1 cpuc avoided cost workshop generation avoided costs
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1
CPUC Avoided Cost Workshop
Generation Avoided Costs
2
Organization of Presentation
Goals and Recommended Approach Discussion of Comments Input Data Vs. Methodology Scenarios and Stress Cases
3
Goals for the Avoided Cost Methodology Disaggregate information by area and time to
facilitate detailed analyses where appropriate Use publicly available data, or information that
can be easily provided by utilities Transparent method Easily updated
4
Forecasts: How Often Are They “Correct”?Historical and Projected Natural Gas Price
Averaged over Delivery Month
0
2
4
6
8
10
12
Jul-1
996
Jul-1
998
Jul-2
000
Jul-2
002
Jul-2
004
Jul-2
006
Jul-2
008
Jul-2
010
Jul-2
012
Jul-2
014
Jul-2
016
Jul-2
018
Jul-2
020
Jul-2
022
No
min
al $
/MM
Btu
PG&E Citygate SoCal Gas
Henry Hub Spot NYMEX
EIA CEC
Data SourcesData Sources
5
Generation Avoided Cost Comments
“Thin markets are not accurate” “Forward prices do not reflect full capacity
value - Hedge value” “Use of CCGT misstates avoided cost in high
usage and low-usage periods” Market price referents
“Separate electric capacity and energy avoided costs are needed”
Source of generation cost inputs
6
Generation Marginal Cost Forecast Working Group Framework
2004 2006 2008 2023
Electric Forward data
Gas Futures data
Long Run Marginal Cost (CCGT)
Market Data(Short Term)
Long Run Proxy(Long Term)
7
Short-Term Forecast Example
Megawatt Daily sample of long-term forward data for on-peak delivery ($/MWh for August 22, 2003)
Average annual prices derived from on-peak quotes Use 1999 PX data for
on-peak to off-peak ratio
Data SourcesData Sources
WESTSep Oct Q4 Q1 04 Q2 04 Q3 04 Cal 2004 Cal 2005 Cal 2006
Mid-C 43.75 43.25 45.75 46.00 31.00 46.00 41.75 40.75 40.60Palo Verde 50.75 47.00 45.50 47.00 44.75 58.00 49.20 48.35 48.10NP15 52.00 51.50 52.00 53.50 48.00 62.25 53.80 52.85 52.50SP15 54.50 53.00 53.50 54.00 51.50 64.75 55.25 54.50 54.20
$44.5
$45.0
$45.5
$46.0
$46.5
2004 2005 2006
Year
$/M
Wh
Annual Average Pricesfor NP15
8
$30
$35
$40
$45
$50
2004 2005 2006 2007 2008
4.04.14.24.34.44.54.64.74.84.95.0
Annual Avg Power Price (NP15) Annual Avg NYMEX Gas Futures
NYMEX Gas Futures Extend Forwards through 2008
$/MWh $/mmbtuElectric forwards data
Natural gas futures data
9
Recommendation on Market Forwards
“Thin markets are not accurate”
“Forward prices do not reflect full capacity value - Hedge value”
10
Liquidity of Forward Market Data
Electricity Forwards: Platts does not include volume data. Likely illiquid, especially for 2006. Intercontinental Exchange (ICE) is another potential source.
Gas Futures: NYMEX data indicate good liquidity in the near 24-36 delivery months, less so in the subsequent months
Gas Basis Swaps: No basis swap volume data published, likely illiquid, especially for later months
Illiquidity does not necessarily imply a systematic bias in the data (higher or lower than avoided cost)
It is possible that illiquid markets can be manipulated
11
Comparison of Platts (broker quotes) and NYMEX
Contact NYMEX NP15 Platts NP15 NYMEX Mid-C Platts Mid-CJul-04 64.75 65.50 53.25 54.50Aug-04 70.00 70.25 59.50 59.50Sep-04 67.00 66.75 58.75 58.50
Q4 62.88 63.25 55.75 56.50
Contract NYMEX SP15 Platts SP15 NYMEX PV Platts PVJul-04 66.80 67.50 61.25Aug-04 73.50 66.50Sep-04 69.75 61.25
Q4 64.00 64.25 56.25 57.25
The comparison shows that forward market prices do not differ significantly by market (NYMEX futures vs. Platts bilateral).
12
Possible alternatives to reliance on illiquid forward markets1) Utilities provide their own forward price curves2) Average forward prices over several days or
multiple sources rather than relying on a single source and day
3) Econometric electricity price forecast: NYMEX gas with electricity spot price regression
4) Use NYMEX gas with monthly heat rate assumption5) Use forecast from CEC or a production simulation
model6) Ignore forward markets and move directly to
resource balance year
With the exception of 1) and 2), it is not clear these alternatives provide a better outcome than E3’s proposed methodology
13
Full Capacity and Hedge Value in The Market Data Forward contracts are firm delivery at a set
price, so no additional hedge value is required.
The forward price contains the market valuation of the capacity needed to ensure firm delivery of the contracted energy. No additional capacity value is required.
14
Generation Cost Level: LRMC
Long Run Marginal Costs (LRMC) used for marginal costs beyond the resource balance year in the forecast.
The LRMC estimate would be based on the cost to own and operate a combined cycle gas fired generator located in the California Control Area.
LRMC sets the annual average costs, and the historical market is used for the shape.
LRMC data source We recommend that the forecast use publicly available
input from the CEC, EIA and possibly EPRI.
Data and Data and ApproachApproach
15
LRMC Proxy Cost Is a gas fired CCGT a reasonable proxy for the long term marginal cost of electricity in CA?
Reviewed over 350 plant descriptions from NWPPC, WECC and CEC for plants built in last 3 years and in process of being built over next 5 years. Several conclusions can be drawn from this data:
1. Most capacity that has come on line or is planned is from gas fired generation: 73% in US; 90% in NWPPC area; 84% in WECC area; and 98% in California.
2. Combined Cycle (CCGT) plants are the dominant technology: 89% of NWPPC area gas fired plants; 94% of planned gas fired plants in WECC area; 87% of the gas fired plants constructed in the last 3 years or planned in California.
3. Combustion Turbines (CT) comprise of 5% of the NWPPC area gas fired generator market. In the WECC area, of the gas fired plants that had their technology specified 3% of the plants planned were CTs. In California, CTs comprise of 13% of the gas fired plants.
16
LRMC- Different Plant Specifications(Data was produced in June, 2002)
Construction Cost
($/kW-yr)
Other Fixed Cost
($/kW-yr)
Total Fixed Cost
($/kW-yr)
Fuel Cost ($/MWh)
Variable O&M & Offset costs
($/MWh)
Total Variable Cost
($/MWh) EIA CT 60.68 11.14 71.82 49.69 1.23 50.93 EIA CCGT 85.80 23.23 109.03 33.27 1.72 34.98 EIA Advanced CT 84.73 15.72 100.45 39.39 1.23 40.62 EIA Advanced CCGT 110.78 23.43 134.21 30.00 1.72 31.72 EPRI CT 63.37 7.73 71.10 50.27 13.29 63.56 EPRI CCGT 81.21 10.98 92.19 31.65 3.73 35.39 EPRI Advanced CT 62.87 8.94 71.81 44.40 12.83 57.23 EPRI Advanced CCGT 83.71 12.94 96.66 30.82 3.62 34.44 CEC CT 66.19 11.31 77.50 40.61 5.68 46.29 CEC CCGT 86.92 24.30 111.22 29.69 3.97 33.66
$-
$100
$200
$300
$400
$500
$600
- 2,000 4,000 6,000 8,000
Hours of Operation
An
nu
al C
ost
of
Ow
ners
hip
an
d
Ope
rati
on
(pe
r kW
of
capa
city
)
EIA CT
EIA CCGT
2,334 hours
-
1,000
2,000
3,000
4,000
5,000
6,000
7,000
0 2000 4000 6000 8000
Hour of the Year
Pe
ak
Lo
ad
(M
W) 2004MW of CT
2334 hours
CC
GT
Data shows significant differences in costs and performance by plant type
Data SourcesData Sources
17
LRMC Example Using EIA, EPRI and CEC estimates of CT and CCGT Costs
LRMC Levelized Cost ($/MWh Year 2003 $’s)
EIA Conventional $55.80 EIA Advanced $57.84 EPRI Conventional $53.99 EPRI Advanced $53.68 CEC $55.10
Low Cost --- using low forecasts across all major variables.
Lowest Cost Technology using
Futures Prices
High Cost Technology using
Futures Prices
High Cost --- using high forecasts across
all major variables Debt Cost 8.00% 9.00% 9.00% 10.00% Equity Cost 11% 13.9% 13.9% 16.8% Financing years 30 25 25 20 Natural Gas Forecast
CEC Forecast NYMEX NYMEX NYMEX, plus 3% inflation
Plant Cost and Operating Pattern
Lowest Cost (not restricted to pairs)
Lowest cost pair Highest cost pair Highest cost pair
LRMC Cost ($/MWh)
$48.57 $53.68 $57.84 $62.93
The levelized cost is fairly close if we use a common set of input assumptions
What really drives the LRMC are the gas and financing forecasting assumptions
Data SourcesData Sources
18
Hourly Shape: Historical Market Data Timeline
Marketopen
04/98 04/00
Normal times:Relatively stableand low prices
06/0101/01
Electricity crisis: hot summer, gas price spike, emission cost spikes; dry hydro; capacity shortage; rolling blackouts; capped prices
PXclose
DWR
01/03
UDCs resumeprocurementfor small RNS
Used for Price Shape
Data SourcesData Sources
19
Example NP15 Shape
1
5
9
13
17
21
1 2 3 4 5 6 7 8 9 10 11 12
0.00
10.00
20.00
30.00
40.00
50.00
60.00
70.00
Hours
MonthsHour
Ave
rag
e o
f H
ou
rly
Val
ues
by
Mo
nth
Price Duration Curve
0
20
40
60
80
100
120
140
160
1
484
967
1450
1933
2416
2899
3382
3865
4348
4831
5314
5797
6280
6763
7246
7729
8212
8695
Hours
NP
15 M
arke
t P
rice
Sh
ape
20
Capacity Separation
“Separate electric capacity and energy avoided costs are needed”
21
Example of Capacity Separation
Integral of the light blue area is the capacity cost.
0.00
20.00
40.00
60.00
80.00
100.00
120.00
140.00
1
251
501
751
1001
1251
1501
1751
2001
2251
2501
2751
3001
3251
3501
3751
4001
4251
4501
4751
5001
5251
5501
5751
6001
6251
6501
6751
7001
7251
7501
7751
8001
8251
8501
8751
Hours
$/M
Wh
CT Energy Margin
CT Operating Costs
NP15 2005 Market Prices
Average CEC Variable Cost
827 Hours of CT Operation
22
Market Price Referents
“Use of CCGT misstates avoided cost in high usage and low-usage periods”
23
Hourly Costs Already Reflect Market Prices for Various Generator Types Generators that operate few hours (like peakers) will have
relatively high average market prices. Baseload plants will have relatively low average market prices,
as they will be operating when marginal costs are lowest,.
0.00
20.00
40.00
60.00
80.00
100.00
120.00
140.00
1
251
501
751
1001
1251
1501
1751
2001
2251
2501
2751
3001
3251
3501
3751
4001
4251
4501
4751
5001
5251
5501
5751
6001
6251
6501
6751
7001
7251
7501
7751
8001
8251
8501
8751
Hours
$/M
Wh
CT Energy Margin
CT Operating Costs
NP15 2005 Market Prices
Average CEC Variable Cost
827 Hours of CT Operation
Peaker Average
Baseload Average
24
Peakers are not getting the capital cost of a CCGT unit Under LRMC, CCGT’s recover the full capital
cost of their plant IF they: have a heat rate of 7100 BTU/kWh operate at 91.6% capacity factor
Peaker units have higher heat rates, so their margin when they operate is lower --- so less capital recovery.
Peaker units would also operate far fewer hours, so there would be even less margin to cover return on and of the capital
25
Scenarios and Stress Cases
May be Suitable for DR and Dispatchable DG or Rate Programs
262004 2005 2006 2007 2008 2009 2010 2023
High Gas Price/High Growth ScenarioScenario- Higher growth pushes the resource balance yearto 2007, the transition to LRMC begins at 2006 and we have 75th percentile gas prices until 2010 and base case LRMC after.
Resource Balance Year Long Run Marginal Cost (CCGT)
LRMC withHigh Gas
LRMC withBase Case Gas
ScenariosScenarios
Electric Forward
data from Platts
Transition to LRMC
27
Stress Case Model
28
Using the Model to Create Scenarios
29
Example of program evaluation
Avoided cost values for a range of alternative scenarios for a dispatchable program with fewer than 4 hours per dispatch and 50 dispatches per year.
PG&E climate zone 12, weighted average of planning divisions
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