Bob Graham-Queensland Government Owned Generators Comparative Study

12th Annual Queensland State Energy Outlook
Conference

Queensland Government-owned Generators
– A comparative study

18 September 2008

12TH ANNUAL QUEENSLAND STATE ENERGY OUTLOOK CONFERENCE

Acknowledgements
The author, Bob Graham, would like to acknowledge the assistance of Grethe Casson
of MMA, and several reviewers within MMA and in other corporations for their
comments.

Melbourne Office Brisbane Office Canberra Office
242 Ferrars Street GPO Box 2421 Tel: +61 2 6257 5423
South Melbourne Vic 3205 Brisbane Qld 4001
Tel: +61 3 9699 3977 Tel: +61 7 3100 8064
Fax: +61 3 9690 9881 Fax: +61 7 3100 8067

Email: mma@mmassociates.com.au ACN: 004 765 235
Website: www.mmassociates.com.au ABN: 33 579 847 254

, 18 September 2008 McLennan Magasanik Associates


TABLE OF CONTENTS
EXECUTIVE SUMMARY _________________________________________________________I

1 INTRODUCTION _________________________________________________________ 1

2 CS ENERGY ______________________________________________________________ 2

2.1 Current Portfolio _____________________________________________________ 2

2.2 Future Projects _______________________________________________________ 2

2.3 Historical financial performance________________________________________ 3

2.4 Market position ______________________________________________________ 3

2.5 Market access ________________________________________________________ 7

2.6 Fuel _______________________________________________________________ 13

2.7 Water supply _______________________________________________________ 14

2.8 Greenhouse Intensity ________________________________________________ 14

3 STANWELL _____________________________________________________________ 17

3.1 Current Portfolio ____________________________________________________ 17

3.2 Future Projects ______________________________________________________ 17

3.3 Historical financial performance_______________________________________ 18

3.4 Market position _____________________________________________________ 18

3.5 Market access _______________________________________________________ 19

3.6 Fuel _______________________________________________________________ 22

3.7 Water supply _______________________________________________________ 22


4 TARONG ENERGY ______________________________________________________ 24

4.1 Current Portfolio ____________________________________________________ 24

4.2 Future Projects ______________________________________________________ 24

4.3 Historical financial performance_______________________________________ 24

4.4 Market position _____________________________________________________ 24

4.5 Market access _______________________________________________________ 26

4.6 Fuel _______________________________________________________________ 29

4.7 Water supply _______________________________________________________ 29


5 CONCLUSIONS _________________________________________________________ 31

18 September 2008 i McLennan Magasanik Associates


LIST OF TABLES
Table 1-1 Government-owned generator plant ____________________________________ i

Table 2-1 CS Energy plant_____________________________________________________ 2

Table 2-2 Historical financial performance_______________________________________ 3

Table 2-3 Selected CS Energy coal suppliers ____________________________________ 13

Table 2-4 Greenhouse gas emissions factors for combustion of fuels ________________ 14

Table 2-5 Emissions intensity of CS Energy NEM plant___________________________ 15

Table 3-1 Stanwell plant _____________________________________________________ 17

Table 3-2 Emissions intensity of Stanwell plant__________________________________ 22

Table 4-1 Tarong Energy plant________________________________________________ 24

Table 4-2 Tarong power stations’ fuel supply options ____________________________ 29

Table 4-3 Emissions intensity of Tarong Energy plant ____________________________ 30

LIST OF FIGURES
Figure 1-1 Return on assets ____________________________________________________ ii

Figure 1-2 Return on equity ____________________________________________________ ii

Figure 1-3 Cost-based merit order curve _________________________________________iii

Figure 1-4 Cost-based merit order curve @ $20/tonne CO2-e ________________________iii

Figure 1-5 Cost-based merit order curve @ $50/tonne CO2-e ________________________ iv

Figure 1-6 Long term dispatch trends of major Queensland power stations ___________ iv

Figure 1-7 Generation-weighted pool price vs capacity factor _______________________ v

Figure 1-8 Location of major plant in transmission network_________________________ vi

Figure 1-9 Collinsville MLF (North Queensland) _________________________________ vii

Figure 1-10 Stanwell MLF (Central Queensland) __________________________________ vii

Figure 1-11 Swanbank B MLF (South-east Queensland) ____________________________viii

Figure 1-12 Tarong MLF (South-west Queensland) ________________________________viii

Figure 1-13 Greenhouse intensity 2007/08_________________________________________ ix

Figure 2-1 Cost-based merit order curve _________________________________________ 4

Figure 2-2 Typical weekly dispatch pattern of Callide B (from 20 Jan 2008)____________ 5

Figure 2-3 Typical weekly dispatch pattern of Callide Power Plant (from 23 Mar 2008) _ 5

18 September 2008 ii McLennan Magasanik Associates


Figure 2-4 Long term dispatch trends of major Queensland power stations ___________ 6

Figure 2-5 Generation-weighted pool price vs capacity factor _______________________ 6

Figure 2-6 CS Energy plant in transmission network _______________________________ 8

Figure 2-7 Collinsville MLF ____________________________________________________ 9

Figure 2-8 Callide B MLF _____________________________________________________ 10

Figure 2-9 Callide Power Plant MLF____________________________________________ 10

Figure 2-10 Swanbank B MLF __________________________________________________ 11

Figure 2-11 Swanbank E MLF __________________________________________________ 11

Figure 2-12 Kogan Creek MLF__________________________________________________ 12

Figure 2-13 Cost-based merit order curve @ $20/tonne CO2-e _______________________ 15

Figure 2-14 Cost-based merit order curve @ $50/tonne CO2-e _______________________ 16

Figure 3-1 Typical weekly dispatch pattern of Stanwell (from 17 Feb 2008)___________ 18

Figure 3-2 Typical weekly dispatch pattern of Gladstone (from 20 Jan 2008)__________ 19

Figure 3-3 Stanwell plant in transmission network _______________________________ 20

Figure 3-4 Stanwell MLF______________________________________________________ 21

Figure 3-5 Gladstone MLF ____________________________________________________ 21

Figure 4-1 Typical weekly dispatch pattern of Tarong (from 20 Jan 2008) ____________ 25

Figure 4-2 Typical weekly dispatch pattern of Tarong North (from 20 Jan 2008) ______ 25

Figure 4-3 Tarong Energy plant in transmission network __________________________ 26

Figure 4-4 Wivenhoe MLF ____________________________________________________ 27

Figure 4-5 Tarong MLF _______________________________________________________ 28

Figure 4-6 Tarong North MLF _________________________________________________ 28

18 September 2008 iii McLennan Magasanik Associates


EXECUTIVE SUMMARY

This report summarises key features of the Queensland Government-owned generators
with an emphasis on commercial and market aspects, including the plant dispatched
through Power Purchase Agreements.

Details of the plant are shown in Table 1-1.

Table 1-1 Government-owned generator plant
Market Fuel
CS Energy-controlled plant MW Share Region Fuel Ownership Fuel Supply
Callide B 700 Central Qld Coal 3rd party Conveyor 2km
50% Callide Power Plant 450 Central Qld Coal 3rd party Conveyor 2km
Kogan Creek 724 SW Qld Coal Own fuel Conveyor 4km
Collinsville PPA 187 North Qld Coal 3rd party Conveyor 1km
Swanbank B 480 SE Qld Coal 3rd party Truck/Rail 5-200km
Swanbank E 350 SE Qld Gas 3rd party Pipeline 500km
NEM Total 2,891 26%
Mica Creek 325 NW Qld Gas 3rd party Pipeline 700km
Total 3,216
Market Fuel
Stanwell-controlled plant MW Share Region Fuel Ownership Fuel Supply
Barron Gorge 60 North Qld Hydro 3rd party River
Gladstone PPA 1,680 Central Qld Coal 3rd party Rail 500km
Kareeya 88 North Qld Hydro River
Koombooloomba 7 North Qld Hydro River
Wivenhoe small hydro 5 SE Qld Hydro River
Mackay GT 34 North Qld Liquid 3rd party Truck 400km
Stanwell 1,440 Central Qld Coal 3rd party Rail 400km
Total 3,314 30%
Market Fuel
Tarong Energy-controlled plant MW Share Region Fuel Ownership Fuel Supply
Tarong 1,400 SW Qld Coal Own fuel 1-16 km Conveyor
Tarong North 50% PPA 443 SW Qld Coal Own fuel 1-16 km Conveyor
Wivenhoe 500 SE Qld PS Hydro Local
Total 2,343 21%

All are pursuing development projects, but CS Energy is considered most likely to lower
their carbon intensity in the near term.

Financial performance is summarised in Figure 1-1 and Figure 1-2 with the effects of the
drought on Tarong clearly shown.

, 18 September 2008 i McLennan Magasanik Associates


Figure 1-1 Return on assets

Return on assets

25%

20%

15%

10%

5%

0%
2004/05 2005/06 2006/07

-5%

CS Energy Stanwell Tarong Energy

Figure 1-2 Return on equity

Return on equity

25%

20%

15%

10%

5%

0%
2004/05 2005/06 2006/07

-5%


The market position based on publicly reported generating costs is shown in Figure 1-3,
which shows Tarong and Kogan Creek in strong base-load positions, with Stanwell
having significant pricing power.

, 18 September 2008 ii McLennan Magasanik Associates


Figure 1-3 Cost-based merit order curve

Queensland Thermal Merit Order including GEC, NGAC & MLF effects

$80

$70

Privately-controlled
$60

Ergon
$50
$/MWh sent out

$40

$30

Stanwell
$20
Tarong CS Energy
$10
Swanbank E

$-
- 2,000 4,000 6,000 8,000 10,000 12,000
Cumulative MW

Using a very approximate analysis, this curve would change as per Figure 1-4 and Figure
1-5 under two carbon price scenarios.

Figure 1-4 Cost-based merit order curve @ $20/tonne CO2-e

Queensland Thermal Merit Order including GEC, NGAC* & MLF effects
@$20/tonne CO2-e
*NGAC to be discontinued
$80

$70

$60

$50
LRMC NE CCGT SEQ
$/MWh sent out

CS Energy
$40
Privately-controlled Stanwell
$30
SRMC NE CCGT SEQ
Tarong
$20

Swanbank E
$10

$-
- 2,000 4,000 6,000 8,000 10,000 12,000
Cumulative MW

, 18 September 2008 iii McLennan Magasanik Associates



@$50/tonne CO2-e
$80

$70

Tarong
$60
LRMC NE CCGT SEQ

Stanwell
$50
$/MWh sent out

$40 CS Energy
SRMC NE CCGT SEQ

$30
Swanbank
E
$20

$10

$-
- 2,000 4,000 6,000 8,000 10,000 12,000
Cumulative MW

The long term capacity factors of Tarong and Gladstone have increased over time, while
Callide B has fallen as shown in Figure 1-6.

Figure 1-6 Long term dispatch trends of major Queensland power stations

Dispatch of major Queensland power stations
before and after the NEM
100%
Merit Order Dispatch prior to 1998 NEM from 1999 onwards
Tarong drought
effect not
included
90%
Tarong

80%

Callide B
Stanwell being
commissioned
CF

70%

Stanwell

60%

Gladstone

50%

40%
1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008
Financial Years

, 18 September 2008 iv McLennan Magasanik Associates


The generation-weighted pool price1 of major stations vs capacity factor for the last three
years is shown in Figure 1-7.

Figure 1-7 Generation-weighted pool price vs capacity factor

2005-06, 2006-07 and 2007-08 Financial Years

$60
Ave rage Price s
$55
$52.34 (2007-08)
Generator Weighted Average Price

$52.14 (2006-07)
$50

$45

$40

$35

$30
$28.12 (2005-06)

$25
30% 40% 50% 60% 70% 80% 90% 100%
Capacity Factor

Callide Pow er Plant Callide B Gladstone Stanw ell Tarong Tarong North A verage prices

While lower capacity factors may ideally be offset by higher pool prices, this trend is
really only seen in 2005/06. The drought and other forced outages have affected this
outcome.

As shown in Figure 1-8, from a network point of view, Barron Gorge, Kareeya and
Collinsville are well located in North Queensland, and Swanbank and Wivenhoe in south-
east Queensland.

1 This is similar to price received, except for the effects of parasitic load and MLF, which have not been applied.

, 18 September 2008 v McLennan Magasanik Associates


Figure 1-8 Location of major plant in transmission network

Barron Gorge
Kareeya

Collinsville

Stanwell
Callide B
Callide Power Gladstone

Tarong
Tarong North
Kogan Creek

Swanbank B & E

• Wivenhoe

, 18 September 2008 vi McLennan Magasanik Associates


Trends in selected but indicative marginal loss factors are shown in Figure 1-9 to Figure
1-12. Higher marginal loss factors show more favourable locations.

Figure 1-9 Collinsville MLF (North Queensland)

Collinsville PS MLF

1.100

1.050

MLF
1.000
Linear Trend

0.950

0.900
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009
Financial Year Ending June

Figure 1-10 Stanwell MLF (Central Queensland)

Stanwell PS MLF

1.100

1.050

MLF
1.000
Linear Trend

0.950

0.900
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

, 18 September 2008 vii McLennan Magasanik Associates


Figure 1-11 Swanbank B MLF (South-east Queensland)

Swanbank B PS MLF

1.100

1.050

MLF
1.000 Linear Trend

0.950

0.900
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

Figure 1-12 Tarong MLF (South-west Queensland)

Tarong PS MLF

1.1

1.05

1
MLF
Linear Trend

0.95

0.9
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

While south-west Queensland marginal loss factors are not too unfavourable, increasing
generation capacity in this area is likely to make future marginal loss factors somewhat
volatile.

, 18 September 2008 viii McLennan Magasanik Associates


By purchasing its own fuel supply, Tarong Energy has reduced its fuel supply risk and
dispatch risk to the lowest risk position compared to the other generators. Others have
partially implemented this strategy.

Stanwell is in the lowest risk position concerning water supply.

CS Energy has achieved the lowest greenhouse intensity thanks to its gas-fired generation
from Swanbank E, while Stanwell has had some benefit from its hydro plant. This does
not include any carbon off-sets.

Figure 1-13 Greenhouse intensity 2007/08

Portfolio Greenhouse Intensity

0.90

0.89

0.88

0.87
t CO2-e /MWh so

0.86

0.85

0.84

0.83

0.82

0.81

0.80

To sum up the commercial and market strengths of the three portfolios, CS Energy would
be the lowest risk, Stanwell the largest market position, and Tarong the lowest marginal
cost.

, 18 September 2008 ix McLennan Magasanik Associates


1 INTRODUCTION

This paper summarises key features of the Queensland Government-owned Corporations
whose primary business is power generation (GOGs). These organisations control 77% of
the generating capacity in the Queensland Region of the NEM. The focus is on
commercial and market aspects of the organisations rather than on engineering assets or
human resources. Plant which a GOG does not own, but has the right to dispatch through
a Power Purchase Agreement (PPA), are therefore included in its portfolio and this
analysis.

Information has been sourced from their web-sites1 and annual reports, unless referenced
otherwise. Any opinions and judgements are those of the author. The author has worked
extensively for NRG Energy Inc., the part-owner and operator of Gladstone power station,
as an employee and now as a consultant, and in the state-owned electricity industry
before that.

1 http://csenergy.com.au/ , http://www.stanwell.com/ , http://www.tarongenergy.com.au/

, 18 September 2008 1 McLennan Magasanik Associates


2 CS ENERGY

2.1 Current Portfolio
CS Energy has a widely dispersed portfolio of 3,216 MW of plant across Northern, Central
and Southern Queensland, providing a strong locational diversity for physical risks. It
has fuel diversity across coal and gas.

Characteristics of its plant are summarised in Table 2-1.

Table 2-1 CS Energy plant
Market Fuel
CS Energy-controlled plant MW Share Region Fuel Ownership Fuel Supply
Callide B 700 Central Qld Coal 3rd party Conveyor 2km
50% Callide Power Plant 450 Central Qld Coal 3rd party Conveyor 2km
Kogan Creek 724 SW Qld Coal Own fuel Conveyor 4km
Collinsville PPA 187 North Qld Coal 3rd party Conveyor 1km
Swanbank B 480 SE Qld Coal 3rd party Truck/Rail 5-200km
Swanbank E 350 SE Qld Gas 3rd party Pipeline 500km
NEM Total 2,891 26%
Mica Creek 325 NW Qld Gas 3rd party Pipeline 700km
Total 3,216

CS Energy trades the output of Collinsville into the NEM under a PPA which lasts until
20162.

2.2 Future Projects
In the past, CS Energy has successfully developed and constructed Kogan Creek power
station, the Swanbank E Combined Cycle Gas Turbine (CCGT) power station and the
Callide Power Project as part of a joint venture.

Currently it “is completing technical and economic feasibility work for Swanbank F”, another
CCGT unit. It has also executed a farm-in agreement with Metgasco3 for future gas
supplies from New South Wales.

In conjunction with AGL, CS Energy is reviewing expansion opportunities for Mica Creek.

From 2009, CS Energy intends to trial an oxy-firing demonstration plant at its de-
commissioned Callide A site. This is an option for increasing the concentration of CO2 in
power station waste gases to make it more cost-effective to extract, by burning the coal in
“a mixture of oxygen and recirculated flue gas” instead of air. There are many parties
involved as partners, and the project is partially federally funded. It is not public what
rights to any new intellectual property would accrue to CS Energy.

Both the Swanbank and Kogan Creek sites are understood to have the potential for further
greenfield expansion.

2 NRG Energy Inc. Annual Report 2000, www.NRGEnergy.com
3 http://www.csenergy.com.au/_cmsimages/csenergy/pdfs/2006/061213%20metgasco%20farmin.pdf

18 September 2008 2 McLennan Magasanik Associates


2.3 Historical financial performance
According to a study by the Productivity Commission4, CS Energy has made a return on
assets of 5.5% over three recent years, and a return on total equity of 11.9%. This equity
return was the highest of the three GOGs. Details are shown in Table 2-2.

Table 2-2 Historical financial performance
Return on assets
2004/05 2005/06 2006/07 Average
Qld Pool Price $ 28.96 $ 28.12 $ 52.14 $ 36.41
CS Energy 4.5% 5.2% 6.9% 5.5%
Stanwell 3.6% 7.6% 13.6% 8.3%
Tarong Energy 9.0% 7.3% -0.1% 5.4%
Average 5.7% 6.7% 6.8% 6.4%
Return on total equity
2004/05 2005/06 2006/07 Average
Qld Pool Price $ 28.96 $ 28.12 $ 52.14 $ 36.41
CS Energy 8.3% 8.1% 19.2% 11.9%
Stanwell 4.1% 8.4% 21.8% 11.4%
Tarong Energy 12.1% 9.7% 2.4% 8.1%
Average 8.2% 8.7% 14.5% 10.5%

2.4 Market position
CS Energy has some of the lowest variable cost plant in Queensland in Kogan Creek,
Callide B and 50% of the Callide Power Project. Other CS Energy plants are relatively
higher cost.

As seen in Figure 2-1, this results in CS Energy having plant spread intermittently across
the cost-based merit order curve.

4 Financial Performance of Government Trading Enterprises 2004–05 to 2006–07, July 2008,
http://www.pc.gov.au/__data/assets/pdf_file/0003/82227/gte-2006-07.pdf



Figure 2-1 Cost-based merit order curve

Queensland Thermal Merit Order including GEC, NGAC & MLF effects

$80

$70

$60

Ergon
$50
$/MWh sent out

$40

$30

Stanwell
$20
Tarong CS Energy
$10
Swanbank E

$-
- 2,000 4,000 6,000 8,000 10,000 12,000
Cumulative MW

The above costs are based on NEMMCO’s 2008 transmission planning assumptions5, and
are adjusted for transmission Marginal Loss Factors (MLF). These costs are used because
they are publicly available and have been consulted on. MMA has its own views on
generator costs which may differ in some cases from those above.

A typical week’s dispatch pattern for Callide B power station and the Callide Power Plant
are shown in Figure 2-2 and Figure 2-3.

5 2008 ANTS Consultation: Final Report, http://www.nemmco.com.au/psplanning/410-0099.pdf Table 46, adjusted for
MLF



Figure 2-2 Typical weekly dispatch pattern of Callide B (from 20 Jan 2008)

Callide B MW Generated
Price

700 $140

600 $120

500 $100

400

$/MWh
$80
MW

300 $60

200 $40

100 $20

- $-
1 49 97 145 193 241 289
Half-hours of the week starting Sunday

Figure 2-3 Typical weekly dispatch pattern of Callide Power Plant (from 23 Mar 2008)

Callide Pow Plant
er MW Generated
Price

900 $140

800 $120
700
$100
600

$/MWh
500 $80
MW

400 $60

300
$40
200
$20
100
- $-
1 49 97 145 193 241 289

Over the long term, Callide B has fallen from capacity factors in excess of 90% to closer to
80% in recent years, as shown in Figure 2-4.



Figure 2-4 Long term dispatch trends of major Queensland power stations

Dispatch of major Queensland power stations
before and after the NEM
100%
Merit Order Dispatch prior to 1998 NEM from 1999 onwards
Tarong drought
effect not
included
90%
Tarong

80%

Callide B
Stanwell being
commissioned
CF

70%

Stanwell

60%

Gladstone

50%

40%
1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008
Financial Years

The generation-weighted pool price6 of major stations vs capacity factor for the last three
years is shown in Figure 2-5.

Figure 2-5 Generation-weighted pool price vs capacity factor

2005-06, 2006-07 and 2007-08 Financial Years

$60
Ave rage Price s
$55
$52.34 (2007-08)
Generator Weighted Average Price

$52.14 (2006-07)
$50

$45

$40

$35

$30
$28.12 (2005-06)

$25
30% 40% 50% 60% 70% 80% 90% 100%
Capacity Factor

Callide Pow er Plant Callide B Gladstone Stanw ell Tarong Tarong North A verage prices

6 This is similar to pool price received, except for the effects of parasitic load and MLF, which have not been applied.



Three general observations can be made. Average prices were significantly higher in the
last two years, compared to before the drought. Kogan Creek’s generation has had the
effect of reducing the capacity factor of all other plant in 2007/08. If a generator can
choose the timing of its outages, for a given year, a lower capacity factor would be
expected to result in a higher generation-weighted price, which is most clearly seen in
2005/06. Forced outages and contract positions would affect this pattern.

Callide Power Plant recovered from a low dispatch year in 2005/06. While 2006/07 seems
more normal between these two plants, in 2007/08, Callide Power Plant had a lower
capacity factor and price than Callide B.

2.5 Market access

2.5.1 Location in network
The location of CS Energy’s plant in the Queensland transmission network is shown in
Figure 2-6, courtesy of Powerlink7. This flow diagram is of the summer of 2010/11 after
some years of load growth. Collinsville and Swanbank are well located in power
importing areas and are unlikely to be constrained down in their generation. The larger
Callide stations and Kogan Creek are less well located from a market access viewpoint.

7 Powerlink 2008 Annual Planning Report,
http://www.powerlink.com.au/data/portal/00005056/content/56727001214541091625.pdf



Figure 2-6 CS Energy plant in transmission network

Collinsville

Callide B
Callide Power

Kogan Creek

Swanbank B & E

•

2.5.2 Marginal loss factors
Transmission Marginal Loss Factors in the NEM affect the pool revenue of a power station
and its ability to trade contracts at the regional reference node. The more local supply
exceeds local demand, the lower the MLF will be and the lower the energy market
revenue available to the plant. Local supply includes local generation and imports by
transmission.

CS Energy has a widely varying exposure to this issue because of the varying location of
its NEM power stations in Queensland, Collinsville, Callide B, Callide C, Swanbank B and
E, and Kogan Creek.



2.5.3 North Queensland
Figure 2-7 shows the historical trend in MLF for its north Queensland power station,
Collinsville, as published by NEMMCO since 1998/99.

Figure 2-7 Collinsville MLF

Collinsville PS MLF

1.100

1.050

MLF
1.000
Linear Trend

0.950

0.900
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

Historically, this has generally been above 1.00 and quite favourable. However while
north Queensland’s load is growing strongly, more generation has also been locating
there, bringing MLFs down. Transmission reinforcement from central Queensland is also
lowering MLFs. However further reductions are considered less likely without a fuel
source for new high capacity factor plant.

2.5.4 Central Queensland
Figure 2-8 and Figure 2-9 show the historical trend in MLF for its central Queensland
power stations, Callide B and Callide Power Plant.



Figure 2-8 Callide B MLF

Callide B PS MLF

1.100

1.050

MLF
1.000
Linear Trend

0.950

0.900
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

Figure 2-9 Callide Power Plant MLF

Callide Power Plant MLF

1.100

1.050

MLF
1.000
Linear Trend

0.950

0.900
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

These values are low and trending worse. Given the ample coal reserves in Central
Queensland the long-term trend may remain unfavourable, but may also be mitigated by
the commissioning of new stations in South-West Queensland.



2.5.5 South-east Queensland
Figure 2-10 and Figure 2-11 show the historical trend in MLF for its south-east
Queensland power stations, Swanbank B and Swanbank E.

Figure 2-10 Swanbank B MLF

Swanbank B PS MLF

1.100

1.050

MLF
1.000 Linear Trend

0.950

0.900
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

Figure 2-11 Swanbank E MLF

Swanbank E PS MLF

1.100

1.050

MLF
1.000
Linear Trend

0.950

0.900
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009



These are stable, favourable values representing their relative proximity to Queensland’s
regional reference node at South Pine.

2.5.6 South-west Queensland
Figure 2-12 shows the recent MLFs for its new south-west Queensland power station,
Kogan Creek.

Figure 2-12 Kogan Creek MLF

Kogan Creek PS MLF

1.100

1.050

1.000 MLF

0.950

0.900
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

The MLF is currently not too unfavourable. In the future, a high volatility is considered
likely for MLFs in this region. For some future time periods, MLFs are likely to decrease
due to the following factors:

• The commissioning of Braemar 2 and Darling Downs power stations will further
increase power flows from south-west Queensland to the Brisbane region, reducing
these MLFs.
• Any further development of gas fired intermediate generation in south-west
Queensland would also reduce MLFs. While it is possible that intermediate gas fired
generation will be sited closer to Brisbane or in central Queensland, south-west
Queensland remains a favourable area for generation development.

There are also some factors which may cause MLFs to increase. These are:

• The augmentation of transmission capacity from Millmerran and Tarong to Brisbane
and the Gold Coast should reduce losses for a given power flow and provide some
MLF relief for a period until transmission flows build up to rated levels again.



• Any augmentation of the QNI capacity to increase power flows south may also
enhance the MLF for south-west Queensland as the power flow from Tarong to
Brisbane is reduced. This would also mitigate the impact of additional capacity built
in the Bulli Creek/Braemar area.

A likely future for this region is regular decreases in MLF with increasing generation,
relieved from time to time with increases resulting from augmented transmission
capacity, leading to a volatile future for south-west Queensland MLFs.

2.6 Fuel

2.6.1 Coal
Collinsville is supplied from an adjacent mine owned by Xstrata coal. Except for local
physical supply issues, this will ensure fuel supply security. The terms of Collinsville’s
PPA are not public concerning energy pricing or fuel pricing from the mine to Collinsville
power station.

The Callide stations are supplied with 5.8 – 6.0 million tpa8 from an adjacent mine owned
by Anglo Coal. Except for local physical supply issues, this also ensures fuel supply
security. The terms of the fuel pricing from the mine to the Callide power stations are not
public.

Swanbank B’s coal supply of approximately 1 million tpa is trucked “and railed from mines
in South-east Queensland, including Oakleigh, Jeebropilly and Acland.”

Kogan Creek power station is supplied with 2.8 million tpa from its adjacent mine also
owned by CS Energy. Except for local physical supply issues, this will ensure fuel supply
security, and relative security of fuel pricing.

Some details of CS Energy’s coal suppliers are shown in Table 2-3.

Table 2-3 Selected CS Energy coal suppliers9
Size Gross
(Measured Specific % Ash Fusion-
Distance Open cut Energy Moisture Deformation Hardgrove
(km) Delivery Ownership Thermal Mt) (MJ/kg ad) (ad) % Ash C Grindability
Callide Mine
Callide
Southern 2 Conveyor Anglo Coal 225 20.8 10.9 18.9 1,334 85
Kogan Creek mine
Raw coal 4 Conveyor CS Energy 310 21.1 8.4 26.6 1,320 40

Except for Kogan Creek CS Energy remains exposed to future long term volatility in coal
prices.

8 Terms of reference for an Environmental Impact Statement Boundary Hill Mine Extension Project, Part A,
http://www.epa.qld.gov.au/register/p02396aa
9 Coal specifications from Queensland Coals 2003



2.6.2 Gas
Swanbank E’s gas requirements of approximately 18 PJpa are initially being “supplied from
the Scotia gas field near Wandoan via the Roma to Brisbane Pipeline”. Other gas supply deals
have been done with Arrow Energy10 for the Kogan North field, Santos, QGC, BHPBilliton
and the Metgasco deal metioned in Section 2.2.

Mica Creek’s gas requirements of approximately 21 PJpa are “conveyed from the southwest
Queensland gas fields, via the Carpentaria gas pipeline”.

Except for any gas farm-in arrangements, CS Energy is exposed to future long term
volatility in gas prices.

2.7 Water supply
Swanbank power stations are supplied from Wivenhoe dam, the Warrill Scheme and
recycled water. The last option was developed in response to the recent drought, and has
been operational since August 200711. Wivenhoe supplies most of south-east
Queensland’s water. As a combined cycle plant, Swanbank E has a lower water usage
than conventional coal-fired plant.

The Callide stations are supplied from Awoonga dam. Awoonga dam has been affected
by drought previously.

Kogan Creek is supplied from local bores, and being dry-cooled has very low water usage.

2.8 Greenhouse Intensity

2.8.1 Greenhouse intensity of fuel burnt
The following emissions factors were used from the National Greenhouse and Energy
Reporting (Measurement) Technical Guidelines 2008 v1.012 published by the Department
of Climate Change.

Table 2-4 Greenhouse gas emissions factors for combustion of fuels

Combustion of fuels only kg Co2-e/GJ Reference

Method 1, All gases

Black coal 88.43 Table 2.2.2

Natural gas 51.33 Table 2.3.2

Diesel fuel 69.50 Table 2.4.2A

Emissions from production of fuels were not addressed, and hydro is assumed to produce
negligible emissions.

10 http://www.csenergy.com.au/_cmsimages/csenergy/pdfs/pre2005/0412csearrowrelease_001.pdf
11 http://www.westerncorridor.com.au/Media/media_releases/Purified_recycled_water_read_for_swanbank.pdf
12 http://www.climatechange.gov.au/reporting/guidelines/pubs/nger-technical-guidelines.pdf



2.8.2 Emissions from NEM power stations
The greenhouse intensity of CS Energy’s NEM power stations and portfolio was derived
for the 2007/08 year. The Heat Rates are based on NEMMCO’s 2008 transmission
planning assumptions13. These Heat Rates are used because they are publicly available
and have been consulted on. MMA has its own views on generator Heat Rates which may
differ in some cases from those below.

Table 2-5 Emissions intensity of CS Energy NEM plant
Emissions Heat Rate Emissions 2007/08
Intensity kg GJ/MWh Intensity t CO2- Capacity
CS Energy-controlled plant MW Fuel CO2-e/GJ so e/MWh so Factor
Callide B 700 Coal 88.43 9.97 0.882 75%
50% Callide Power Plant 450 Coal 88.43 9.23 0.816 72%
Kogan Creek 724 Coal 88.43 9.47 0.838 71%
Collinsville 187 Coal 88.43 13.00 1.149 47%
Swanbank B 480 Coal 88.43 11.50 1.017 49%
Swanbank E 350 Gas 51.33 7.06 0.362 63%
NEM Total 2,891 0.83

At 0.83 t CO2-e / MWh, the portfolio has the lowest intensity of any of the GOGs. This
ignores any carbon off-set activities, and will be even lower if Swanbank F proceeds.

Figure 2-13 shows the impact of a carbon cost of $20/t CO2-e on the cost-based merit order
curve. This is simply added to current costs and does not include considerations such as
the removal of NGACs, increasing gas and other costs, changes in Tarong’s marginal costs
and peak/off-peak roles.


@$20/tonne CO2-e
$80

$70

$60

$50
LRMC NE CCGT SEQ
$/MWh sent out

CS Energy
$40
Privately-controlled Stanwell
$30
SRMC NE CCGT SEQ
Tarong
$20

Swanbank E
$10

$-
- 2,000 4,000 6,000 8,000 10,000 12,000
Cumulative MW

13 2008 ANTS Consultation: Final Report, http://www.nemmco.com.au/psplanning/410-0099.pdf Table 46, Thermal
efficiencies converted to Heat Rates



As its costs rise less than other plant, Swanbank E’s position improves to third position.
The short-run marginal cost of a new entrant CCGT plant in South-east Queensland,
based on NEMMCO’s assumptions, is also shown. Such a new entrant plant would be
dispatched before most plant in Queensland at this carbon price.

For such a new entrant plant, NEMMCO assume fixed costs of $115 / kWpa. At a
conservatively assumed capacity factor of 60%, this translates to an additional $22/MWh
in fixed costs, and a long run marginal cost of $46/MWh. Most plants would still be
returning significant contributions to fixed costs in this scenario.

MMA has its own views on generator costs which may differ in some cases from those
above.

Figure 2-14 similarly shows the impact of a carbon cost of $50/t CO2-e on the cost-based
merit order curve.


@$50/tonne CO2-e
$80

$70

Tarong
$60
LRMC NE CCGT SEQ

Stanwell
$50
$/MWh sent out

$40 CS Energy
SRMC NE CCGT SEQ

$30
Swanbank
E
$20

$10

$-
- 2,000 4,000 6,000 8,000 10,000 12,000
Cumulative MW

Swanbank E moves to be the lowest cost thermal plant and only highly efficient coal-fired
plant would make any contributions to fixed costs from a long run marginal cost of
$57/MWh. Some plant may still be viable with reduced dispatch.

This is intended to be a simple illustration and detailed market modelling would provide
more useful analysis.



3 STANWELL

Stanwell has the largest portfolio of 3,314 MW in a widely dispersed portfolio of plant,
although its major plant is all located in Central Queensland. It has fuel diversity across
coal and hydro, although once again its major plant is all coal-fired. Since 2007 it controls
the dispatch of the Gladstone power station, which is owned by a consortium of private
owners including NRG Energy, Inc., Rio Tinto Alcan and several Japanese companies.
This power purchase agreement ends in 202914.


Table 3-1 Stanwell plant
Market Fuel
Stanwell-controlled plant MW Share Region Fuel Ownership Fuel Supply
Barron Gorge 60 North Qld Hydro 3rd party River
Gladstone PPA 1,680 Central Qld Coal 3rd party Rail 500km
Kareeya 88 North Qld Hydro River
Koombooloomba 7 North Qld Hydro River
Wivenhoe small hydro 5 SE Qld Hydro River
Mackay GT 34 North Qld Liquid 3rd party Truck 400km
Stanwell 1,440 Central Qld Coal 3rd party Rail 400km
Total 3,314 30%

3.2 Future Projects
In the past Stanwell has developed various renewable energy projects, which have since
been sold off. It also initiated the ZeroGen clean coal project, which was then sold to the
Queensland government, although Stanwell remains as a major service provider to the
project.

Stanwell are seeking to secure “access to a coal resource in the Central Queensland region for
the development (in conjunction with joint venture partners) of a new baseload power station.”

Stanwell has an “energy park” adjacent to the power station, where they wish to attract
customers for off-grid energy supply, steam and other utilities.

Its recent purchase of a stake in Blueenergy15, an oil and gas development company, is in
line with a stated initiative of pursuing gas-based opportunities.

The Stanwell site may offer some greenfield expansion potential.

14 1994 Australian Trade Practices Reporter, Comalco Limited and Comalco Aluminium Limited (1994) ATPR (Com) 50-142
s4.32
15 http://www.blueenergy.com.au/



According to the Productivity Commission study, Stanwell has made a return on assets of
8.3% over three recent years, and a return on total equity of 11.4%. This return on assets
was the highest of the three GOGs. Details are shown in Table 2-2.

3.4 Market position

3.4.1 Merit order cost curve
As seen in Figure 2-1, Stanwell controls the relatively high cost coal-fired plant in
Queensland in the Stanwell and Gladstone power stations. While this is not a low cost
base for a portfolio, the large combined capacity gives Stanwell significant control over
prices for a large section of the daily price curve.

3.4.2 Weekly Dispatch
A typical week’s dispatch pattern for Stanwell power station is shown in Figure 3-1.

Figure 3-1 Typical weekly dispatch pattern of Stanwell (from 17 Feb 2008)

Stanwell MW Generated
Price

1,400 $140

1,200 $120

1,000 $100

800

$/MWh
$80
MW

600 $60

400 $40

200 $20

- $-
1 49 97 145 193 241 289

A typical week’s dispatch pattern for Gladstone power station is shown in Figure 3-2.



Figure 3-2 Typical weekly dispatch pattern of Gladstone (from 20 Jan 2008)

Gladstone MW Generated
Price

$140
1,600
$120
1,400

1,200 $100

1,000

$/MWh
$80
MW

800
$60
600
$40
400
$20
200

- $-
1 49 97 145 193 241 289

3.4.3 Capacity Factors
Stanwell power station often had units in commissioning phases until the NEM was
introduced, but as shown in Figure 2-4 has maintained approximately 80% capacity factor
since.

The privately-owned Gladstone power station’s dispatch has been controlled by Enertrade
from 1994 until 2007, and by Stanwell since then. As seen in Figure 2-4, the introduction
of the NEM in 1998 has seen an increase in long term average dispatch from Gladstone
power station from the low 50% region to 60% since, while the average capacity factors of
the State-owned major generators have actually fallen slightly.

As shown in Figure 2-5, for each year, Gladstone has lower capacity factors and higher
prices than Stanwell.

3.5 Market access

The location of Stanwell’s major plant in the Queensland transmission network is shown
in Figure 3-3.



Figure 3-3 Stanwell plant in transmission network

Barron Gorge

Kareeya

Stanwell
Gladstone

Figure 3-4 and Figure 3-5 show the historical trend in MLF for Stanwell’s central
Queensland power stations, Stanwell and Gladstone.



Figure 3-4 Stanwell MLF

Stanwell PS MLF

1.100

1.050

MLF
1.000
Linear Trend

0.950

0.900
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

Figure 3-5 Gladstone MLF

Gladstone PS 275 kV MLF

1.100

1.050

MLF
1.000
Linear Trend

0.950

0.900
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

These values are low but stable. Further discussion of central Queensland MLFs is in
Section 2.5.4.



The north Queensland hydro stations have higher values but have a smaller revenue
impact than these two.

3.6 Fuel
Stanwell’s coal requirements of three to four million tpa are delivered by rail from several
mines in Central Queensland, including some ownership and on-sale arrangements.
Curragh North is often mentioned however other suppliers have not been outlined
recently. In 2003, suppliers were Blackwater, Burton, Cook, Curragh and Ensham16.

Gladstone’s coal requirements are similarly delivered by rail from several mines in
Central Queensland, but current details are not public. From the same source in 2003,
suppliers were Blackwater, Callide, Curragh, Ensham, Gregory-Crinum, Jellinbah East
and Rolleston.

Except for Curragh North and any other coal ownership arrangements, Stanwell remains
exposed to future long term volatility in coal prices.

3.7 Water supply
Gladstone’s cooling water supply is from the ocean, and process water is supplied from
Awoonga dam. Awoonga dam has been affected by drought previously, but a proposed
link to the Fitzroy river would improve this significantly.

Stanwell’s water supply is from a barrier on the Fitzroy river. Due to its large catchment,
the Fitzroy river represents a very secure water supply. Stanwell’s coal-fired stations
therefore have the most secure water supply of GOG coal-fired power stations.

The greenhouse intensity of Stanwell’s NEM power stations and portfolio was derived for
the 2007/08 year, although long term average capacity factors were used for
Koombooloomba and Wivenhoe small hydro.

Table 3-2 Emissions intensity of Stanwell plant
Stanwell-controlled plant MW Fuel CO2-e/GJ so e/MWh so Factor
Barron Gorge 60 Hydro 0 50%
Gladstone 1,680 Coal 88.43 10.23 0.904 57%
Kareeya 88 Hydro 0 64%
Koombooloomba 7 Hydro 0 27%
Wivenhoe small hydro 5 Hydro 0 30%
Mackay GT 34 Liquid 69.50 12.86 0.894 0%
Stanwell 1,440 Coal 88.43 9.89 0.875 77%
Total 3,314 0.85

At 0.85 t CO2-e / MWh, the portfolio benefits significantly from the hydro generation.
This ignores any carbon off-set activities.

16 The Queensland Coal Industry Review 2002-2003



As seen in Figure 2-13 and Figure 2-14, Stanwell’s major thermal plant still seem viable at
$20 /t CO2-e, but are very marginal at $50 /t CO2-e. The hydro plants experience a
windfall gain.



4 TARONG ENERGY

Tarong has a concentrated presence in southern Queensland with its major plant all on the
one site. This proved vulnerable in the recent drought. It has fuel diversity across coal
and hydro, although its major plant is all coal-fired and the hydro plant is pumped-
storage.


Table 4-1 Tarong Energy plant
Market Fuel
Tarong Energy-controlled plant MW Share Region Fuel Ownership Fuel Supply
Tarong 1,400 SW Qld Coal Own fuel 1-16 km Conveyor
Tarong North 50% PPA 443 SW Qld Coal Own fuel 1-16 km Conveyor
Wivenhoe 500 SE Qld PS Hydro Local
Total 2,343 21%

4.2 Future Projects
In the past, Tarong Energy has successfully developed the Tarong North project, and also
various renewable energy projects which have since been sold off. Recent business
development has concentrated on securing its fuel supply in purchasing the Meandu mine
and Kunioon deposit. Other future plans are not clear.

The Tarong site could offer greenfield expansion potential to a sixth unit.

According the Productivity Commission study, Tarong Energy has made a return on
assets of 5.4% over three recent years, and a return on total equity of 8.1%. These returns
were heavily adversely affected by the recent drought. Tarong Energy had the highest
returns of the three GOGs on both measures prior to the drought. Details are shown in
Table 2-2.

4.4 Market position
As seen in Figure 2-1, Tarong Energy has its thermal plant concentrated in a low cost
portion of the cost-based merit order curve. Wivenhoe is available for short term back-up
to the limit of its pumped storage capacity which is reportedly 10 hours17.

A typical week’s dispatch pattern for Tarong power station and the Tarong North power
station are shown in Figure 2-2 and Figure 2-3. Tarong’s capacity was effectively limited
by water restrictions to 700 MW during this time.

17 http://seqwater.com.au/content/standard.asp?name=WivenhoePowerStation



Figure 4-1 Typical weekly dispatch pattern of Tarong (from 20 Jan 2008)

Tarong MW Generated
Price

1,400 $140

1,200 $120

1,000 $100

800

$/MWh
$80
MW

600 $60

400 $40

200 $20

- $-
1 49 97 145 193 241 289

Figure 4-2 Typical weekly dispatch pattern of Tarong North (from 20 Jan 2008)

Tarong North MW Generated
Price

500 $140

450
$120
400
350 $100

300

$/MWh
$80
MW

250
$60
200
150 $40
100
$20
50
- $-
1 49 97 145 193 241 289

Excluding the effect of the drought, over the long term, Tarong has actually increased its
capacity factors to in excess of 90% in recent years, as shown in Figure 2-4.

As shown in Figure 2-5, this was seriously reversed for the last two years, with capacity
factors falling both years for both stations. In 2006/07 for Tarong, the generation-
weighted price was well below the year’s average price. This appears to be due to high



generation early in the year and reduced generation due to water restrictions during the
higher priced periods later in the year.

4.5 Market access

The location of Tarong Energy’s major plant in the Queensland transmission network is
shown in Figure 4-3.

Figure 4-3 Tarong Energy plant in transmission network

Tarong

Tarong North

Wivenhoe

Wivenhoe is well located in south-east Queensland, however the Tarong site in south-
west Queensland has previously been subject to constrained access to the node. Recent



transmission upgrades as well as the presence in the portfolio of Wivenhoe close to the
node, help to mitigate this risk.


4.5.2.1 South-east Queensland
Figure 4-4 shows the historical trend in MLF for Tarong Energy’s south-east Queensland
power station, Wivenhoe.

Figure 4-4 Wivenhoe MLF

Wivenhoe PS MLF

1.1

1.05

MLF
1
Linear Trend

0.95

0.9
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

These are stable, favourable values representing Wivenhoe’s relative proximity to
Queensland’s regional reference node at South Pine.

4.5.2.2 South-west Queensland
Figure 4-5 and Figure 4-6 show the historical trend in MLF for Tarong Energy’s south-
west Queensland power stations, Tarong and Tarong North.



Figure 4-5 Tarong MLF

Tarong PS MLF

1.1

1.05

1
MLF
Linear Trend

0.95

0.9
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

Figure 4-6 Tarong North MLF

Tarong North PS MLF

1.1

1.05

MLF
1
Linear Trend

0.95

0.9
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

These values are somewhat low but relatively stable. Further discussion of factors
affecting south-west Queensland MLFs is in Section 2.5.6.



4.6 Fuel
Tarong, and latterly Tarong North, have historically been supplied with 6.5 to 7.2 Mtpa18
of coal from the Meandu Creek mine previously owned by Rio Tinto Coal Australia. To
fuel both these power stations well into the future (“at least 20 years”), a new source of coal
was required.

Three sources were assessed over a long period and recently Tarong Energy chose to
purchase the existing Meandu Creek mine, and the Kunioon deposit from Rio Tinto Coal
Australia, and develop the Kunioon deposit for its new fuel source. Details of these and
the other two major contenders are detailed in Table 4-2.

Table 4-2 Tarong power stations’ fuel supply options19

Size Gross
(Measured Specific % Ash Fusion-
Distance Open cut Energy Moisture Deformation Hardgrove
(km) Delivery Ownership Thermal Mt) (MJ/kg ad) (ad) % Ash C Grindability
Previously
Meandu Rio Tinto
Creek now Tarong
(existing) 1 Conveyor Energy 364 21.1 5.5 30.1 1,485 53

Kunioon
(selected) Previously
(Specifi- Rio Tinto
cations New now Tarong
inferred) 16 conveyor Energy 214 19.30 35.0
New New
Acland 71 conveyor New Hope 242 28.90 3.7 13.0 1,572 40
Tarong
Glen Wilga 150 New rail Energy 132 25.60 5.6 14.8 1,387 35

This decision provides Tarong Energy with full control and pricing security over its fuel
supply in the long term. Ownership of the mines also reduces the stations’ marginal costs
to that required to extract and ship each tonne of coal, plus royalties. This will increase
dispatch, and the security of dispatch planning. Whether it proves a low cost strategy
depends on the price paid, coal available and further mine development and operating
costs.

4.7 Water supply
Tarong’s water supply is from the Boondooma and Wivenhoe dams, which have recently
been heavily affected by drought. Boondooma also supplies local graziers, and Wivenhoe
supplies most of south-east Queensland. Since June 2008, Tarong has received recycled
water from the Western Corridor Recycled Water Project20. The Wivenhoe power station
is also supplied by Wivenhoe dam.

18 Initial Advice Statement, Kunioon Project, April 2007
http://www.epa.qld.gov.au/publications/p02408aa.pdf/Initial_Advice_Statement_Kunioon_Project_/_Parsons_Brinc
kerhoff_Australia_Pty_Limited.pdf
19 Coal specifications from Queensland Coals 2003, except for Kunioon from Metallica Minerals website:

http://www.metallicaminerals.com.au/pdf/04_july_06_metallica_kingaroy_coal_resource_upgrade_asx_release.pdf
20 http://www.westerncorridor.com.au/Media/media_releases/DP_release_-_Water_to_Tarong.pdf



The greenhouse intensity of Tarong Energy’s power stations and portfolio was derived for
the 2007/08 year. Wivenhoe was assumed to use a weighted average supply from the
Tarong Energy thermal plant, and have an 80% energy efficiency in its
pumping/generation cycle.

Table 4-3 Emissions intensity of Tarong Energy plant

Tarong Energy-controlled plant MW Fuel CO2-e/GJ so e/MWh so Factor
Tarong 1,400 Coal 88.43 9.94 0.879 39%
Tarong North 443 Coal 88.43 9.11 0.806 72%
Wivenhoe 500 PS Hydro 1.065 3%
Total 2,343 0.86

At 0.86 t CO2-e / MWh, the portfolio has the highest emissions intensity of the GOGs.
This ignores any carbon off-set activities.

As seen in Figure 2-13 and Figure 2-14, Tarong Energy’s thermal plant still seem viable at
$20 /t CO2-e, but Tarong is very marginal at $50 /t CO2-e.



5 CONCLUSIONS

CS Energy has a diversified and lower risk portfolio of plant from all three perspectives of
physical location, fuel options and cost curve. It has partially secured its fuel risk, has
significant transmission risk exposure, but has the best portfolio and most proven
development capabilities for gas-fired generation. This will be valuable in a high carbon
cost environment.

Stanwell has the largest portfolio, but its portfolio is largely based on central Queensland
coal-fired generation. It has partially secured its fuel risk, but has significant transmission
risk exposure. It has proven development capabilities for renewable energy projects. In a
high carbon cost environment, these projects will become more economically viable.

Tarong Energy has a low marginal cost advantage but is largely concentrated on the one
site, and based on south-west Queensland coal-fired generation. It has secured its fuel
risk and dispatch risk but still has some transmission risk exposure. Its future strategy for
a high carbon cost environment is currently unclear.


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