012
2
Background
 PG&E's 2011 GRC Phase 2 settlement, D.11-12-053, adopted December
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15, 2011, calls for a workshop prior to May 1, 2012, to identify
and
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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.
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Marginal Generation Costs Components
Marginal Energy Cost (MEC)
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 ¢/kWh.
 Average forecast hourly power price for northern California, January 1,
2014 through December 31, 2014.
 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, 2019.
 For three voltage levels.
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Public Source of Data and Calculation
 Avoided cost model created by Energy and Environmental Economics
Portfolio
Inc. (E3) for the CPUC.
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 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.09-11-014.
 E3’s Distributed Electric Resources Avoided Cost Model, version 3.9:
http://www.ethree.com/documents/E3%20Calculator%2009.20.11/DERAv
oidedCostModel_v3.9_2011%20v4b%20CA%20Avg.zip
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Marginal Cost Changes from 2011 GRC Phase 2
Data Source and Calculation Methodology
2011 GRC Phase 2
Methodology Based on E3
Methodology
Modeling
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Marginal Energy Cost Proprietary forward market price Public forward
market price
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(MEC):
quotes and internal historical
quotes and CAISO historical
hourly price profile.
hourly price profile from E3
Data Source
Avoided Cost Model.
Function
Marginal Generation
Capacity Cost
(MGCC):
Using an internal model with an
existing combined cycle unit for
2011-2013 and a new combined
cycle gas turbine for 2014 –
Costing Methodology
2016.
Using E3 Avoided Cost Model
beginning in 2014 with shortterm capacity cost escalating
up to long-run capacity cost in
2017-2018.
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E3 Energy Price Forecast Methodology
 “For the period after the available forward market prices, the method
interpolates between the last available NYMEX market price
and the
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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 dayahead market price escalated by the natural gas burner tip forecast. “
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E3 Hourly Load Shape Methodology
 “…the annual energy avoided costs are converted to hourly values by
multiplying the annual value by 8760 hourly market shapes.”
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 “…the hourly shape is derived from day-ahead LMPs at loadaggregation 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.”
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Marginal Energy Cost (MEC)
E3 2010 Price Ratios by Rate Period Relative to Summer Off-Peak Period
TOU Rate
Period
Jan
Feb
Mar
Apr
May Jun Jul Aug Sep Oct
Nov Dec 2010
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1.5
Summer
Peak
-
-
-
-
1.1
1.3
1.7
1.6
1.6
1.4
Summer
Partial-Peak
-
-
-
-
1.2
1.2
1.3
1.3
1.3
1.4
-
-
1.3
Summer OffPeak
-
-
-
-
1.0
0.7
1.0
1.1
1.1
1.2
-
-
1.0
Winter
Partial-Peak
1.3
1.3
1.4
1.3
-
-
-
-
-
-
1.3
1.2
1.3
Winter OffPeak
1.1
1.1
1.2
1.1
-
-
-
-
-
-
1.1
1.0
1.1
Summer Off-Peak price = $42.85/MWh and Annual Average price = $49.49/MWh
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Marginal Energy Cost (MEC)
E3 2011 Updated Price Ratios by Rate Period Using Same Methodology
TOU Rate
Period
Jan
Feb
Mar
Apr
May Jun Jul Aug Sep Oct
Nov Dec 2011
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1.5
Summer
Peak
-
-
-
-
1.1
1.4
1.7
1.8
1.7
1.6
Summer
Partial-Peak
-
-
-
-
1.1
1.2
1.3
1.4
1.4
1.6
-
-
1.3
Summer OffPeak
-
-
-
-
0.7
0.7
0.9
1.1
1.3
1.2
-
-
1.0
Winter
Partial-Peak
1.3
1.4
1.2
1.1
-
-
-
-
-
-
1.5
1.5
1.3
Winter OffPeak
1.1
1.1
0.9
0.8
-
-
-
-
-
-
1.3
1.3
1.1
Summer Off-Peak price = $42.30/MWh and Annual Average price = $49.49/MWh
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E3 Hourly Price Shape Methodology
 Start with PG&E’s DLAP Day-ahead LMP from CAISO
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 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.
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Marginal Energy Cost (MEC)
For 2013 By Time of Use Rate Period and Voltage Level (¢/KWh)
TOU Rate Period
Transmission Multiplied
MEC
by
(based on E3’s
Primary
2014 hourly Distribution
market price Energy Loss
forecast)
Factor
Primary
Distribution
MEC
Multiplied
by Portfolio
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Secondary
Distribution Secondary
Energy
Distribution
Loss Factor
MEC
Summer Peak
6.229
x 1.0188 =
6.346
x 1.0495 =
6.660
Summer Partial-Peak
5.493
x 1.0188 =
5.597
x 1.0495 =
5.874
Summer Off-Peak
4.285
x 1.0188 =
4.366
x 1.0495 =
4.582
Winter-Partial
5.472
x 1.0188 =
5.575
x 1.0495 =
5.851
Winter-Off
4.764
x 1.0188 =
4.853
x 1.0495 =
5.093
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T&D Loss Factors
Energy Loss Factors
Percent Loss
Energy Loss
Factor
Factor
Cumulative Loss Factor
Meter to
Location
From Source
1 / ( 1 - Percent
Documents
Loss Factor )
Portfolio
Generation to
Modification
Generation
Meter
Product of Loss
Inverse of
Factors at each
Cumulative Loss
Level
Factors
Generator Bus Bar
0.000%
1.0000
1.0000
1.0000
Generation Tie
0.185%
1.0019
1.0019
0.9982
High Voltage Transmission
1.777%
1.0181
1.0200
0.9804
Low Voltage Transmission
1.544%
1.0157
1.0360
0.9653
Primary Distribution Output
1.847%
1.0188
1.0555
0.9474
Secondary Distribution
4.715%
1.0495
1.1077
0.9028
Sources:
Transmission Losses from May 14, 2010 "Transmission Loss Factors"
Distribution losses from "Distribution Loss Values for the TO-8 Filing"
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E3 Capacity Price Forecast Methodology
Resource Balance Year
 “…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
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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:
$28.07 + (2014 – 2008) * ($138.83 - $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.10-05-006 track
1)…” The 2017 value is $138.83/kW-year.
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E3 Capacity Price Forecast Methodology
Energy Market Net Revenues, a.k.a. Gross Margin or Net Energy Benefit
 “In each hour that it operates, the unit earns the difference between the
market price and its operating costs.”
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
“To determine the long-run value of capacity, the avoided cost model
performs an hourly dispatch of a new CT to determine energy market net
revenues. The CT’s net margin is calculated assuming that the unit
dispatches at full capacity in each hour that the real-time price exceeds
its operating cost (the sum of fuel costs and variable O&M) plus a bid
adder of 10%.”
 “The dispatch uses the 2010 MRTU real-time market shape (not the dayahead market shape), and adjusts for temperature performance
degradation using average monthly 9am – 10pm temperatures…”
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Combustion Turbine Cost
In E3 Avoided Cost Model (2009$)
Component
Combustion Turbine (CT) Installed Cost
Unit
Amount
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$/kW
$1,230.36
%
11.82%
Annualized CT Installed Cost
$/kW-year
$145.42
Fixed O&M
$/kW-year
$17.40
Insurance
$/kW-year
$8.03
Property Tax
$/kW-year
$10.16
Full CT Proxy Cost
$/kW-year
$181.01
Effective Real Economic Carrying Charge
Source:
• E3 Avoided Cost Model, “CT Pro Forma" tab, cells J4:L12 and
• California Energy Commission Staff 2009 Final Report: “Comparative Cost of California Central Station
Electricity Generation Technologies” CEC-200-2009-017-SD
• 2009 Market Price Referent resolution: E 4298
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Residual Capacity Value
In Resource Balance Year (2017$)
Component
Full Combustion Turbine Proxy Cost (2009$)
Unit
Amount
$/kW-year
$181.01
multiplier
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1.17
Full Combustion Turbine Proxy Cost (2017$)
$/kW-year
$212.08
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
$126.73
%
92.6%
$/kW-year
$138.83
Escalation, 2% per year, 2009 to 2017
Percentage Adjustment for
Temperature-caused Degradation of Heat Rate Efficiency
Residual Capacity Value
Source:
E3 Avoided Cost Model, "Market Dynamics" tab, cells K188:K194
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Marginal Generation Capacity Cost (MGCC)
Calculation of Levelized Cost over 2013-2018 ($/kW-year)
Year
Residual
Capacity Value
2014
$101.91
2015
$114.22
2016
$126.52
2017
$138.83
2018
$140.42
2019
$142.09
PG&E After-tax Weighted
Average Cost of Capital
Net Present Value
of six year sum
MGCC, Levelized Cost for 6
years at 7.6%
7.6%
$587.41
$125.53
Source:
E3 Avoided Cost Model, "Market Dynamics" tab, columns G through L, row 199
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Marginal Generation Capacity Cost (MGCC)
Levelized For 2014-2019 By Voltage Level ($/KW-year)
Period
2014-2019
Levelized Cost
Transmission Multiplied
MGCC
by
(based on E3’s
Primary
2014-2019
Distribution
capacity
Demand
forecast)
Loss Factor
$125.53
x 1.0294 =
Primary
Distribution
MGCC
$129.21
Multiplied
by Portfolio
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Secondary
Distribution Secondary
Demand
Distribution
Loss Factor
MGCC
x 1.0599 =
$136.95
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T&D Loss Factors
Demand Loss Factors
Percent Loss
Demand Loss
Factor
Factor
Cumulative Loss Factor
Meter to
Location
From Source
1 / ( 1 - Percent
Documents
Loss Factor )
Portfolio
Generation to
Modification
Generation
Meter
Product of Loss
Inverse of
Factors at each
Cumulative Loss
Level
Factors
Generator Bus Bar
0.000%
1.0000
1.0000
1.0000
Generation Tie
0.211%
1.0021
1.0021
0.9979
High Voltage Transmission
2.061%
1.0210
1.0232
0.9773
Low Voltage Transmission
1.946%
1.0198
1.0435
0.9583
Primary Distribution Output
2.852%
1.0294
1.0741
0.9310
Secondary Distribution
5.651%
1.0599
1.1385
0.8784
Sources:
Transmission Losses from May 14, 2010 "Transmission Loss Factors"
Distribution losses from "Distribution Loss Values for the TO-8 Filing"
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TOU Rate Periods and Voltage Levels
 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
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8:30 a.m., Monday through Friday, except holidays, andModification
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).

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