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