Embed Size (px)
Citation preview
PARLIAMENT OF VICTORIA
NATURAL RESOURCES AND ENVIRONMENT COMMITTEE
No.95
REPORT UPON
ELECTRICITY SUPPLY AND DEMAND
BEYOND THE MID-1990'S
Ordered to be Printed
APRIL 1988
NATURAL RESOURCES AND ENVIRONMENT COMMITTEE
MEMBERSHIP
The Honourable N.B. Reid, M.L.C. (Chairman)
The Honourable B.T. Pullen, M.L.C. (Deputy Chairman)
Mrs. J.M. Hill, M.P.
The Honourable R. Lawson, M.L.C.
The Honourable L.A. McArthur, M.L.C.
Mr. M.J. McDonald, M.P.
Mr. J.F. McGrath, M.P.
Mr. W.D. McGrath, M.P.
The Honourable B.W. Mier, M.L.C.
Mr. E.M.P. Tanner, M.P.
The Honourable C.F. V an Buren, M.L.C.
Dr. R.J.H. Wells, M.P.
Mr. M.R. Knight
Miss V. Velickovic
Mr. A.G. O'Neil
Ms E. Roadley
Mr. P. Garlick
Mr.B.NewelJ
Miss D. Kowalski
COMMITTEE STAFF
Director of Research
Secretary
Research Officer
Research Officer (to end of October 1987)
Consultant
Consultant (October, November 1987)
Word Processor Operator (to end February 1988)
*******
iii
OVERALL TERMS OF REFERENCE
PARLIAMENTARY COMMITTEES ACT 1968
4C. The functions of the Natural Resources and Environment Committee shall be to inquire into, consider and report to the Parliament on -
(a) any proposal, matter or thing concerned with the natural resources of the State;
(b) how the natural resources of the State may be conserved;
(c) any proposal, matter or thing concerned with the environment;
(d) how the quality of the environment may be protected and improved; and
(e) any works or proposed works reasonably capable of having significant effect upon the resources of the State or the environment--
where the Committee is required or permitted so to do by or under this Act.
* * *
V
CONTENTS OF THE REPORT
CHAPTER Page
I. Introduction 1
1.1 Terms of Reference
1.2 Request for Additional Information 2
1.3 Amended Reporting Date 2
1.4 Public Consultation Prior to this Inquiry 3
1 • .5 The Inquiry Programme and Public Consultation 3
1.6 Use of Consultants 6
1.7 Format of the Report 6
1.8 Differences from the Preliminary Report and Draft Recommendations 7
2. Balancing Electricity Supply and Demand 9
2.1 Introduction 9
2.2 Demand Forecast 9
2.3 Existing Generating Capacity 13
2.4 Planned Availability and Retirement of Generating Capacity 13
2 • .5 Additional Supply Capacity Prior to the Mid-1990's 14
2.6 Plant Mix 1.5
2.7 Balancing Supply and Demand 1.5
3. Pricing, Demand Side Measures and Energy Conservation 19
3.1 Introduction 19
3.2 Pricing 19
3.3 Demand Side Measures and Energy Conservation 20
3.4 Assessment of Demand Side Measures and Energy Conservation 23
3 • .5 Integrated Planning 24
3.6 The Greenhouse Effect 24
3.7 Specific Recommendations 2.5
vi
CHAPTER Page
•• The Performance of Existing Generating Plant and the Development of Improved Plant for the Future 27
4.1 Introduction 27
4.2 Plant Availability 27 4.3 Extending Plant Lifetimes 29 4.4 Research and Development into Electricity
Generation from Brown Coal 32
4.4.1 Boiler Plant 33 4.4.2 Coal Winning Techniques 36 4.4.3 Predpitators and Ash Handling Plant 36 4.4.4 New Coal Preparation or Combustion
Technologies 36 4.5 Specific Recommendations 38
,5. Large Scaie Supply Options 41
5.1 Introduction 41
5.2 Overview of Options 42
5.3 Location of Options 46
5.4 Status of Evidence on Options 46 5.5 Option Costs and Workforces 51 5.6 ReliabHity and Energy Efficiency Options 60 5.7 Environmental Impacts Common to Large Scale
Power Supply Options 61 5.8 Environmental Impacts of Individual Options 63 5.9 Preliminary Discussion of Options 67
5.10 Cost of Delivered Power from Selected Options 71
.5.11 Conclusions 71 5.12 Specific Recommendations 73
vii
CHAPTER Page
6. Small Scale Supply Options 75 6.1 Introduction 75 6.2 Roles for Small Scale Supply Options 75
6.3 Small Scale Options and Technologies 76 6.4 Supply Planning and Small Scale Options 80 6.5 Specific Recommendations 81
7. Modelling and Analysis of Supply Sequence Impacts 83 7.1 Introduction 83 7.2 Scenario Modelling 83 7.3 Scenario Modelling Outputs and Analysis 86 7.4 Influence of Assumptions 89
7.5 Comparison of Results 90
7.6 SECV Debt Level 93
7.7 Discount Rates 95
7.8 Comments on Scenario Modelling 95
7.9 Conclusion 99
a. Loy Yang 8 Units 3 &.: 4 101
8.1 Introduction 101
8.2 Construction and Approval Lead Time 101
8.3 Earliest Required Service Date 102 8.4 Economics of Sequences with Loy Yang 8
Units 3 & 4 first 102
8.5 Capital and Operating Costs 103
8.6 Coal Supply for Loy Yang Power Stations 103
8.7 Latrobe Valley Interests 104
8.8 Other Socio-economic Effects 104
8.9 Overall Economic Uncertainty 105
8.10 Conclusions 105
8.ll Specific Recommendations 105
viii
CHAPTER Page
9. Oaklands 107
9.1 Introduction 107
9.2 Costs and Benefits 108
9.3 Infrastructure 110
9.4 Potential for Arrangements with NSW 112
9.5 Specific Recommendations 113
10. Natural Gas 115
10.1 Gas Fired Options 115
10.1.1 Introduction 115
10.1.2 Potential Economic and Financial Benefits 116
1 0.1.3 Planning Flexibility Benefits 122
10.2 Natural Gas Resources 123
10.2.1 Introduction 123
10.2.2 Gippsland Basin Reserves 124
10.2.3 Impact of Additional Gas Fired Generating Capacity on Gippsland Basin Reserves 125
10.2.4 Allocating Natural Gas Resources 125
10.2.5 Deliverability of Natural Gas 128
10.2.6 Long Term Supply of and Demand for Natural Gas 129
10.3 Specific Recommendations .)(;
131
11. The Next Brown Coal Station to Follow Loy Yang B Units 3 &: 4 133
11.1 Options 133
11.1.1 Loy Yang "C" 133
11.1.2 Driffield 133
11.1.3 Morwell 134
11.1.4 Yallourn 134
11.1.5 The Briquette Factory 135
ix
CHAPTER Page
11.2 Estimated Costs 136
11.3 Timing/Sequencing 136
11.4 Further Strategic Review and Planning and Environmental Approval Processes 138
11.5 Specific Recommendations 139
12. Interstate Electricity Transfers and Planning 141
12.1 Introduction 141 12.2 The Three-State South Eastern Electricity Grid 141
12.3 The Economics of Interstate Electricity Transfer -Zeidler Re-examined 145
12.4 Opportunities for Interstate Transfer of Electricity 149
12.4.1 Base/Intermediate Load Transfer 149
12.4.2 Peak Load Transfers 150
12.4.3 Interconnection with Tasmania 151
12.5 Mechanisms for Interstate Electricity Transfer and Planning 151
12.6 The Snowy Scheme 153 12.7 Specific Recommendations 157
13. Alternative Power Supply Sequences 159
13.1 Introduction 159
13.2 General Conclusions 159
13.3 Overall Evaluation of Sequences 161
13.4 Balancing Financial and Social Costs 162
13.5 Latrobe Valley Economy 164
13.6 Assumptions 166
13.7 Degree of Certainty in Relation to Major Supply Options 167
13.8 Conclusions Reached by the Committee 168
13.9 Specific Recommendations 171
X
CHAPTER Page
14. Electricity Development Strategy Beyond the Mid-1990's 173
14.1 Introduction 17 3
14.2 An Electricity Development Strategy 173
14.3 Overall Objective 174
14.4 Strategic Principles 174
14.5 Key Elements 17 5
14.6 Relationship to Existing Strategies 176
14.7 Implementing the Electricity Development Strategy 178
14.8 Reviewing the Strategy and its Implementation 180
14.9 Principal Recommendations 181
* * *
xi
LIST OF APPENDICES
APPENDIX NO.
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
Key Reference Documents
Inquiry Programme
List of Witnesses
List of those who made Submissions to the Inquiry
Classification of Demand Side Measures and Summary of SECV Programme
SECV letter: System Value of Extending the Life of Hazelwood Power Station to 40 Years
Cost of Production Indices for Future Power Supply Options
Victorian Government Policy -The Use of Natural Gas for Power Generation
Natural Gas Resources
Description of Base Scenarios -Five Families of SECV Sequences
Basis for Comparison of Zeidler Inquiry and NREC Inquiry Generation Cost Estimates
Recommendations of the Commission of Inquiry into Electricity Generation Planning in NSW (McDoneU Inquiry) Concerning the Snowy Scheme
SECV letter: Brown/BlackCoal/Gas Scenario with Minimum Fluctuations in Latrobe Valley Construction Employment
Electricity Development Strategy and Implementation Review - Draft Format
Summary of Changes made in this Report from the Committee's Preliminary Report and Draft Recommendations of December 1987
Glossary of Terms
Energy and Power Units
List of Abbreviations
Extracts from the Proceedings
* * *
xii
Page
183
189
191
201
205
211
217
227 229
249
251
253
255
261
263
271
275
277
279
FIGURE NO.
2.1
2.2
5.1
5.2
5.3
5.4
7.1
10.1
10.2
12.1
A9.1
A9.2
A9.3
A9.4
A9.5
LIST OF FIGURES
Total Electricity Generation Forecasts for the Victorian System 19&7-2002 (SECV)
Comparison of Demand Forecasts and Range of Supply Capability of Existing and Committed Plant (35 & 40 year life at Hazelwood Power Station)
Location of Power Supply Options in Victoria
Location of Power Supply Options in the Latrobe Valley
Location of Possible Sites for Power Stations based on Oaklands Coal
Cost of Power Delivered to Melbourne versus Capacity Factor for Representative Options
Simplified Diagram of Scenario Modelling Approach
Bass Strait Gas Delivered to Major Customers 1981/1982- 1986/1987
Long-run Marginal Costs for Gas Turbine/Brown Coal Sequences - SECV Results
Three-State Interconnected Electricity Supply System
Movements in Gas Reserve Estimates 1978-1987
Victorian Daily Gas Usage- 1981
GFCV Projection of Delivery Requirements
Australian Natural Gas Reserves - BHP
Natural Gas Pipelines in Australia - AMEC September 1986
* * *
xiii
Page
10
17
47
48
49
72
85
117
121
144
238
239
239
242
244
TABLE NO.
7.1
9.1
10.1
10.2
10.3
12.1
13.1
A.5.1
A.5.2
A.5.3
A7.1
LIST OF TABLES
SECV Estimates of Conservation, Cogeneration and Off-peak Marketing included in the 1987 Forecast
SECV Planned or Expected Plant Installations and Retirements
Large Scale Supply Options - Cost Data
Large Scale Supply Options- Workforce Requirements
Reliability and Energy Efficiency of Different Types of Large Scale Supply Options
Comparison of Results for Selected Scenarios
Present Value of Potential Generation Cost Savings Due to Oak lands Option, 1986-2015
Present Value of Potential Generation Cost Savings for Gas Turbine Options, 1986-2015
Breakdown of Potential Generation Cost Savings for a 1000 MW Gas Turbine - Brown Coal Sequence, 1986-201.5
Gippsland Basin Gas Reserves, December 1987
Comparison of Zeidler Inquiry and Natural Resources and Environment Committee Inquiry Base Load Generation Cost Estimates
Ranking of Major Sequences on Evaluation Criteria (SECV Table 21.1)
Classification and Examples of Demand Side Measures
Expected Contribution of Current Demand Management Programmes - SECV December 1986
SECV Demand Side Measures under Investigation and Possible Future Programmes
Options and Direct Costs
xiv
Page
12
30
53
57
59
91
111
119
120
124
148
161
207
208
209
218
TABLE NO.
A7.2
A7.3
A7.4
A7.5
A7.6
A9.1
A9.2
A9.3
A9.4
"Cost of Electricity Sent Out"- 4% Discount Rate
"Cost of Electricity Sent Out" - 8% Discount Rate
"Cost of Electricity Delivered" - 4% Discount Rate
"Cost of Electricity Delivered" - 8% Discount Rate
Offsets to Cost of Power Delivered from Oak1ands
Gipps1and Basin Natural Gas Reserves - Estimates at December 1987
Uncommitted Gipps1and Basin Natural Gas Reserves -Estimates at December 1987
Gippsland Basin Natural Gas Reserve Lifetimes based on Current Reserves and Usage Rates
North West Australian Gas Reserves- Identified Remaining Reserves at June 1987
* * *
XV
Page
221
222
223
224
225
231
232
233
247
TERMS OF REFERENCE
INQUIRY INTO ELECTRICITY SUPPLY AND DEMAND BEYOND THE MID-1990's
To inquire into, consider and report to the Parliament by 4 May 1988* on the most appropriate sequencing of future power supply options to foJJow Loy Yang B Units 1 & 2 in order to meet the forecast range of load growth for the decade beyond the mid-1990's, as part of the development of long-term strategies for balancing electricity supply and demand.
In particular, the Committee should:
J, Take into account:
(a) State Economic Strategy and Government Energy Policy, the SEC's statutory obligations and Corporate objectives, including social, employment, infrastructure, environmental and economic factors;
(b) current and proposed initiatives in demand planning and the potential impact of plant refurbishment programmes;
(c) consideration of the strategic role and economics of investment in conservation, cogeneration and load management and progress with development of renewable energy resources;
(d) the desirable mix of future fuels for generation in the Victorian electricity system (other than nuclear power, excluded under the Nuclear Activities (Prohibition) Act 1983), in the light of potential economic, business, and regional/State employment implications, and the location, nature and extent of potential fuel resources;
(e) the development of the three-State South East Australia interconnected power system and its potential for future extension/expansion; and
xvi
(f) the extent to which the possible requirements for future steam supplies or other services to new industrial applications for coal, including the future requirements for briquetting, might impact on the sequencing of future Latrobe Valley power generation projects.
2. Include recommendations as to whether or not the SEC should pursue the feasibility of developing a black coal fired power station in northern Victoria, or the prospects for an arrangement with NSW and/or other partners for either investment in or purchase of power from a possible Oaklands, NSW power project.
3. Identify specific issues requiring detailed consideration during the subsequent environmental assessment/project approval processes for the future power generation projects recommended by the Committee.
* Amended by the Governor-in-Council 24 November 1987.
* * *
xvii
SUMMARY OF FINDINGS
The Committee has concluded that a long-term electricity development
strategy should be implemented which has the objective of maximising the
benefits which can be obtained from the supply and utilisation of electricity by
minimising the economic, social and environmental costs.
This objective is consistent with the State Economic Strategy and SECV's
statutory obligations and corporate objectives.
It is anticipated that the bulk of the State's electricity supply will continue to
be based on the brown coal resources of the Latrobe VaJJey and the Committee
has concluded that Loy Yang B Units 3 & 4 should be the next base load units
committed for construction after Loy Yang B Units 1 & 2.
The development of black coal resources at Oaklands in NSW could provide
Victoria with an opportunity to gain access to an economic source of
intermediate load power supply and at the same time to benefit from the
strengthened interconnection between the two States. The Government should
pursue this opportunity with the Government of New South Wales. In certain·
circumstances, construction of the Oaklands plant could overlap with
construction of Loy Yang B Units .3 & 4.
An increased use of natural gas for power generation could have benefits for
Victoria. The Committee has inquired into the long-term availability of
natural gas to Victoria and the possibility that gas might need to be supplied to
Victoria from the North West Shelf some time after 2010. The Committee has
concluded that there is a case for inclusion of up to 500 MW of additional gas
fired capacity in the Victorian system.
xix
The Committee commends the Unions, the Latrobe Regional Commission,
CRA Ltd., BHP and SECV for their submissions on the effects of a large range
of alternative future power supply sequences. This approach to long term
broadly based power supply planning is new in Victoria and has allowed the
Committee to propose a strategy for the development of the Victorian
electricity supply system.
Most of the submissions, lead to the conclusion that it is not in the best
interests of Victoria to define a sequence of power supply options for the
decade following the mid-1990's.
In principle, the evidence presented to the Inquiry shows that the least cost
Victorian electricity supply system should include a combination of
hydro-electric, brown coal, black coal and natural gas fired plant, and greater
energy interchange between Victoria and New South Wales. This in turn leads
to the conclusion that there will be an increasing need for co-ordination of the
development and use of all forms of energy both in Victoria and between
States.
The evidence indicates that the selection of the most appropriate future power
station sequence will be influenced by the future social and economic
environment as much as by the internal configuration of the sequence itself.
SECV has used sophisticated analytical techniques to forecast a range of
future electricity demands. Uncertainty still attaches to these forecasts.
Uncertain world economic conditions could result in an electrical load growth
which fluctuates and which may have a long term trend lying outside the
ranges projected by SECV.
This uncertainty about the economy and Victorian power requirements,
together with other uncertainties related to the performance and life of
existing plant, and the possibility of using a more diverse range of fuels
highlights the need to optimise capital and operating costs. The Committee
has concluded that it is in the best interests of Victoria to adopt a flexible
strategy rather than a definite sequence of future power supply options. Such
a strategy would also encourage competition between the available energy
resources and promote improved technology based on brown coal.
XX
The availability and expected life of existing generating plant is an important
factor in the need for and timing of new plant additions. Plant life extension
generally leads to greater economic benefits than new plant construction.
However, the economic life of a particular plant will only be established as a
result of regular reviews throughout its life. Predictions of plant lives and
performance therefore include an element of uncertainty.
On present estimates the installation of Loy Yang B Units 3 & 4 would cost
less than the installation of any of the other brown coal fired plant options in
the Latrobe Valley. The Committee believes that scope exists to further
reduce the capital and operating costs of this development. This should be
explored before the Government authorises commitment to contracts and
expenditure on the construction of Loy Yang B Units 3 & 4.
Further work needs to be undertaken by SECV before it is possible to
determine which should be the next Victorian brown coal power supply option
to follow Loy Yang B Units 3 & 4. The Committee has recommended that this
matter should be referred to it under new terms of reference.
A black coal fired power station based on the Oaklands coal deposit would be
significantly lower in capital cost than an equivalent brown coal fired station
and would be suitable for intermediate load duty on the Victorian system.
Estimates based on a range of probable coal prices indicate that the cost of
energy from such a station would be comparable to the cost of energy from
Loy Yang B Units 3 & 4 and significantly less than the cost of energy from
other brown coal fired options.
Joint development of the Oaklands project by NSW and Victoria would result
in a strengthening of the transmission link between the two States alJowing a
higher level of interchange and system reliability with overall economic
benefits to both States. There are also potential benefits for South Australia.
Development of the Oaklands project would provide the greatest economic
benefit to Victoria if it was timed to meet coincident needs in NSW and
Victoria. The economics do not favour sole Victorian participation in a two
unit development at Oaklands. Development of a two unit station at Telford,
xxi
south of Yarrawonga is not considered to be economically or environmentally
desirable.
There is as yet no commitment by NSW to the development of Oaklands, it
remains one of a number of potential new power supply options which are
being evaluated by NSW. It is expected that the first draft Electricity
Development and Fuel Sourcing Plan for NSW will be available at the end of
June 1988.
It is essential that, should the Oaklands project proceed, an adequate
community infrastructure be provided in the region. Estimates of the cost of
providing this infrastructure show that this is unlikely to be comparable with
the potential benefits which could be derived from the project or with the
overall cost of the project itself.
In summary, there are potential benefits of joint participation with NSW in a
4 x 700 MW Oaklands power station project and the possibility of such an
arrangement should be pursued with the Government of New South Wales.
There are sufficient uncommitted Bass Strait gas reserves to allow the
installation of at least a further 500 MW of gas turbines. The additional gas
consumption, if this amount of new plant was installed, would shorten the
expected life of present known Bass Strait gas reserves by approximately one
and a half years in the period after 2010. At that time, unless further
significant reserves of gas are discovered in Bass Strait, it is probable that gas
wiH be supplied at competitive prices to the whole of south east Australia by a
pipeline from the North West Shelf.
There could be an economic argument for the inclusion of up to 1000 MW of
new gas turbines of a unit size in the order of 1 00 MW on the Victorian system
to supply peak and intermediate loads. The low capital cost of gas turbines,
together with their short construction lead time provides the potential for
financial savings if gas can be supplied at a suitable price. The cost of gas can
only be determined by negotiations with Esso-BHP for a firm contract to
supply defined quantities of gas, under certain conditions.
xxii
The Committee has therefore concluded that Government policy should be
amended to allow for the further use of gas for power generation. The SECV
should attempt to negotiate a firm contract for the supply of sufficient gas to
fuel up to 500 MW of gas fired plant operating in a peak/intermediate load role
over a twenty year plant life.
During the Inquiry concern was expressed about the potential impacts of
various sequences of power supply options on the Latrobe Valley, particularly
with respect to employment levels and other socio-economic effects. The
Committee has concluded that, from an employment viewpoint, the Latrobe
Valley is one of the more fortunate areas of provincial Victoria in that three
of Victoria's largest and most stable industries are based in the region. These
are the power, oil and gas, and paper industries. However, because of the
generally high level of continuity of work in these industries, the regional
economy and the community as a whole has become unduly reliant on their
continuing growth. The investment required per employee in the power
industry is extremely high. It would benefit both the region and the State if
this reliance could be reduced through the introduction of other more diverse
industries. This is not something that will come about of its own accord. It is
most likely to be achieved as the result of initiatives developed either from
within the region, by Government or by individual industries.
Comments received as a result of the Committee publishing a Preliminary
Report and Draft Recommendations in December 1987 suggested that the
Committee had paid insufficient attention to the potential savings that could
be achieved through demand management and energy conservation. The
Committee has examined this aspect in more depth and has concluded that it
is necessary for SECV to develop improved analytical tools in order to present
demand and supply side measures on a common basis. The Committee has
recommended that demand side measures be further considered by it under
new terms of reference.
During the course of the Inquiry, the Committee made several requests for
further information on the briquette factory at Morwell. In March 1988,
limited information was made available; however, this information did not
cover all the issues associated with the future of this plant, and the
Committee has recommended that the briquette operation should also be
xxiii
further considered by it under new terms of reference.
The overall thrust of this report is the same as that contained in the
Committee's Preliminary Report and Draft Recommendations published in
December 1987. Differences between the two reports are summarised in
Appendix 15.
xxiv
RECOMMENDATIONS
PREAMBLE
The information provided in evidence to the Committee does not provide a
sufficient basis on which to nominate a specific power supply sequence to follow
Loy Yang B Units 1 & 2. The need to maintain flexibility to meet unpredicted
changes in electricity demand levels, to minimise the risk of commitment of
large State capital resources before it is necessary to do so and to have the
ability to incorporate improved technology and practices militates against
prescribing a single fixed sequence at this time.
Hence, the Committee considers that the future needs of Victoria will be best
served if the Government and SECV adopt a long term electricity development
strategy as described in the following recommendations.
Some aspects of the proposed electricity development strategy
endorse statutory requirements, policy and procedures already followed
or proposed by SECV. However, the recommendations are designed to ensure
that SECV becomes more accountable to the community.
AN ELECTRICITY DEVELOPMENT STRATEGY
Principal Recommendations
1. The Government and SECV should adopt an Electricity Development Strategy based on the Overall Objective, Strategic Principles and Key Elements described below, together with the Specific Recommendations which follow.
(S.14.9- P.181)
2. SECV should prepare and publish an annual Electricity Development Strategy and Implementation Review document for submission to the Parliament, in accordance with the format suggested in Appendix 14 of this report.
(S.14.9- P.181)
XXV
Overall Objective
3. The objective of the proposed Electricity Development Strategy should be:
"In the face of an uncertain future, to provide Victoria with the greatest opportunity to maximise the benefits that can be obtained from the supply and utilisation of electricity by minimising economic, social and environmental costs."
(S.14.3 - P.174)
Strategic Principles
4. The principles underlying the Electricity Development Strategy to meet this objective should be:
Conservation of the State's energy resources;
Effective and efficient use of the State's installed electricity supply system;
Regular evaluation of a full range of options for balancing electricity supply and demand over time based on assessment of the future economic, social, biophysical, political, technical, scientific and market environments in which Victoria's electricity supply system will evolve;
Consideration of the robustness and flexibility required to deal with a wide range of unpredicted changes without incurring unacceptable social or economic consequences;
Consideration of the level of diversity which should be provided in the supply system when selecting and locating new generation options and their associated fuels;
Introduction of new technology and techniques for supplying and more efficiently utilising electricity;
Incorporation of public accountability, participation and review where appropriate.
(S.14.4- P.174/5)
Key Elements
5. The strategy should include the following elements:
The development and implementation of economic conservation and demand side measures;
xxvi
The development of Research and Development programmes incorporating iMovative approaches to both electricity supply and demand. These should include the development of brown coal technology, energy conservation measures and renewable energy resources;
The extension of existing SECV programmes for improving the availability and life of existing plant:
The development of SECV's scenario approach to planning to ensure that the impacts of alternative measures for balancing supply and demand can be re-assessed as circumstances change;
An increased level of joint planning between the intercoMected States of NSW, SA and Victoria;
The establishment of a clear and open project approval process which encourages flexibility and rapid response to changed circumstances;
A reduction in the risks associated with the uncertain economic environment and the long lead time required for power supply projects, particularly coal fired plant. There is considerable scope for improvement in this area, and the following concepts outline some of the ways in which this could be achieved:
Where possible, plaMing and environmental approval being granted "in principle" for individual projects ahead of the time when they might be required. A shorter review should be held to consider remaining issues related to the timing of the project, just prior to the Government granting authority to proceed. However, projects with "in principle'' approval which do not proceed for several years should be examined at ten yearly intervals and the approval revoked if the basis for the original approval becomes invalid;
The use of short lead time options such as small gas fired units to buffer the longer lead time coal fired plant against unforeseen changes in electricity demand forecasts;
The avoidance of commitments to UMecessarily large packages of new plant consistent with optimising capital and operating costs;
The use of flexible purchase and installation contracts where this is economic and appropriate.
(8.14.5 - P.175/6)
xxvii
SPECIFIC RECOMMENDATIONS
The following recommendations should form part of the electricity development
strategy:
Pricing, Demand Side Measures and Energy Conservation
6. SECV should continue to evaluate the relationship between the costs of proposed sequences of supply options and its pricing policies to establish the consequent implications for future levels of electricity demand.
(S.3. 7 - P .25)
7. SECV should give consideration to expanding its range of electricity supply tariffs to include more generally available tariffs for controllable or interruptable supplies.
(S.3. 7 - P .25)
8. SECV should continue its present programmes which are aimed at encouraging conservation and demand side measures. They should investigate the potential to expand these programmes and to develop new programmes. The effectiveness of these programmes and their potential for expansion should be reported in SECV's annual report.
(S.3. 7 - P.25)
9. The Government should amend the Victoria Building Regulations to require thermal insulation in new buildings and should continue to promote the design and construction of solar and energy efficient buildings.
(S.3.7- P.25)
10. Further terms of reference should be given to this Committee to allow for a more detailed examination of demand side and energy conservation measures and their potential to contribute to economically, socially and environmentally beneficial strategies for balancing electricity supply and demand. This examination should be based on:
The development of methodologies for quantifying the effects of and evaluating demand side and energy conservation programmes on a basis consistent with evaluation of supply side options;
The integration of demand side and supply side planning using a least cost approach to maximise overall benefits to Victoria;
The development, selection and implementation of practical demand side and energy conservation programmes for Victoria;
xxviii
The identification of research and information needs for effective demand side and energy conservation programmes.
(S.3. 7 - P.26)
11. The Commonwealth and Victorian Governments should support the gathering and analysis of information which would improve the current level of understanding of the Greenhouse Effect and its implications for Victoria, Australia and the world at large. In particular, SECV should assist by providing annual estimates of the total release of Carbon Dioxide and other contributing emissions from its operations. This information should be published each year in Victoria's "State of the Environment Report" together with estimates of contributions from other sources.
(8.3. 7 - p .26)
The Performance of Existing Generating Plant
12. Priority should be given to improving and maintaining the availability of existing plant and extending its life where this is economically viable.
(S.4.5 - P.38)
13. SECV should publish a yearly review of the performance and condition of its generating plant, including:
Details of available and actual capacity factors achieved, major planned and unplanned unit outages, repair times and other statistics;
Targets and projections for the performance of existing plant over future years, and explanations of any significant deviation of actual performance from earlier targets.
(8.4.5 - P.38)
14. SECV should carry out and publish regular assessments of the scope for improving the projected performance or expected lifetime of existing plant through refurbishment or preventive maintenance works, changed management or work practices, or technological enhancements.
(S.4.5 - P.38)
15. Prior to commitments to construct new generating plant, the interaction between existing plant performance and lifetime, and the introduction of new plant should be reviewed. This review should ensure that the fuel resources allocated to the existing plant allow the maximum scope for performance improvement and economic life extension. In particular, the planned retirement date of the Hazelwood Power Station should be subject to a detailed review prior to any commitments to construct new power stations for service after 1999.
(S.4.5 - P.39)
xxix
Research and Development Related to the Use of Brown Coal
16. A more active Research and Development programme should be initiated by SECV into improved techniques for the use of brown coal in power generation. This should include:
Development of efficient methods for the production and utilisation of pulverised dried brown coal;
Investigation of the potential for development of a "de watered" coal;
Development of improved milling, burner and precipitator designs;
Optimisation of boiler designs;
Optimisation of coal winning techniques, utilisation strategies, and equipment;
An on-going review of developments in the Circulating Fluidised Bed Combustion and Integrated Gasification Combined Cycle technologies;
A detailed review of the possibility that gas turbines could be developed to operate satisfactorily on brown coal.
(S.4.5 - P.39/40)
The Desirable Mix of Fuels
17. The Victorian electricity supply system should be developed to include hydro-electric, gas, black coal and brown coal fired plant, together with a strengthening as required of the interconnections between Victoria, NSW and SA.
(S.13.9- P.171)
18. The relative proportions of the different types of plant should be determined by regular reviews of resource availability and the economic social and environmental factors involved.
(S.13.9 - P.171)
19. SECV should carry out a further review of the possibility that pumped storage options could be developed in association with existing storages, in particular the Thomson and Dartmouth Reservoirs. If feasible sites are identified, the capital costs of their development should be estimated by expert feasibility studies and they should be subjected to economic and environmental evaluation. This evaluation should be carried out in a manner similar to the evaluations of other major supply options presented to this inquiry so that the value attributed to pumped storage in terms of system costs and reliability is demonstrably valid given the current and expected future plant mix and load profile.
(S.5.12- P.73)
XXX
Loy Yang B Units 3 &: 4
20. On the basis of the cost comparisons presently available to the Committee and the social and employment contributions to the Latrobe region and Victoria, Loy Yang B Units 3 &. 4 should be the next base load units committed for construction after Loy Yang B Units 1 &. 2.
(S.13.9 - P.172)
21. No final commitment to contracts and expenditure to construct Loy Yang B Units 3 &. 4 should be given until the latest time consistent with maintaining a reliable electricity supply system. Immediately prior to authorising expenditure on the major plant items, the Government should ensure that SECV reviews the capital and operating costs of both Loy Yang B Units 3 &. 4 and other viable power supply and demand side options. This should include a re-evaluation of the socio-economic effects of these alternatives in the light of updated load forecasts and other relevant information.
(S.B.ll - P.l 05)
Oaldands
22. Negotiations should be initiated and pursued by the Victorian Government with the Government of New South Wales to establish the prospects for an arrangement with NSW and/or other partners for either investment in or the purchase of power from a black coal fired power station at Oaklands in NSW.
(S.9.5 - P.113)
23. The introduction of the Oaklands plant should be primarily determined by a coincident need for additional sources of power supply in both Victoria and NSW and an agreement to proceed on a co-ordinated basis. The Oaklands plant would probably be constructed after Loy Yang B Units 3 &. 4, however, the possibility of the projects overlapping in certain circumstances, such as a rapid growth in the demand for electricity, should not be ruled out.
(S.9.5 - P.113)
24. Prior to the Oaklands project proceeding, a detailed evaluation of the electricity transmission systems interconnecting the three States and the Snowy Scheme should be carried out with a view to optimising the benefits which might flow from the reinforcement of this system as part of the Oaklands project. This should include a review of the appropriate voltage levels for the transmission system and the possible benefits that might arise from strengthening the transmission links in advance of the Oaklands development.
(S.9.5 - P.114)
xxxi
25. The following issues should be considered before Victoria makes a final commitment to an Oaklands project:
The commercial relationships between the parties to the Oaklands project;
An independent detailed evaluation of the economics and long term viability of the Oaklands project including the proposals for the supply and disposal of water, and the proposed coal supply arrangements;
The requirements of the appropriate environmental and resource planning authorities including the Murray-Darling Basin Commission;
The provzswn and funding of community and project infrastructure both in NSW and Northern Victoria;
The arrangements for sharing the output both in respect of Victoria's needs and the passibility of minimising undesirable employment effects in the Latrobe Valley;
Transmission line routes from Oaklands to Melbourne. (S.9.5 - P.114)
Joint Interstate Planning
26. The Government should seek to achieve an increased level of co-ordination and joint electricity planning amongst the interconnected States of NSW, SA and Victoria. Consideration should be given to the sharing of new power projects, in addition to the opportunity offered by Oaklands, including gas fired peaking plant and coal fired intermediate and base load plant. The possibility of delaying capital expenditure on new plant by short term increases in the level of interstate energy transfers in the period immediately preceding the installation and commissioning of the new plant should always be considered. From time to time the possibility of a link with Tasmania should be reviewed.
(S.12.7- P.157)
27. The Government should initiate the formation of a South Eastern States Energy Planning Committee consisting of representatives of the Governments of Victoria, New South Wales, South Australia and Tasmania. This Committee should be responsible for the co-ordination and joint planning of energy supplies in South Eastern Australia, including an on-going review of:
Expanded electricity transfer between the States;
The development of a South Eastern States gas grid, including in the longer term a gas supply from North West Australia;
The development of management structures to formulate joint forward planning and efficient management of joint interconnected systems for the energy industry.
(S.12.7- P.157)
:r::r::r:ii
The Snowy Scheme
28. Through its representation on the Snowy Mountains Council, Victoria should continue to ensure that the considerable benefits deriving from the Snowy Mountains Hydro-electric Scheme are maximised. A review of the potential for further pumped storage capacity should be carried out. Operational strategies, options for plant refurbishment and upgrading should be regularly reviewed and any changes assessed in relation to their overall impact on the Victorian and NSW electricity and water systems.
(S.12.7- P.158)
Natural Gas
29. The Government should review its present energy policy with respect to the use of natural gas for power generation, taking into account the Natural Resources and Environment Committee's conclusion that considerable benefits would result from the inclusion of up to 500 MW of additional gas fired plant in the Victorian system. This additional plant should be used for peak/intermediate load duties only.
(S.10.3- P.131)
30. If Government policy is changed to accommodate the conclusions reached by the Committee, then SECV should be authorised to negotiate a suitable gas supply contract. The Government should ensure that SECV and GFCV adopt a co-ordinated approach to negotiations with the producers so that adequate consideration of deliverability issues occurs, consistent with maintaining a minimum overall cost to Victoria.
(S.10.3 - P.132)
31. SECV should continue to develop proposals for both gas turbine and combined cycle plants, including the option of staged development of a combined cycle station.
(S.10.3 - P.132)
32. In determining the detailed programme for installing new gas fired plant, SECV should take into account the potential for improving the robustness and flexibility of the overall supply development programme.
. (S.10.3 - P.132)
33. The proposed study of Bass Strait natural gas reserves by the Department of Industry, Technology and Resources should be expedited and its findings should be made publicly available as soon as it is completed.
(S.10.3 - P.132)
34. If a gas supply contract is negotiated then planning and environmental approval procedures for an appropriate site or sites for locating gas fired generation facilities should be commenced as soon as the contract negotiations are completed. These procedures should be incorporated in
xxxiii
an Inquiry conducted by the Natural Resources and Environment Committee under appropriate Terms of Reference proclaimed by the Governor-in-Council and should be co-ordinated with requirements under the Environment Effects Act 1978.
(8.10.3 - P.132)
Brown Coal Options after Loy Yang B Units 3 &: 4
35. Further terms of reference should be given to this Committee so that further consideration can be given as to which should be the next brown coal fired power station constructed after L.oy Yang B Units 3 & 4. The terms of reference should also require the Committee to address:
(a) the most appropriate form for the subsequent environmental assessment/project approval processes;
(b) the specific issues requiring detailed consideration during the subsequent environmental assessment/project approval processes.
(8.11.5- P.139)
High Voltage Transmission Lines
36. Prior to any new high voltage transmission lines being constructed, a further public evaluation of the long-term development of the Victorian high voltage transmission system should occur. This should be integrated with a review of the alternative demand and supply side options and sequences available at that time, together with consideration of environmental, health and safety issues.
(8.5.12- P.73)
The Briquette Factory
37. Further terms of reference should be given to this Committee to allow further consideration of the future of the Morwell Power Station and Briquette Factory. These terms of reference should require the Committee to address:
(a) The most appropriate auxiliary fuels for existing and future brown coal fired boilers;
(b) The future market for briquettes other than for use by SECV;
(c) The effects of any proposed changes on employment levels. (8.11.5 - P.139)
Small Scale Supply Options
38. SECV should consider stand alone power supply systems as an alternative to extending the electricity distribution system into remote areas.
(8.6.5 - P.81)
xxxiv
39. The Government and SECV should review the effects of the cogeneration and renewable energy "incentives" package after a suitable period has elapsed and, if appropriate, further restructure SECV's standby and buy-back tariffs.
(S.6.5 - P.81)
40. SECV should investigate the possibility of making firm arrangements for the operation of private emergency and standby generators during periods of potential energy shortage on the interconnected generating system. These investigations should consider the possible cost advantages which might arise from such arrangements through reduction in SECV reserve plant requirements.
(8.6.5 - P.Bl)
41. SECV should significantly expand its involvement in research and demonstration projects related to renewable energy based electricity generating technologies.
(8.6.5 - P.81)
Latrobe Valley Employment Impacts
42. Local, Regional, State and Commonwealth Authorities should attempt to introduce a more diverse range of industry to the Latrobe Valley.
(8.13.9 - P.172)
43. When considering the detailed timing of future power supply options, consideration should be given to the possibility of minimising the employment impacts in the Latrobe Valley without incurring significant economic penalties.
(S.13.9 - P.172)
*
XXXV
The Natural Resources and Environment Committee appointed pursuant to the
provisions of the Parliamentary Committees Act 1968 (No. 7727) has the honour to
report as follows:
INQUIRY INTO ELECTRICITY SUPPLY AND DEMAND
BEYOND THE MID-1990'S
CHAPTER ONE
INTRODUCTION
1.1 Terms of Reference
On 7 October 1986, the Committee was directed by His Excellency the
Governor-in-Council:
To inquire into, consider and report to the Parliament by 1 October 1987 on the most appropriate sequencing of future power supply options to follow Loy Yang B Units 1 & 2 in order to meet the forecast range of load growth for the decade beyond the mid-1990's, as part of the development of long-term strategies for balancing electricity supply and demand.
In particular, the Committee should:
1. Take into account:
(a) State Economic Strategy and Government Energy Policy, the SEC's statutory obligations and Corporate objectives, including social, employment, infrastructure, environmental and economic factors;
(b) current and proposed initiatives in demand planning and the potential impact of plant refurbiShment programmes;
(c) consideration of the strategic role and economics of investment in conservation, cogeneration and load management and progress with development of renewable energy resources;
1
(d) the desirable mix of future fuels for generation in the Victorian electricity system (other than nuclear power, excluded under the Nuclear Activities (Prohibition) Act 1983), in the light of potential economic, business, and regional/State employment implications, and the location, nature and extent of potential fuel resources;
(e) the development of the three-State South East Australia interconnected power system and its potential for future extension/expansion; and
(f) the extent to which the possible requirements for future steam supplies or other services to new industrial applications for coal, including the future requirements for briquetttng, might impact on the sequencing of future Latrobe Valley power generation projects.
2. Include recommendations as to whether or not the SEC should pursue the feasibility of developing a black coal fired power station in northern Victoria, or the prospects for an arrangement with NSW and/or other partners for either investment in or purchase of power from a possible Oaklands, NSW power project.
3. Identify specific issues requiring detailed consideration during the . subsequent environmental assessment/project approval processes for the future power generation projects recommended by the Committee.
1.2 Request for Additional Information
In December 1986, the Committee requested the State Electricity
Commission of Victoria (SECV) to include in its evidence to the Inquiry
consideration of the possibility of an increased use of natural gas for power
generation. This request resulted in SECV having to considerably revise and
add to the information it was proposing to present as evidence to the
Committee. The time taken to prepare the revised evidence, together with
the extensive public consultation programme proposed by the Committee
resulted in a revision of the originally specified reporting date of
7 October 1987.
1.3 Amended Reporting Date
On 24 November 1987, the Governor-in-Council amended the reporting date
for the Inquiry to 4 May 1988.
2
1.4 Public Consultation Prior to this Inquiry
Prior to a decision being made on the need for this Inquiry, SECV conducted a
public consultation process in order to review the most appropriate planning
and approval processes for the choice and sequencing of new power
generation options and their subsequent statutory approval.
During this public consultation process, three specific concepts were raised,
these were:
The need for any planning and approval process to create an
environment favourable to an informed public debate on the
significant issues. It was suggested that the adversarial nature of
earlier Parliamentary Inquiries, such as the Driffield Inquiry,
inhibited contributions from the public.
The need to provide funds to assist community groups and
individuals with the cost of preparing submissions to the approval
process.
The need to ensure that those involved in assessing the
submissions to the approval process had access to experts who
could assist in reviewing complex technical matters, where this
proved necessary.
This Inquiry was established on the understanding that the above concepts
would be incorporated in the Inquiry process in as far as might be practicable.
1.5 The Inquiry Programme and Public Consultation
The Inquiry has moved through the following broad stages:
October 1986
December 1986
Terms of Reference promulgated, Public Hearings- initial public briefing by SECY.
Public Hearings - SECV presented evidence on the need for new sources of power supply in the period 1995-2005.
3
February 19&7 The Committee visited NSW, SA and the Snowy Mountains Hydro-electric Scheme.
March 19&7 The Committee visited Latrobe Valley, inspected existing power stations, reviewed plant improvement and plant life extension programmes.
March/ April 19&7 - Public Hearings - evidence presented on available energy resources and power supply options.
May 19&7 The Committee visited Latrobe Valley and Yarrawonga and inspected sites for possible future power supply options. The Committee also visited Richmond Control Centre and Newport Power Station.
July 19&7 Public Hearings - evidence presented on the effects of alternative sequences of the available power supply options.
August 19&7 Committee visited SECV's Latrobe Valley workshops. Informal public seminars held to allow more detailed discussion of the July evidence and its implications.
October 19&7 Public Hearings - formal evidence taken as to the most appropriate sequence of future power supply options.
December 19&7 The Committee issued its Preliminary Report and Draft Recommendations for public comment.
February 19&& Public Hearings - evidence taken in respect of comments on the Committee's Preliminary Report and Draft Recommendations.
April 19&& The Committee makes its report to the Parliament.
The public hearings in October and December 19&6 and July 19&7 were held in
Melbourne. The public hearings in March/ April 19&7, October 19&7 and
February 19&& and the seminars in August 19&7 were held in both MorweJl and
Yarrawonga.
Members of the public attending the public hearings have been provided with
the opportunity to raise questions through the chair to those giving evidence.
4
A mailing list was established at the start of the Inquiry. This rapidly grew
to some 600 addresses. AH those on the mailing list received five
information booklets prepared by the Inquiry staff summarising evidence
given to the Committee, the Committee's Preliminary Report and Draft
Recommendations and four papers prepared by Consultants for the
Committee, and the Committee's report to the Parliament.
Some 200 of those on the mailing list requested and received copies of all
written evidence submitted to the Committee. A further 20 received copies
of the transcript of evidence given at the public hearings.
In total, over 1200 copies of the Committee's Preliminary Report and Draft
Recommendations and the Committee's Report to the Parliament have been
distributed.
All public hearings have been advertised in the local, regional and State
press. Press releases have been prepared and sent to all relevant newspapers,
radio and television stations on each occasion. Very good media coverage has
occurred in the Latrobe Valley and reasonable coverage occurred in the
Yarrawonga area. Very little comment, if any, has occurred in the Statewide
media.
The Department of Industry, Technology and Resources, on behalf of the'
Government, advertised and made available funds to assist individuals and
groups wishing to make submissions to the Inquiry. Approximately $15,000
was granted in total to the one individual and three organisations who took
advantage of this offer.
The Latrobe Valley Regional Commission organised the interested parties in
the Latrobe Valley to make a series of co-ordinated responses to the Inquiry.
In the Yarrawonga area, the Shires of Yarrawonga (Victoria), Corowa (N.S.W.)
and Urana (N.S. W .) combined to make a similar co-ordinated response.
109 written submissions were made to the Inquiry by 79 individuals and
organisations. 128 people representing either themselves or their
organisations gave evidence to the Committee at the public hearings.
5
Full details of the Inquiry Programme and of those who made submissions and
gave evidence are contained in Appendices 2, 3 and 4.
1.6 Use of Consultants
The Committee received assistance from the following consultants:
G.J. McDonell
P.M. Garlick and Associates Pty. Ltd.
B.Newell
Professor G. McColl
A.S. Atkins, D.G. Evans A. Wain
P.J. Brain, B.S. Gray, J.K. Stanley
1.7 Format of the Report
Commissioner, Inquiry into Electricity Generation Planning in NSW.
Consultant in the energy field.
Consultant on brown coal.
School of Economics, University of NSW.
School of Environmental Planning, University of Melbourne.
National Institute of Economic and Industry Research
The report first sets out the basic evidence presented to the Inquiry dealing
with forecasts of future demand, the capability of existing generating plant,
predicted plant retirements and existing commitments to new plant. This
evidence indicates that it is probable that up to 4000 MW of additional power
supply capacity may be required during the decade after 1995.
Before examining the power supply options available, possible demand side
measures are reviewed, the performance of existing generating plant is
examined and the possibility of introducing new technology is discussed. This
occurs in Chapters 3 and 4.
The major potentially viable supply options available during the period
1995-2005 are identified in Chapter 5 and include completion of Loy Yang B
Units 3 & 4, the continued development of Victoria's brown coal reserves, a
6
possible development based on black coal located at Oaklands in NSW and the
use of additional quantities of natural gas.
Chapter 6 discusses the role for small scale supply options in the Victorian
electricity supply system.
Chapter 7 describes the role of scenario modelling in the Inquiry and
summarises the results produced using this technique.
Each of the major power supply options is then reviewed in some detail in
Chapters 8, 9, 10 and 11. As part of this review, specific issues have been
identified which would require detailed consideration during any subsequent
project approval processes.
Chapter 12 examines the potential for an increased level of interstate
transfer of electricity and the need for an on-going review of the operation
of the Snowy Mountains Hydro-electric Scheme.
The review of the possible power supply options and increased interstate
trade in electricity leads, in Chapters 13 and 14, to consideration of the most
appropriate sequence of power supply options to follow Loy Yang B
Units 1 & 2 and in turn to a proposed electricity development strategy.
1.8 Differences from the Preliminary Report and Draft Recommendations
This report is based on the Preliminary Report and Draft Recommendations
published by the Committee for public comment in December 1987.
Comments received both as written submissions and at the public hearings in
February 1988 have been taken into account, and further background
information has been added. Appendix 15 summarises the differences
between this report and the Preliminary Report published in December 1987.
Copies of the comments received and transcript of the hearings can be
obtained from the Committee's offices.
7
CHAPTER TWO
BALANCING ELECTRICITY SUPPLY AND DEMAND
2.1 Introduction
Economic operation of an electricity system requires that the system supply
capability remains in balance with the demands of electricity consumers.
Too much electricity generation capacity needlessly increases the cost of
electricity. Too little results in electricity rationing and blackouts with
resultant costs to the community.
The Committee has examined proposals for balancing electricity supply and
demand beyond the mid-1990's. This has involved projections of the future
which, by their very nature involve a degree of uncertainty.
Evidence from SECV has included forecasts of the future demand for
electricity, projections of the performance of the existing supply system and
detailed information on the options available to increase the capacity of the
system.
2.2 Demand Forecast
Each year, SECV updates its long-term forecasts of electricity generation
and sales. High, median and low growth projections give a range of
electricity demand which reflect SECV's estimates of the range of
uncertainties of future economic activity. SECV's June 1987 forecasts are
shown in Figure 2.1.
SECV forecasts use econometric techniques which relate electricity
consumption to economic factors, population and price levels. End use
analysis is also used to assess particular consumption sectors.
9
et: ([
60000
ssooo
soooo
g:! 45000
c.. QJ a.
:I: 40000 3 (!)
asooo
aoooo
FIGURE 2.1
, '/-""
I
I
, ,
, , ,
HIGH
, , , , , , , MEDIAN , , , , , , LOW
/ /
/
Annual Growth Rate 1987-2002
I HIGH - 4. 9"1. MEDIAN ~ a. 5"1. LOW - 2. 9?.
1995 1990 1995 YEAR
2000 2005
TOTAL ELECTRICITY GENERATION FORECASTS FOR THE VICTORIAN SYSTEM 1987- 2002 (SECV)
10
Despite the use of sophisticated analytical methods, a high degree of
uncertainty must still be attached to any longer term forecast. Some of this
uncertainty is reflected in the range of the high, median and low forecasts
presented by SECV. However, these forecasts are based on fairly
conservative sets of alternative assumptions about the future which make no
allowance for the increasingly unstable world economic environment or for
significant changes in the longer term relationship between economic activity
and energy consumption. It is quite possible that future "catastrophic" events
such as the 1987 stock market crash or the 1973 oil price shock could lead to
quite different short or long term outcomes from those predicted by SECV.
It is worth recognising that, around the world, most forecasts of electricity
demand growth over the last decade have proven too high and have
consistently be:en revised downwards.
The demand for electricity can be modified deliberately by specific demand
side measures. Examples of these are the current Government policies
designed to promote cogeneration and conservation which should reduce the
future demand to be met by SECV. These measures are complementary to a
policy which aims to attract energy intensive industries to Victoria.
SECV has allowed for the effects of demand management by explicitly
adjusting the load forecasts in accordance with targets established for each
of the categories of demand management. The 1987 targets are shown in
Table 2.1 and SECV has indicated that these will be regularly reviewed as
further information becomes available.
SECV targets for demand management are not sufficiently substantive at this
stage. More work needs to be done to quantify the most appropriate targets
in order to maximise potential benefits and to integrate demand side
programmes with supply side developments. This is discussed further in
Chapter 3.
While it is recognised that demand management has the potential to improve
the efficiency of electricity utilisation, the Committee also acknowledges
that it is SECV's responsibility to maintain an adequate electricity supply
capability.
11
..... N
TABLE 2.1
Year
1987 1988 1989 1990 1991 1992 1993 1994 199.5 1996 1997 1998 1999 2000 2001 2002
(1) NB.
SECV ESTIMATES OF CONSERVATION, COGENERATION AND
OFF-PEAK MARKETING INCLUDED IN THE 1987 FORECAST
MEDIAN SCENARIO
Impact on Retail Electricity Sales (GWh) Domestic Commercial Industrial Total Conservation Conservation Cogeneration Cogeneration Conservation Cogeneration and Cogeneration
- - - - - -2 1 1 29 66 99
47 42 7 .50 112 2.58 91 8.5 11 74 168 429
134 128 17 102 234 61.5 178 171 22 127 281 779 221 217 28 1.54 3.50 970 266 264 34 180 412 11.56 312 314 40 207 47.5 1348 360 366 47 237 .541 1.5.51 406 419 .54 26.5 609 1753 4.53 476 60 296 680 196.5 .500 .53.5 68 329 757 2189 .549 .597 76 364 838 2424 600 663 84 402 922 2671 6.53 732 93 440 1011 2927
----
Conservation and cogeneration reduce the forecast values, whereas off-peak marketing will increase sales.
DomesticW Off-Peak Marketing
28 .51 96
161 244 3.50 466 600 744 898 963
1028 1093 11.57 1223 1287
2.3 Existing Generating Capacity
Victorian generating capability at 30 June 1988 will comprise 8003 MW of
plant made up of:
2750 MW of relatively new brown coal fired thermal plant of good
availability operating on base load duty. (Loy Yang A Units 1-4-
and YalJourn W Stage 2);
2710 MW of older brown coal fired thermal plant also on base load
duty but with lower availabilities and undergoing progressive
refurbishment (Yallourn W Stage 1, Hazelwood, Morwell and
Yallourn E);
500 MW of natural gas fired thermal plant on intermediate load
duty (Newport D).
465 MW of natural g.:~.s fired combustion turbines on peaking and
standby duty (Jeeralar:g);
1578 MW of hydro plant on intermediate and peaking duty
(includes 1084 MW of Snowy Mountains Hydro-electric Scheme
output).
2.4 Planned Availability and Retirement of Generating Capacity
It is currently estimated that Yallourn E (24-0 MW) will need to be retired in
1993 and that individual generating units at Hazelwood (8 x 200 MW) will be
progressively retired between 1999 and 2005.
The availability of a generating unit is a measure of the total possible annual
output from the unit allowing for maintenance shutdowns and partial
reductions in output caused by equipment failures. Until recently, Victorian
brown coal units have had relatively low availabilities and this has required
the establishment and maintenance of increased capacity margins.
13
Prediction of the future life and availability of existing plant is critical to
the assessment of the time that new plant might need to come into service.
SECV is currently proceeding with Production Improvement Programmes
(PIP) aimed at improving the availability of all power stations and Plant Life
Extension (PLE) programmes at Hazelwood and Yallourn W Stage 1 Power
Stations. The Hazelwood PLE programmes is intended to give these units a
life of 35 years. SECV has also submitted evidence that further life
extension at Hazelwood to 40 years would provide considerable savings (see
Appendix 6). Plant availability and lives have been dealt with in more detail
in Chapter 4.
2 • .5 Additional Supply Capacity Prior to the Mid-1990's
The Terms of Reference of this Inquiry imply that an additional two 500 MW
units (Loy Yang B Units 1 &: 2) will be installed prior to the mid-1990's on
the Loy Yang site. At the time of writing, the final date for completion of
these units had not been announced.
SECV is also in the process of investigating the possibility of a supply from
the Electricity Commission of New South Wales (ECNSW) on a block contract
basis over a period of up to two years during the early 1990's. This possibility
arises because ECNSW may have excess capacity available in its system
following completion of the Mt. Piper Power Station. Such a contract with
ECNSW may enable some capital expenditure by SECV to be delayed. SECV
also indicated that some additional delay may be possible if limited quantities
of energy are "banked" during the late 1980's when generating capacity is
expected to exceed the demand for electricity. This can be achieved in two
ways. The first is by allowing the water levels in the Snowy Mountains
Hydro-electric system to rise by reducing the call on the water for
generation. The second is to reduce power station natural gas consumption
and defer contractual minimum gas take requirements to later years.
14
2.6 Plant Mix
It is normal for electricity systems to feature a mix of high capital cost, low
fuel cost base load plant; lower capital cost, higher fuel cost intermediate
and peaking plant; and high capital cost, zero fuel cost hydro-electric plant
with a range of duties dependent on water availability. Least cost electricity
supply requires a balanced mix of available plant types.
This principle has been followed to good effect in the development of the
Victorian electricity system. The high capital cost brown coal fired plants in
the Latrobe Valley provide base load energy. The lower capital cost natural
gas fired plants at Newport D and Jeeralang provide intermediate and
peaking energy. The hydro plants in Victoria and the Snowy Scheme also
provide peaking energy but the total energy available from this source varies
from year to year with rainfall and irrigation demands. Natural gas provides
a flexible energy source which balances the base load brown coal energy and
the peaking energy from the hydro-electric schemes.
The Victorian electricity system is connected with the NSW electricity
system through the Snowy Scheme and is also to connect with the South
Australian system in early 1990. Interconnection improves system reliabiJity
because interstate support is usually available if one State's electricity supply
position becomes short for any reason. "Opportunity" transfers also give
overall fuel cost savings which are shared between the States. Interstate
trade in electricity is discussed in more detail in Chapter 12.
2.7 Balancing Supply and Demand
The need for new plant additions to the generating system depends on load
growth, the capacity and availability of the existing plant, plant retirements,
the level of interstate support available and the desired level of system
reliability. SECV evidence has stated that the desirable level of reliability
should be achieved with an Energy Reserve Margin of 5%. This is equivalent
to 25-30% of spare plant capacity above the system's maximum load.
15
Figure 2.2 is based on the various predictions by SECV of future loads and
plant capad ties.
The three broken lines represent the 1987 high, medium and low electricity
demand forecasts.
The heavy black lines represent alternative SECV views as to the most likely
capability of the existing and committed plant. This capability rises in the
period 1988-1993 because of the commissioning and working up of
Loy Yang A Power Station and the refurbishment of Hazelwood and
Yallourn W Power Stations. This is offset by the retirement of Yallourn E
Power Station in the period just prior to 1993. Flexible arrangments for the
commissioning of Loy Yang B Units 1 & 2 result in a range of possible plant
capabilities in the period 1992-1999. After 1999, the plant capabilities tail
off as Hazelwood units are progressively retired. This process could be
delayed by at least five years and is shown by the 35 year and 40 year life
alternatives.
The shaded area indicates the range of possible deviation from the most
likely plant capability if plant availability can be up-graded beyond or,
alternatively, falls below targetted levels.
Figure 2.2 is indicative of the large range of uncertainty involved in
predicting what supply and demand side measures will be required to balance
supply and demand in the decade beyond the mid-1990's.
It can be concluded from this diagram that it is probable that some additional
sources of supply will be required in the period 1995-2005.
16
> 0 a: w z w ...1
50000
45000
40000
~ 35000 z z c(
30000
25000
POSSIBLE RANGE OF CAPABILITY PROVIDED BY FLEXIBLE INSTALLATlON PROGRAM FOR LOY YANG B UNITS~ & 2
I I
I I
I
I I
1HIGH
I
/
/MEDIAN
/
POSSIBLE RANGE OF CAPABILITY DEPENDENT ON PLANT PERFORMANCE AND HAZELWOOD PLANT LIFE
1985 1990 1995 2000
YEAR ENDING 30th JUNE
1987 DEMAND FORECASTS
40 YR UFE. HAZEL WOOD
2005
FIGURE 2.2 COMPARISON OF DEMAND FORECASTS AND RANGE OF SUPPLY CAP ASD..ITY OF EXISTING AND COMMITTED PLANT (J' &: lfO YEAR LIFE AT HAZELWOODPOWERSTATION)
17
CHAPTER THREE
PRICING, DEMAND SIDE MEASURES AND
ENERGY CONSERVATION
3.1 Introduction
Pricing, demand side measures and energy conservation should not be
overlooked in the formulation of a long-term strategy for balancing supply
and demand. Such measures have received comparatively little attention in
the evidence presented to this Inquiry. The SECV approach to demand
management is outlined in the 1986 report, "SEC Outlook for Demand
Management to the Mid-1990's". This document establishes targets for a
number of demand management and energy conservation measures but fails
to establish clear economic criteria by which these can be compared and
integrated with supply side strategies. The Committee has concluded that a
further more detailed evaluation of the potential for demand management
and energy conservation measures to economicaJly contribute to a long-term
strategy is warranted. This chapter briefly discusses the reasons for this
conclusion and comments on the evidence presented to the Inquiry on demand
side measures and energy conservation.
3.2 Pricing
Pricing policy plays a large role in determining the relative economic
attractiveness of supply side and demand side measures.
A frequent recommendation concerning electricity prices is that they should
reflect the marginal costs of supply, that is, the costs of supplying additional
units of demand. Under marginal cost pricing it is argl'ed that both
consumers and supply authorities wiU receive the most appropriate signals
about consumption, conservation and investment decisions. Demand side
measures, which rely on modifications to consumer investment or
consumption decisions to achieve an overall economic benefit, will only occur
if the pricing signals encourage these modifications.
19
It is not proposed here to enter what continues to be an active field of
research and debate into public monopoly pricing, nor to analyse SECV's
present pricing levels and structure, but it is stressed that the relationship
between the price of electricity and the cost of supplying it must receive
early consideration in assessing all options for balancing supply and demand
over the longer term.
This will require a re-examination of SECV's intended pricing policies over
the next five to ten years in conjunction with the supply options chosen as a
result of this Inquiry. Evidence to the Inquiry has shown that different
combinations of supply options can have quite widely varying long run
marginal costs. The short run marginal costs of production would also vary
considerably between different plant sequences. This will probably have
implications for the level and structure of electricity prices, for the
consequent levels of electricity demand, and for the role of demand side
options. SECV has acknowledged that existing cross-subsidies between
consumers and consumer classes further complicate the consideration of
demand side measures.
SECV previously intended to issue a Pricing Development Plan in 1987 for
public consideration and comment. It is understood that an early draft of
this plan was discussed with the Commission's Consultative Committee on
Pricing, however, no final document has been released. The finalisation of
such a plan should be a matter of priority, although it is recognised that
reduction of cross-subsidies and moves to marginal cost pricing may require a
lengthy phase-in period. SECV should therefore continue to refine their
marginal cost analyses and to pursue the adoption of more consistent tariff
structures.
3.3 Demand Side Measures and Energy Conservation
Demand side measures are programmes aimed at reducing, or changing the
pattern of, electricity demand. Energy conservation measures form a
specific class of demand side measures. Typical examples of conservation
programmes would be financial assistance for thermal insulation in houses or
factories, and the promotion of energy efficient appliances. Other demand
side measures not necessarily leading to conservation of energy would include
20
initiatives like time-of-use prtcmg to encourage consumers to shift
electricity consumption to off-peak periods. It may be more cost effective
to change the future demand for electricity rather than to install additional
generating capacity in order to supply the "natural" level and pattern of
demand. Demand side measures can be thought of as alternatives, or
complements, to "conventional" supply measures. By comparing the costs and
other effects of different combinations of supply side and demand side
measures the most suitable combination can be selected.
Compared to thermal power stations, some demand side measures have the
advantage of requiring a short lead time. In addition, they can require only
small outlays of capital, particularly by the supply authority. This would be
of great advantage to SECV given its relatively high level of capital assets
and debt. Another advantage of many demand side measures, particularly
conservation, is their lack of, or low level of, environmental impact in
comparison with the impact of energy production technologies. Factors such
as the Greenhouse Effect, when more fully evaluated, may significantly
affect the emphasis placed on demand side measures by the community at
large.
On the other hand, there is less certainty about the overall level of effect of
demand side programmes. Only by implementing a programme can the rate
of penetration and ultimate effect be finally assessed.
More attention should be paid to conservation and demand side measures as a
means of improving the efficiency of Victorian energy use, reducing the
heavy demands for capital from the energy supply sector, and maintaining or
enhancing environmental quality. SECV should demonstrate that a
proportion of potential future load growth can or cannot be "supplied" more
economically through investment in demand side measures than through
investment in conventional supply options.
It is important that all options for balancing supply and demand in the longer
term are fully considered at the strategic planning stage, because the
relative attractiveness of demand side measures and energy conservation
changes markedly once irrevocable supply side investment decisions are
made. For example, SECV is committed contractually to the construction
21
of Loy Yang B Units 1 &: 2, and so has Jimited financial incentive to invest
heavily in the short to medium term in conservation or other demand side
measures which might reduce projected demand to the point where
over-capacity would result from installation of these units.
System reliability considerations are also important in balancing supply and
demand. Traditionally, electricity systems have invested in a certain
proportion of reserve plant to cover the probability that plant outages might
occur when system demand is high. Demand side measures are also available
which can contribute to system reliability. Specifically, arrangements can
be made by means of financial incentives for particular consumers to reduce
demand when supply capacity is short. Such interruptible or controllable
loads are common overseas. In Victoria, arrangements have been made for
the large aluminium smelting loads to be interrupted for short periods when
emergency situations occur. Arrangements could also be made for
privately-owned emergency or standby generators to come into service
during periods of potential energy shortage in SECV generating system.
These demand side measures should receive more detailed consideration by
SECV.
The earlier comments on electricity pricing should also be noted here. SECV
has argued that opportunities for significant investment in demand side
measures will be limited by the intention of SECV and government to adjust
prices over time to reflect long-run marginal costs. However, evidence
before this Inquiry has shown how widely marginal costs can vary with the
inclusion of different supply options and with the discount rate used to
calculate marginal cost, making it difficult to reconcile this intention with
the concurrent aim of maintaining stability in electricity prices. It can be
expected that there will continue to be areas in which substantial investment
in demand management can be justified.
22
3.4 Assessment of Demand Side Measures and Energy Conservation
Appendix 5 categorises demand side measures according to their nature and
purpose, and presents a summary of SECV's current demand side programmes.
The SECV approach to demand management has identified nineteen demand
management programmes and these provide the basis for the targets in
Table 2.1. However, no evidence has been presented as to how the
economics of each programme compares with supply side options, or how the
quantitative targets set by SECV were determined.
SECV should develop economic screening methods for demand side measures
so that each programme's priority can be set in relation to conventional
supply side options. The Committee understands that such methods have
been the subject of much development work in the U.S.A. over recent years
and that evaluation techniques are now available in that country.
In addition, the contribution of each demand side measure should be
quantified in relation to the duration of each programme and the programme
participants. Because the effects of demand side programmes can be
uncertain, SECV should develop methodologies aimed at quantifying and
reducing the uncertainty.
On the financial assessment of demand side programmes, SECV have proposed
that each programme should be required to pass the "non-participant's test".
This test would require that each programme should have no adverse financial
impact on any section of the community.
In practice, application of this test can serve to prevent the implementation
of demand side programmes with very sound economic features and benefit to
cost ratios. Application of the test to individual programmes is not
necessarily sound as it is the aggregate effect of all programmes which is
important. Consumers who are slightly worse off under one programme can
benefit from other programmes. In addition, there has never been a
requirement that supply side strategies should meet a non-participant's test.
For these reasons, the non-participant's test has fallen out of favour in the
USA and the most favoured approach is to develop least cost energy
23
strategies. The least cost strategy seeks to minimise the overall cost of
both supply and demand side developments.
SECV should pursue a least cost strategy as this will result in the maximum
long-term benefit to the Victorian community.
3.5 Integrated Planning
SECV have developed targets for their proposed demand management
programmes and then adjusted the load forecasts in accordance with these
targets. Supply side scenarios are then developed against the modified load
forecasts. This approach fails to properly integrate supply side options with
demand side programmes.
After developing priorities for demand management, SECV should seek an
integrated approach where the timing of both supply side and demand side
options are co-ordinated in individual scenario studies. Under such an
approach, more flexible and responsive strategies can be developed.
3.6 The Greenhouse Effect
It has been demonstrated that the levels of carbon dioxide in the atmosphere
have increased significantly over the last century. lt is currently thought
that two of the major underlying causes for this increase are dramatic
increases occurring in the world population combined with increased per
capita usage of fossil fuels. It is predicted that the levels of carbon dioxide
will continue to increase.
The term "greenhouse effect" arises because carbon dioxide acts like the
glass in a greenhouse. Visible radiation from the sun passes through glass or
carbon dioxide; on hitting the ground the sunlight is converted into heat and
the ground emits infra-red radiation. Infra-red radiation is blocked or
absorbed by the glass or carbon dioxide and this causes the overall ambient
temperatures of the air, the earth's surface and the sea to rise.
It has been predicted that changes in the ambient temperature will cause sea
levels to rise and major changes in global weather patterns to occur.
24
The overall process is extremely complicated and not well understood;
considerable co-ordinated international research is required over the next
decade or more before the implications can be fully evaluated. Until this
work has been done, it will not be possible to come to definite conclusions
about what precise action, if any, should or could be taken with regard to the
use of fossil fuels for the generation of electricity.
There is an urgent need for both the Commonwealth and Victoria to actively
support the gathering and analysis of the necessary information.
3.7 Specific Recommendations
SECV should continue to evaluate the relationship between the
costs of proposed sequences of supply options and its pricing
policies to establish the consequent implications for future levels
of electricity demand. (Recommendation 6)
SECV should give consideration to expanding its range of
electricity supply tariffs to include more generally available
tariffs for controllable or interruptable supplies.
{Recommendation 7)
SECV should continue its present programmes which are aimed at
encouraging conservation and demand side measures. They
should investigate the potential to expand these programmes and
to develop new programmes. The effectiveness of these
programmes and their potential for expansion should be reported
in SECV's annual report. {Recommendation 8)
The Government should amend the Victoria Building Regulations
to require thermal insulation in new buildings and should continue
to promote the design and construction of solar and energy
efficient buildings. (Recommendation 9)
25
Further terms of reference should be given to this Committee to
allow for a more detailed examination of demand side and energy
conservation measures and their potential to contribute to
economically, socially and environmentally beneficial strategies
for balancing electricity supply and demand. This examination
should be based on:
The development of methodologies for quantifying the
effects of and evaluating demand side and energy
conservation programmes on a basis consistent with
evaluation of supply side options;
The integration of demand side and supply side planning
using a least cost approach to maximise overall benefits to
Victoria;
The development, selection and implementation of
practical demand side and energy conservation programmes
in Victoria;
The identification of research and information needs for
effective demand side and energy conservation
programmes;
(Recommendation 10)
The Commonwealth and Victorian Governments should support the
gathering and analysis of information which would improve the
current level of understanding of the Greenhouse Effect and its
implications for Victoria, Australia and the world at large. In
particular, SECV should assist by providing annual estimates of
the total release of Carbon Dioxide and other contributing
emissions from its operations. This information should be
published each year in Victoria's "State of the Environment
Report" together with estimates of contributions from other
sources.
(Recommendation 11)
26
CHAPTER FOUR
THE PERFORMANCE OF EXISTING GENERATING
PLANT AND THE DEVELOPMENT OF IMPROVED PLANT
FOR THE FUTURE
4.1 Introduction
The generating capability of SECV's existing plant is a major determinant of
the short-term reliability of, and cost of operating, the electricity system,
and of the longer term requirements for the addition of supply capacity.
Poor performance from existing plants can increase the risk of electricity
restrictions and blackouts, and if prolonged, advance the time at which new
plant must be constructed and brought into service. Conversely, good
performance ensures reliability of supply, and if sustained, reduces future
requirements for new plant.
Over the last four years, SECV has identified the performance of its existing
brown coal fired power stations as an area of significant concern. Under the
Production Improvement Programme (PIP), it has obtained approval to spend
nearly five hundred million dollars on refurbishment and other works to
increase the projected energy contribution from these stations by either
improving reliability and capability or extending plant lifetimes. SECV
evaluations indicate that expenditures of this magnitude are more cost
effective than the alternative of earlier construction of new generating
plant.
Many of those giving evidence stressed the need for an increased level of
Research and Development if brown coal is to continue to compete with
other fuels in the long term.
4.2 Plant Availability
Plant availability can be broadly defined as the extent to which a power
station (or its individual units) is able to supply its rated capacity to the
system if called on.
27
The Committee commissioned P.M. Garlick &:: Associates to produce a paper
on power plant availability issues, with particular reference to experience
overseas and in other Australian states. Amongst the issues identified were:
Improving or stable trends in overseas plant availability, at levels
generally higher than Australian averages;
Significantly lower availabilities for thermal power stations in
NSW and Victoria than in Queensland, SA, or overseas;
Recent declines in availability in Victoria's older brown coal
stations;
The importance of technology, management procedures, work
practices and industrial relations in improving availabilities.
The paper reinforces the conclusion that availability is an extremely
important issue for SECV over the remainder of this century, and can
potentially have major impacts on the requirements for new generating
capacity over this period. PIP represents a significant commitment by SECV
to the objective of improving availability.
It is therefore important that the progress of this programme and the scope
for additional improvements in plant availability and performance are
regularly and publicly reviewed, in the same way as other aspects of SECV
operations, such as cost control on the Loy Yang project since 1982. Failure
to maximise the performance of existing generating plant by pursuing all
opportunities for improvement could lead to large and unnecessary additional
costs being imposed on all electricity consumers.
As part of this public review, SECV could produce a regular yearly report on
the performance of its installed generating plant, including details of
available and actual capacity factors achieved, planned and unplanned unit
outages, repair times and other statistics. In addition, target performance
levels for future years could be published and any significant deviations of
actual performance from earlier targets explained. Such a report would
enhance accountability and complement the detailed financial statements
presently required of SECV.
28
Any future commitments to new generating plant construction must be made
with adequate regard to existing plant performance. The incentive to
maximise plant performance can be severely reduced once fixed
commitments to expenditure and service dates for new plant are made.
Therefore, developing a strategy for new plant commitments that retains
incentives to maximise availability in existing power plants is an important
consideration.
4.3 Extending Plant Lifetimes
The assumptions used to estimate the financial, economic and regional
effects of future supply option sequences presented in this Inquiry, required
SECV to nominate retirement dates for its older power stations. SECV
indicated that a significant proportion of the present installed capacity,
particularly the base load brown coal fired capacity, would reach the end of
its operational life in the period following the mid-1990's. The retirement
dates nominated by SECV are shown in Table lf.l.
This means that the magnitude and timing of new plant installation over this
period is significantly driven by the requirement to replace retiring plant, in
addition to meeting projected demand increases. Consideration of the high
capital cost of new generating plant suggests that, if the lifetime of older
stations such as Hazelwood and YaHourn W Stage 1 can be prolonged by even
five or ten years, then very substantial cost savings may be available as the
need to construct a corresponding amount of new base load capac,ity would be
deferred.
Recognising the potential importance of this issue, the Committee requested
SECV to examine the economic value of extending the life of Hazelwood
Power Station from the assumed 35 years used in previous scenario studies to
lj.Q years. SECV's response to this request, reproduced as Appendix 6,
indicates that very significant benefits could accrue if such an extension
were feasible.
In fact, Hazelwood Power Station is currently undergoing a major
refurbishment and life extension programme, at a cost of around $300 m
(June 19&6), following a plant life study in 19&1f that indicated that
29
TABLE 4.1
SECV PLANNED OR EXPECTED PLANT INSTALLATIONS
AND RETIREMENTS
YEAR INSTALLATION RETIREMENT
1988 Loy Yang A4 (500 MW)
1992-940) Loy Yang Bl (500 MW)
1993-960) Loy Yang B2 (500 MW)
1993 Yallourn E (240 MW)
1999 Hazelwood I &: 2 (400 MW)
2001 Hazel wood 3 &: 4 ( 400 MW)
2003 Hazelwood 5 &: 6 (400 MW)
2005 Hazelwood 7 &: 8 (400 MW)
2006 Jeeralang A (225 MW)
2008 Jeeralang B (240 MW)
2011 Newport D (500 MW)
2013 Yallourn W l &: 2 (700 MW)
(I) Loy Yang B Units 1 &: 2 are currently programmed for installation on a flexible timetable dependent on load growth and plant performance.
30
complete closure of the station by as early as 1990, a twenty-five year life,
could have occurred without such works. This early closure would have had
severe consequences, necessitating reformulation of the present strategy for
Loy Yang B Units 1 & 2, with employment and other implications for the
Latrobe Valley.
It is of some concern to the Committee that the condition of the Hazelwood
plant had evidently deteriorated to the point where quite drastic measures,
such as complete replacement of the boiler waterwalls on the older units, had
become necessary to avert possibly imminent closure of the station. It is
somewhat fortuitous that the excess capacity now existing on the generating
system (a result of the inability to re-schedule Loy Yang A construction
despite lower than expected load growth) allows the extended outages needed
at Hazelwood to undertake this work, without prejudicing the reliability of
electricity supply. Such a situation cannot be relied on to occur in the
future.
It remains to be seen whether the present work on Hazelwood does result in
the extension of the plant's life to the thirty-five years hoped for. To date,
two units have undergone life extension works. Several years of operation
and continued monitoring of the condition of each unit will be required before
any definite indications will be available. The fact that two units underwent
costly "reconstructions" between 1981 and 1983, only to require further major
works five years later indicates that life extension is not a certain business.
Despite these uncertainties, it is obvious that SECV must continue to devote
considerable attention and resources to maximising the economic lifetimes of
its existing plants. Over the next three years, major works under PIP will
occur at all Latrobe Valley brown coal stations. Following these, the
Committee believes that a process of continuous review of plant condition
and remaining lifetime should be maintained, in order to detect deterioration
early, avert unexpected major failures where possible, arrange fuel supplies
for replacement plant and ultimately allow orderly planning of plant
retirement. The present notional retirement of the Hazelwood Power Station
at the turn of the century is clearly an issue that should be the subject of an
early, detailed economic and engineering review following the present life
extension works.
31
4.4 Research and Development into Electricity Generation from Brown Coal
Generation of electricity from Victorian brown coals presently involves
technology based on German experience modified to deal with the unique
properties of Latrobe Valley coals.
Brown coal in the Latrobe Valley has a very high moisture content
(over 6096). Considerable effort has gone into the development of plant
which can handle and burn this fuel in a reliable and efficient way.
Some of the particular utilisation characteristics of this fuel include:
Spontaneous combustion of stockpiled coal;
Auxiliary fuels (distillate or briquettes) are required for start-up
and to maintain flame stability at low load;
Coal needs to be partially dried by furnace gases prior to
combustion;
Coal needs to be finely crushed in milling plant and thoroughly
mixed with hot air to obtain efficient combustion;
Fouling of boiler tubes by ash deposits can be a major problem
with some Latrobe Valley coals;
Very large volumes of water vapour have to be removed with the
combustion products from the furnace;
Boiler furnace size is relatively very large;
Flue gas temperatures at the boiler outlet have to be kept high in
order to avoid condensation of the water vapour and consequent
corrosion problems;
A very low density fly ash must be removed from flue gases.
32
Plant design features have largely accommodated these utilisation
characteristics particularly in the later plant such as Loy Yang A; however,
it has resulted in the development of highly capital intensive plant. Evidence
to this Inquiry has revealed that the current level of capital intensity of
brown coal fired generation plant appears to significantly offset the
advantages of the abundance of, and relative ease of mining the raw fuel.
Electricity generation from other fuels, particularly black coal, may now
have significant overall cost advantages (see Chapter 12). If the capital
intensity of technologies for generating electricity from brown coal is not
reduced, Victoria may lose its apparent comparative advantage in electricity
generation, despite its very large primary energy reserves.
The scope for significantly reducing this capital intensity using the
technology currently employed is limited. Some of the concepts put forward
during the Inquiry for marginally improving the capital intensity were:
4.4.1 Boiler Plant
The use of pulverised dried brown coal (PDBC) as an auxiliary
fuel.
The briquettes currently used for auxiliary fuel have to be ground
up prior to use in the boiler system. Pulverised dried brown coal
would not require pre-grinding and thus eliminate the cost of the
mills currently used for this purpose.
Proven technology is available in Germany where PDBC is
produced in conventional briquette factory dryers. An
alternative means of production has been proposed which uses a
stand alone mill drying system similar to those used in Latrobe
Valley boilers. Production and use of PDBC using this system is
to be tried out by SECV during 1990.
The need to evaluate alternative auxiliary fuels to possibly
replace briquettes is becoming a presssing issue and is further
addressed in Section 11.1.5. This work should be given a high
priority.
33
The development of improved milling systems
SECV have calculated that application of their present knowledge
to the redesign of the current mill system will save 15-2096 of the
current capitalised life cycle costs of the mills which are about
$3.3 million per mill. Specific proposals include:
Improving the fan efficiency;
Pre-milling the coal prior to injecting into the
furnace gas offtake.
This is a proposal which will have the effect of immediate cost
reductions if applied to the next stage of Loy Yang.
proposals should be implemented.
The development of improved burners
These
Swirl burners have been investigated by SECV and are a
technically viable option. Major laboratory and prototype studies
were done in the 1970's and swirl burners were offered for
Loy Yang boilers by one tenderer following tests in Yallourn
Power Station. Further work on swirl burners is currently being
done in a burner test rig.
The recessed burners of the type used for Yallourn W2 and
Loy Yang have unique mixing characteristics which have been
examined in some depth. Their influence on overall furnace
flow/combustion/fouling is being investigated both in a physical
model in the Herman Research Laboratory and through a
collaborative research programme with Swinburne Institute of
Technology.
This work will improve SECV's ability to design burners for
specific coals and to determine if separation of the hot coal/air
stream by particle size is required. In conjunction with other
research work, this could lead to lower capital costs and increased
34
availability of future brown coal plants. This is an area where
SECV should place considerable emphasis.
Optimisation of boiler design
Currently, brown coal combustion chambers are some 2.5 times
the volume of equivalent black coal chambers. Significant cost
savings could be achieved if furnace height and volume were
reduced. This would raise furnace exit temperature and could
increase superheater fouling. Key elements of a current SECV
research project are aimed at:
Establishing the sensitivity of ash fouling to gas
temperature;
Investigation of combustion modification and use of
additives as a means of fouling control;
Investigation of the possible use of water blowers in
superheaters - their effectiveness and influence on
superheater tube integrity.
There is potential for reduction in furnace cross-section if the
combustion system can be optimised so as to minimise furnace
wall fouling and slagging. Investigations of the effects of
changes to furnace aspect ratio, burner positioning, degree of
separation firing and means of keeping burner jets and hence ash
from impinging on the furnace waHs are to be conducted by SECV
using simulation modelling techniques being developed in
conjunction with Swinburne Institute of Technology. Considerable
emphasis should be placed on this work as it is fundamental to
improving the design of brown coal fired boilers.
35
4.4.2 Coal Winning Techniques
The Union submission suggested that the amount of coal extracted from a
particular open cut could be maximised if much more cost effective and
flexible coal-winning techniques were used, including the possible
interconnection by coal transfer systems of selected open cuts. It was
suggested that this would allow maximum use of existing infrastructure. This
possibility should be further reviewed.
4.4.3 Precipitators and Ash Handling Plant
The Union submission suggested that further work was required to optimise
the design of precipitators in order to reduce corrosion and to improve the
operation of precipitator ash handling plant. This should be further
investigated.
4.4.4 New Coal Preparation or Combustion Technologies
New technologies which could have a significant impact on the capital
intensity of brown coal fired electricity generation in the longer term are:
Thermal dewatering of coal
Conventional pre-drying of brown coal for combustion processes
increases boiler combustion temperatures and aggravates fouling
problems. However, thermal dewatering (heating slurried coal
under presssure to approximately 300°C) removes most of the
inorganic materials from the coal. These materials are the cause
of fouling problems. The resulting dewatered coal could be used
in the form of a concentrated slurry suitable for injection into a
gas turbine or as an auxiliary fuel or main fuel for a conventional
boiler. Use of this fuel as the main fuel in a conventional boiler
would considerably reduce the size of the boiler for a similar
output and hence reduce its capital cost. This technique should
be further investigated.
36
Circulating Fluidised Bed Combustion (CFBC)
Preliminary studies indicate CFBC boilers are competitive with
conventional boilers with flue gas desulphurisation plant but not
when desulphurisation is not required. Desulphurisation is not
required for brown coal. However, the studies referred to were
carried out by overseas authorities and do not relate directly to
brown coal. Other benefits may occur when using brown coal.
The Electricity Trust of S.A. (ETSA) are having tests conducted
on Bowmans and Lochiel coal in a Lurgi 1.5 MW CFBC pilot plant
in Germany. These are to be followed by a Boiler Feasibility
Study.
Consideration should be given to conducting similar tests on
Latrobe Valley coals if the tests on SA coal indicate potential
benefits from using this technology.
Gasification
Integrated gasification combined cycle (IGCC) plants are
considered to be competitive with conventional plant based on a
German proposal for a 600 MW plant for brown coal. A 100 MW
demonstration plant at Cool Water, USA, has operated
successfully but not on brown coal. A German consortium is
investigating a possible 2 x 300 MW IGCC plant for Bow mans coal
in SA. This investigation includes gasification tests in the HT
Winkler pilot plant in Germany. The SA work should be kept
under review by SECV and a more detailed assessment of the
economics conducted. If these assessments are favourable, the
research required to evaluate Latrobe Valley coals should be
undertaken.
Coal Fired Gas Turbine
Investigations by the Commonwealth Aircraft Research
Laboratories in 1948-1971 showed that the main limitation to
37
using dri~d brown coal to fuel a "gas" turbine was the fouling and
erosion of the turbine's blades. With the advances in materials
technology and blade design to combat erosion and transpiration
cooling of blades to reduce fouling, a review of this technology is
warranted.
The possibility that gas turbines could be developed to operate
satisfactorily on brown coal should be further investigated. This
investigation should include the possibility of using coal that has
not been pre-dried, coal pre-dried using turbine exhaust heat and
thermally dewatered coal.
4..5 Specific Recommendations
The Committee recommends that:
Priority should be given to improving and maintaining the
availability of existing plant and extending its life where this is
economically viable. (Recommendation 12)
SECV should publish a yearly review of the performance and
condition of its generating plant, including:
Details of avallable and actual capacity factors
achieved, major planned and unplanned unit outages,
repair times and other statistics;
Targets and projections for the performance of existing
plant over future years, and explanations of any
significant deviation of actual performance from earlier
targets. (Recommendation 13)
3&
SECV should carry out and publish regular assessments of the
scope for improving the projected performance or expected
lifetime of existing plant through refurbishment or preventive
maintenance works, changed management or work practices, or
technological enhancements. (Recommendation 14)
Prior to commitments to the construction of new generating
plant, the interaction between existing plant performance and
lifetime, and the introduction of new plant should be reviewed.
This review should ensure that the fuel resources allocated to the
existing plant allow the maximum scope for performance
improvement and economic life extension. In particular, the
planned retirement date of the Hazelwood Power Station should
be subject to a detailed review prior to any commitments to
construct new power stations for service after 1999.
(Recommendation 15)
A more active Research and Development programme should be
initiated by SECV into improved techniques for the use of brown
coal in power generation. This should include:
Development of efficient methods for the production
and utilisation of pulverised dried brown coal;
Investigation of the potential for development of a
"dewatered" coal;
Development of improved milling, burner and
predpitator designs;
Optimisation of boiler designs;
Optimisation of coal winning techniques, utilisation
strategies, and equipment;
39
An on-going review of developments in the Circulating
Fluidised Bed Combustion and Integrated Gasification
Combined Cycle technologies;
A detailed review of the possibility that gas turbines
could be developed to operate satisfactorily on brown
coal.
(Recommendation 1 6)
40
CHAPTER FIVE
LARGE SCALE SUPPLY OPTIONS
5.1 Introduction
This chapter summarises evidence presented to the Inquiry on possible large
scale power supply options for Victoria beyond the mid-1990's, in terms of
their locations, technology, environmental impacts and costs. Key individual
large scale power supply options and considerations on their sequencing are
discussed in detail in later chapters of the report.
Small scale power supply options, typically of less than 10 MW capacity, are
discussed in Chapter 6. These small scale options may currently be
attractive because of factors such as geography (e.g. remote area power
supplies), energy efficiency (e.g. cogeneration), or environmental
considerations (e.g. wind, small hydro, and solar). It is unlikely that their
implementation in the decade covered by this Inquiry will have major impacts
on the choice or sequencing of the large scale supply options, although they
may well affect the timing of such options.
The Committee also considered the possibility that future large scale power
supply options could be based on technologies other than those currently in
use in Victoria. A wide range of new technologies is being developed
throughout the world and many of these are approaching the stage where
large scale implementation may become economically viable and hence
provide additional competitive options by the turn of the century. These
options are discussed, together with the need for research and development in
other chapters of this report. At this time, none has reached a stage of
development where a positive recommendation to include a particular option
based on a new technology in a future power supply sequence for Victoria
could be substantiated.
41
Therefore, the Committee has reached its primary recommendations on the
sequencing of supply options to follow Loy Yang B Units 1 & 2 in the decade
following the mid-1990's on the basis of large scale options using currently
proven technologies. The possibility that new power generation technologies
may become viable in the future has been taken into account in the
Committee's recommendations covering research and development, and
recommendations on processes that would enable early advantage to be taken
of future technological change.
5.2 Overview of Options
The following large scale power supply options were presented in evidence to
the Inquiry, classified here according to their primary energy source and
technology:
Latrobe Valley Brown Coal
These options were presented in SECV evidence and are based on
conventional pulverised fuel boiler technology. They would be similar in most
respects to recent Latrobe Valley power stations.
Loy Yang open cut
Morwell open cut
Yallourn open cut
Driffield area
42
2 x 500 MW option at Loy Yang B (Loy Yang B Units 3 & 4}
2 x 350 MW, 2 x 500 MW or 4 x 500 MW options at Hazelwood South
2 x 350 MW or 2 x 500 MW options at Morwell Siding
2 x 375 MW, 2 x 500 MW or 4 x 500 MW options at Yallourn F
220 MW or 320 MW redevelopments of (retired) Yallourn C/D station
4 x 500 MW or 8 x 500 MW options based on a new open cut.
These options represent the lowest potential cost brown coal options
available and would, in total, provide adequate additional power supply
capacity until well after 2010. Consequently, other "greenfield" brown coal
options described in earlier SECV reports have not been considered by this
Inquiry.
Oaklands Black Coal
CRA Ltd. (on behalf of the CRA/Mitsubishi Oaklands Joint Venture) and
SECV presented evidence on three black coal fired options based on Oaklands
coal. These options would be based on conventional pulverised black coal
boiler technology and would be of a similar design to recent NSW power
stations.
Oaklands power station -
Yarrawonga power station
Natural Gas
2 x 700 MW or 4 x 700 MW options located adjacent to the proposed open cut mine
2 x 700 MW option located near T elford, coal supplied by rail from Oaklands
SECV and BHP Ltd. presented information on gas fired generating options.
These would be supplied with natural gas from the Bass Strait fields, although
other sources of gas supply are possible in future years.
No firm locations for gas fired options were specified in evidence as it was
proposed that the precise location would be resolved by a more detailed
inquiry dealing with the specific environmental effects arising at the
alternative sites. Fuel, land, water, infrastructure and environmental
requirements for such options can be satisfied at a wider range of sites than
is the case for coal fired power stations. Sites would tend to be chosen for
either gas supply or electricity transmission advantages, provided that all
environmental requirements could be met.
43
Notional sites used by SECV for comparative purposes were:
Longford
Latrobe Valley
South-east of Melbourne (e.g. Tyabb or Carrum)
North-west of Melbourne (e.g. Donnybrook or Sydenham)
North-west of Geelong (e.g. Moorabool)
Siting of individual gas turbine units at existing SECV facilities
(e.g. transmission terminal stations)
Possible technologies and station capacities were:
Gas turbines
Combined cycle
Steam cycle (gas fired boiler)
Hydro-electricity
500-2000 MW in 500 MW "blocks" distributed siting of 100 MW units
500-2000 MW in 500 MW blocks
500-1000 MW in 500 MW units
SECV has identified larger hydro-electric options on the following river
systems:
Kiewa - options for extension of existing scheme providing additional 120 MW (150 GWh/yr) or 200 MW (330 GWh/yr)
McAJister 40 MW (60 GWh/yr) option
Mitchell 55 MW (80 GWh/yr) option
Mitta Mitta 20 MW (40 GWh/yr) or 40 MW (80 GWh/yr) options
Rub icon options for redevelopment of existing 13 MW, 80 GWh/yr run of river scheme to provide an additional 12-16 GWh/yr (no extra capacity) or additional 31 MW, 12-16 GWh/yr and storage (peak load) capability.
44
During an inspection of the Snowy Mountains Hydro-electric Scheme by the
Committee, officers of the Snowy Mountains Hydro-electric Authority
informed the Committee that no cost effective and environmentally
acceptable developments appeared feasible in that system in the period under
consideration, with the possible exception of the Yarrangobilly pumped
storage scheme (see below).
Pumped Storage
Previous SECV studies of pumped storage developments included a 500 MW,
30-40 hour storage scheme at Trawool (near Seymour). The Snowy Mountains
Hydro-electric Authority has undertaken preliminary desk studies of a
1000 MW 10 day storage scheme, Yarrangobilly, utilising the existing
Tantangara and Talbingo reservoirs. Pumped storage schemes are net
consumers of energy whose value lies in the ability to store lower cost off
peak electricity and generate at times when high fuel cost sources would
otherwise be required.
Interstate Contract Supply
Victoria's electricity system is connected with that of NSW as a result of
shared access to the Snowy Mountains Hydro-electric Scheme. An extension
to provide interconnection with South Australia is planned for 1990. An
interconnection between the mainland States and Tasmania is technically
feasible. The main uses of the existing Victoria/NSW interconnection (other
than for carrying each State's Snowy energy entitlement) and the justification
for its planned extension to South Australia are short term, non-contractual,
"opportunity" energy interchange which minimises the hourly operating costs
of the combined State systems, and the sharing of reserve generating plant
which increases supply reliabHity. However, large scale interstate contract
supplies would be feasible with appropriate transmission reinforcements.
Supply to Victoria from an Oaklands Power Station could represent one
example of such an arrangement.
Interstate transfers and contract supplies are discussed separately from other
supply options in Chapter 12 of this report.
45
~.3 Location of Options
Figures 5.1, 5.2 and 5.3 illustrate the location of the options listed above.
Definite sites for a Yarrawonga Power Station and for gas fired options were
not specified in the evidence given to the Inquiry.
~.4 Status of Evidence on Options
Evidence before the Inquiry on the impacts of future supply options,
particularly the effects of alternative sequences of these options, has been
complex and voluminous. The consistency and usefulness of this evidence in
describing the effects of the alternative sequences is dependent, in the first
instance, on the basic information presented on individual supply options. It
is important that information on the costs, workforce requirements,
reliability, efficiency and environmental impacts of each option is provided
on a comparable basis and as a result of appropriately detailed studies. In
view of the Inquiry's strategic nature and medium to long term focus, it was
recognised that the level of detail to which each option has been investigated
and described need not be as high as would be required if immediate
investment decisions were necessary, and that some changes in the data
presented are inevitable over time.
Taking as one example the information provided on the capital costs of each
option, the Committee accepts that in most cases cost data have been based
on preliminary or conceptual designs rather than a detailed estimate. This
level of accuracy is quite adequate for establishing the cost relativities of
options. However, some changes from the costs presented would be expected
when more detailed designs, the effects of foreign exchange variations,
tender market conditions and site investigations were fully taken into
account. The preparation of detailed cost estimates would certainly be
required prior to the government giving approval to proceed with any option.
During the early part of the Inquiry, it became apparent that estimates of the
cost of the possible Oaklands developments provided by SECV and CRA were
significantly different.
46
::!l ~~nHm
C)
~ j Mildura
1'11 i ~ .... i
i i I
t""
~ I
g z
..j::>o ~ .......,
~ ~ I
" VI I
~ I
t"" I -< 0
I
8 I
z VI
z < .... Q ~ >
~ LEGEND
• THERMAL POWER STATION
C HYDRO POWER STATION
t1 TERMINAL STATION
TRANSMISSION LINES
• SITE OF POWER STATION OPTIONS
..... , \.SNOWY \sCHEME
' I "- I
e MlTTA MlTTA RIVER
.... ..... .,
• MACALISTER R~lVER ·,,
MITCHELL RIVER • 0
./Lakes Entrance ~Traralgon / '-------'\""\ _ ~.LO.._ . • LONGFORD
~ ~~ YAllOUIIN NORTH
YAUOUMrsf G) YAI.lDIIIIII w ,. I
~ ~ \11 N
.;:. .... t"' (X)
~g
IWIIWOOOrs
ffi~ ~
t"'Q 2iZ ~~
® D''tl I'TIQ <~
® F=, t"'CII ~"~'~c -<., .,
t"' -< 0 g z VI
~)
~ ~r~ ~~i ~ 'j\\1>
IOYU"G A OPI"CUI~
IOY U"G. PS ~
IOY Ylll1!11 I II(J ®
LEGEND
(£) YAllOURN F
I I f J 4 '''" ® MORW!ll SIDING IICAII ® HAZEl WOOD SOUTH
@ lOY YANG 8 UNITS 3 6:.
® DRIFFIELD
FIGURE 5.3
------~r---------1~~
8£RRIGAN
I I
8£NALLA
l -1 i --j
I i L -]
I I I
LOCATION OF POSSIBLE SITES FOR POWER STATIONS BASED ON OAKLANDS COAL
49
CRA estimates were derived from two sources. In the first instance, CRA
had appointed consultants to prepare a feasibility study for an Oaklands coal
mine and power station which included cost estimates for the power station
based on the consultants' "reference design" (of which there are many
operating examples, mostly in the USA). In addition, CRA appointed the
Electricity Commission of New South Wales (ECNSW) as consultants to
prepare cost estimates for the 11power station island" section of the project
based on appropriate adjustments to the design of its recently completed
4 x 660 MW Bayswater Power Station.
SECV had access to ECNSW's cost data on the Bayswater station and used
these as the basis for preparing a "check estimate11 of the Oaklands costs.
The Oaklands cost estimates prepared by CRA and SECV initially differed by
19%. Discussions between SECV and CRA, with the participation of the
Committee's staff, resolved a number of differences on elements of the cost
estimates. However, the resulting revised estimates were still at variance by
some 9%. In an attempt to avoid unnecessary confusion during the later
stages of the Inquiry, the Committee requested that evidence describing the
effects of alternative sequences of these options, should be based on a
"compromise" set of estimates defined by the Committee. These estimates
were intermediate in value to the two revised estimates. The use of the
estimates defined by the Committee did not affect the broad cost relativities
between Oaklands and other supply options. It was also apparent that the
relatively very small differences between the overall estimates for the cost
of energy supplied from either Loy Yang B Units 3 &: 4 or a half share in an
Oaklands project were almost entirely related to the different assumptions
made by the various parties. The potential for variation in more detailed
future estimates of the capital and operating costs of Oaklands (and of all
other options) has been recognised in the Committee's recommendations.
Natural gas and Oaklands black coal would be supplied to power stations
under commercial contracts not yet negotiated. For the purposes of the
Inquiry, participants used a range of fuel prices within which the negotiated
prices would probably fall. Again, the Committee recognises the potential
for actual negotiated prices to lie outside the notional ranges adopted, or for
50
negotiations to fail completely, and has made recommendations allowing for
these possibilities.
During the course of the Inquiry, SECV made the point that the costs for
Loy Yang B Units 3 & 4 were based on the costs for Loy Yang A.
Considerable cost overruns occurred during the early stages of this project
which resulted in a review of these costs being initiated by the Government
and a greatly improved management and cost control structure being
implemented. SECV claim that their estimates for Loy Yang B Units 3 & 4
based on this experience are now very accurate and that costs will be
contained during the course of construction.
SECV indicated that as a result of the July 1987 annual review, the original
capital cost estimates for Loy Yang B Units 3 & 4 could be reduced by
$113 million from those originally given to the Committee in Aprill987. The
SECV also indicated that a review of expected operating and maintenance
costs was being conducted jointly with the Unions.
5.5 Option Costs and Workforces
Tables 5.1 and 5.2 show the basic costs and workforce requirements
associated with the large scale supply options described in this chapter. The
following items are shown:
Capital cost - Cost associated with the construction of each
option and its supporting infrastructure, including direct costs,
overheads and contingency sums. Interest during construction is
not included. For brown coal fired options only, fuel supply (i.e.
coal mine) capital costs are included.
Operating and maintenance cost - Direct and overhead costs of
annual operation and maintenance. For brown coal fired options
the incremental coal mine operating costs associated with each
option are included. For black coal and gas fired options the cost
of purchased fuel is not included.
51
Fuel cost - The cost per unit of energy of purchased fuel (black
coal or gas).
Transmission cost The capital cost of transmission works
required to connect each option to the main transmission system.
Unit capital cost The capital cost and transmission cost of
each option divided by its generating capacity.
Unit operating and maintenance cost - The annual operating and
maintenance cost divided by the generating capacity of each
option.
Construction worker-years - The total number of worker-years
required for construction of the option (on-site employment only).
Peak construction workforce - The highest number of on-site
jobs over the construction period of the option.
Operations workforce The eventual size of the workforce
required to operate the option, including maintenance workers
and, for brown coal fired options only, additional workers required
in the open cut coal mine.
52
TABLE .5.1
Capital Option Capacity Cost
(MW) ($M)
LA TROBE VALLEY BROWN COAL FIRED OPTIONS
Loy Y ang open cut
- Loy Yang B Units 3 & '+ 1000 1236
0'1
w Morwell open cut
- Hazelwood South 700 1.511 1000 1742 2000 3.536
- Morwell Siding 700 1.524 1000 17.5'+
Yalloum open cut
- Yal1ourn F 7.50 1.513 1000 1697 2000 3464
- Yallourn C/D 220 639 (re-development) 320 72.5
Driffield 2000 3661 4000 7247
LARGE SCALE SUPPLY OPTIONS
COST DATA
Operating and
Maintenance Fuel Cost Cost
($M/yr) ($/GJ)
(Note 1) (Note 2)
'+0 0
.57 0 68 0
119 0
.57 0 67 0
62 0 67 0 94 0
29 0 30 0
136 0 200 0
Unit Unit Transmission Capital Operating
Cost Cost Cost ($M) ($/kW) ($/kW /yr)
(Note 3)
0 1236 '+0
.5 2166 81
.5 1747 68 8 1772 60
16 2200 81 16 1770 67
24 2049 83 24 1721 67 42 17.53 47
n/s. 290.5 132 n/s. 2267 94
19 1840 68 n/s. 1812 .50
TABLE 5.1 (Cont'd)
Operating and Unit Unit
Capital Maintenance Fuel Transmission Capital Operating Option Capacity Cost Cost Cost Cost Cost Cost
(MW) ($M) ($M/yr) ($/GJ) ($M) ($/kW) ($/kW/yr)
OAKLANDS BLACK COAL FIRED OPTIONS (Note 4) (Note 5) (Note 6)
Oak1ands 1400 1277 33 0.8-1.0 ) 187-249 1046-1090 24 2800 2300 57 0.8-1.0 ) 888- 910 20
<.n (1400 MW to ~ Victoria)
Yarrawonga 1400 1430 34 1.1-1.3 219 1178 24
NATURAL GAS FIRED OPTIONS (Note 7) (Note 8)
Gas Turbine 500 274 5 2-3 5 558 10 1000 497 10 2-3 7 504 10 2000 (No separate estimate)
Combined Cycle 500 (No separate estimate) 1000 889 8 2-3 7 896 8 2000 (No separate estimate)
Steam Cycle 500 (No separate estimate) 1000 1034 13 2-3 8 1042 13
TABLE .5.1 (Cont'd.)
Operating and Unit Unit
Capital Maintenance Fuel Transmission Capital Operating Option Capacity Cost Cost Cost Cost Cost Cost
(MW) ($M) ($M/yr) ($/GJ) ($M) ($/kW) ($/kW/yr)
HYDRO-ELECTRIC OPTIONS
Kiewa (extension) 120(150 GWh) 228 0.1 0 n/s. 1900 0.8 200 (330 G Wh) 542 0.4 0 n/s. 2710 2
U'1 McAlister 40( 60 GWh) (Not estimated - total costs similar to 120 MW Kiewa Scheme) U'1
Mitchell 55( 80 GWh) (Not estimated - total costs similar to 120 MW Kiewa Scheme)
Mitta Mitta 20( 40 GWh) (Not estimated - total costs similar to 120 MW Kiewa Scheme) 40( 80 GWh) (Not estimated - total costs similar to 120 MW Kiewa Scheme)
Rub icon 0(12-16 GWh) > 100 n/s. 0 n/s. n/a. n/a. (re-development} 31 (12-16 GWh) c. 250 n/s. 0 n/s. c. 8000 n/a.
PUMPED STORAGE OPTIONS
Victorian 500MW n/s. n/s. n/a. n/s. > 1000 n/a. (e.g. Trawool} (30- 40 hours)
Yarrangobilly lOOOMW ( 10 days)
n/s. n/s. n/a. n/s. c. 1500 n/a.
(J'l
0"1
TABLE .5.1 (Cont'd)
NOTES: n/s. = not stated; n/a. = not applicable.
1. Operating and maintenance costs for brown coal options include the cost of auxiliary fuel and an effective 'fuel cost' component for open cut operations. These costs would vary depending on the utilisation of the station. Operating costs would also vary depending on the status of other power stations supplied from the same open cut. Figures shown are for base load operation and are lifetime averages assuming eventual retirement of existing stations sharing open cuts.
2. Fuel costs for brown coal fired options are not available as separate items. The open cut operating and capital costs are included in the individual power stations costs.
3. Spare Latrobe Valley-Melbourne transmission capacity exists to accommodate a further 1000 MW of generation after Loy Yang B Units 1 &: 2. Transmission increments costing $.50M-80M would probably be required to accommodate a subsequent Latrobe Valley option. However, this cannot be attributed to a particular option independently of its sequencing. The costs shown are for connection of each brown coal option to the Latrobe Valley end of transmission system.
11.
.5.
6.
7.
&.
9.
to.
Black coal option operating costs do not include transmission maintenance costs, coal costs, or the cost of auxiliary fuel.
Black coal fuel price ranges include auxiliary fuel (e.g. oil or gas) costs. The ranges shown are equivalent to $111/t-$17/t and S20/t-$23/t coal prices at Oaklands and Yarrawonga respectively.
Transmission from Oaklands or Yarrawonga for a Victorian supply of 1400 MW could be at 330 kV or .500 kV. The range of Oaklands transmission costs is for both voltages while the Yarrawonga figure is for .500 kV transmission.
Gas turbine and combined cycle operating and maintenance costs would vary considerably with load factor. Figures shown are for moderate utilisation.
Transmission costs for gas options assume that sites would be adjacent to existing main transmission facilities.
All costs are expressed at June 1986 price levels.
Source: SECV and CRA submissions and supporting documents.
TABLE .5.2
Option
LARGE SCALE SUPPLY OPTIONS
WORKFORCE REQUIREMENTS
Construe- Construe- Peak tion tion Construction
Capacity Period Worker Employment (MW) (years) Years
(Note l)
LA TROBE VALLEY BROWN COAL FIRED OPTIONS
(Note 2) Loy Y ang open cut
- Loy Yang B Units 3 & 4 1000 5+3 5015 1100
Morwell open cut
- Haze1wood Sth. 700 7+3 4490 950 1000 7+3 5385 1200 2000 (Not estimated)
- Morwell Siding 700 7+3 4490 950 1000 7+3 5385 1200
Y allourn open cut
- Yallourn F 750 7+3 4450 950 1000 7+3 5435 1200 2000 (Not estimated)
- Yallourn C/D re-development 220 n/s. n/s. 500
320 n/s. n/s. 600
Driffield 2000 (Not estimated) 4000 9+7 22450 2800
OAKLANDS BLACK COAL FIRED OPTIONS
Oaldands 1400 (Not estimated) 2800 5+5 9460 1840
(1400 to Victoria)
Yarrawonga 1400 7+2 6000 1600
57
Operations Workforce
(Note 2)
624
800-ll60 800-1220
800-1160 800-1220
800-1230 800-1300
600-900 600-900
3050
665
350
TABLE .5.2 (Cont'd.)
Construe- Construe- Peak tion tion Construction Operations
Option Capacity Period Worker Employment Workforce (MW) (years) Years
NATURAL GAS FIRED OPTIONS (Note 3)
Gas Turbines .500 1. .5+ • .5 n/s. 400 18 1000 1..5+ n/s. 400-600 26 2000 (Not estimated)
Combined Cycle .500 (Not estimated) 1000 3+ n/s. 600-900 47 2000 (Not estimated)
Steam Cycle .500 (Not estimated) 1000 .5+ n/s. n/s. 200
(n/s. = not stated)
Notes:
1. Construction period expressed as years before first operation of first unit + years after first operation of first unit.
2. Construction and operations workforces for brown coal fired options include additional workforce numbers in existing open cuts, and would vary with the status of existing power stations fed from shared open cuts. Construction and operations workforces for black coal fired options do not include mine personnel.
3. Data not available for length of construction period after first operation of first unit for gas fired options.
4. Source: SECV and CRA submissions and supporting documents. (Driffield data from 1981 EES.)
.58
TABLE 5.3
RELIABILITY AND ENERGY EFFICIENCY OF DIFFERENT TYPES
OF LARGE SCALE SUPPLY OPTIONS
Reliability (Available Energy Used in
Types of Capacity Efficiency Station Option Factor) (Thermal) Losses
% % %
Latrobe Valley
Brown Coal Fired 75 32-34 8
Oaklands
Black Coal Fired 80 36 6
Gas Fired
- Gas Turbines 85 30 0.5
- Combined Cycle 85 42 1.5
- Steam Cycle 85 39 5
Hydro-electric 95-99 n/a. 0
Pumped Storage 90 (Note 1) 0
Notes: 1. Overall efficiency of pumping and hydro-generation cycle is about 60-70%.
2. Source: SECV and CRA submissions and supporting documents.
59
.5.6 Reliability and Energy Efficiency of Options
The various types of large scale supply option considered by the Inquiry have
inherent differences in reliability and energy efficiency. Table 5.3 shows the
expected reliability and efficiency of each type of option, according to the
following definitions:
Reliability
This has been expressed as the available capacity factor
achievable by each type of option. The available capacity factor
is the ratio of the maximum energy that could be generated in a
given period by a particular option, allowing for scheduled
maintenance and unscheduled breakdowns, to the total energy
that would be generated in the same period if the option operated
continuously at its rated capacity with no breakdowns and no
stoppages for maintenance. It should be noted that energy
production from hydro-electric plant is not limited by reliability,
but by the availability of water. This is not taken into account in
the calculation of available capacity factor.
Energy Efficiency
This is the ratio of the electrical energy generated to the heating
energy input as fuel (for coal fired and gas fired stations).
Used in Station Losses
This is the proportion of rated electrical output lost in operating
power station auxiliary equipment. Both available capacity factor
and energy efficiency for each type of option are given in terms
of the total electrical energy generated, but the actual energy
available to the system is reduced by power station losses.
60
5.7 Environmental Impacts Common to Large Scale
Power Supply Options
All large scale electricity generation options have significant environmental
impacts. The major impacts of the options presented to this Inquiry are first
discussed in terms of features common to each type of option, then specific
issues raised by individual options are examined.
Coal Fired Options
Brown coal and black coal fired power stations are essentially similar in
terms of their environmental impacts. Combustion of coal in power station
boilers produces large quantities of exhaust gases including particulates (ash
and dust) and acid-forming gases such as oxides of sulphur and nitrogen.
Australian environmental protection authorities generally apply strict limits
to these particulate and oxide emissions and require the installation of such
equipment as is necessary to reduce emissions to the limits imposed. The
costs of emission control measures are reflected in the capital and operating
cost estimates for the coal fired options presented to the Inquiry. Australian
coals are considerably lower in sulphur content than overseas coals and "acid
rain" has not been a problem associated with coal fired power generation in
this country. Nevertheless, the possibility of its occurrence should be
reviewed during environmental impact assessment of future coal fired
stations.
Coal combustion also generates large quantities of carbon dioxide which is
recognised as a major contributor to the "greenhouse effect". However,
there are no controls world-wide on carbon dioxide emissions and, as
discussed in Chapter 3, scientific debate continues on the implications of the
greenhouse effect. If it becomes necessary or desirable to limit such
emissions in future, it seems probable that energy conservation and
renewable energy sources will increase in value.
Steam cycle power stations must reject large quantities of low grade heat to
the environment and generally depend on a cooling water system to do so.
Where large quantities of water are readily ayailable (e.g. at coastal sites) a
"once through" cooling circuit is used, but where water supply is more limited
61
and expensive, a recirculating system and evaporative cooling towers are
used. Where water supplies are even more limited (South Africa is an
example} higher cost "dry cooling" is an option, but one which so far has not
been used in Australia. Again, the capital and operating costs of water
supply and the cooling system are incorporated in the estimates for the
options presented to the Inquiry. Nevertheless, cooling systems for different
options will have differing effects on the environment, both through
consumption of water from stream or groundwater systems and through
disposal of cooling "purge" water.
Open cut coal mines occupy large areas of land and require the storage of
correspondingly large quantities of overburden, particularly during their early
years of development. Their land use and visual impacts are significant on a
regional basis. Water management in open cut mining is essential to avoid
far reaching environmental effects. On this basis, there is some presumption
in favour of maximising the use of existing open cut mines before developing
new mines as fuel sources.
Disposal of ash from coal combustion can present environmental problems if
not properly handled. However, there are not expected to be difficulties with
the options before this Inquiry.
The visual impacts of large coal fired power stations are unavoidable but the
extent of the impact is a function of each site's relationship to the
surrounding landscape and communities. None of the options presented to
this Inquiry is considered inappropriate on this basis. Similar considerations
apply to noise impacts.
Natural Gas Fired Options
Natural gas is generally regarded as the cleanest-burning fossil fuel and gas
fired power stations present fewer environmental difficulties than other
forms of thermal power generation. As with all fossil fuels, large quantities
of carbon dioxide are produced. However, the quantities of carbon dioxide
are considerably less than those produced by burning an equivalent amount of
brown coal. Some emissions, in particular oxides of nitrogen, may need to be
limited by control measures such as water or steam injection.
62
Combined cycle and steam cycle plants would require significant quantities
of cooling water and the disposal of saline cooling tower purge and boiler
water. The associated environmental impacts would be similar in nature to,
but smaller in magnitude than those of coal fired stations. Visual impacts
would be greatly reduced in the case of gas turbine and combined cycle plants
due to smaller size and height but similar to coal fired stations in the case of
steam cycle plant. Noise impacts would also be reduced relative to coal fired
stations.
Hydro-electric and Pumped Storage Options
The major environmental impacts of hydro-electric and pumped storage
options are due to the size of the water storages required and the disruption
to river systems caused by their construction and operation. Where options
could be located at existing water storages, these impacts would be greatly
reduced. As net consumers of energy, pumped storage schemes would also
result indirectly in the consumption of additional fossil fuels •
.5.8 Environmental Impacts of Individual Options
In thi$ section, specific environmental impacts of individual power supply
options are considered, where these are likely to require special control
measures or raise issues bearing on project selection.
Latrobe Valley Brown Coal Fired Options
The environmental impacts of Loy Yang B Units 3 & I+ have already been the
subject of formal public review prior to the entire Loy Yang project being
approved by Parliament in 1976. However, the Committee notes that there
have been some environmental problems with the Loy Yang project to date;
in particular surface water discharges have affected Traralgon Creek. More
attention to controlling these problems would enable Loy Yang B Units 3 & 4
to be constructed and operated within the approved discharge limits.
The Y allourn F options would require the opening of the Maryvale open cut
north of Morwell. Even in the absence of further development at Yallourn,
63
the Maryvale field may be opened after about 2005 to provide coal for the
extension of the life of the existing Yallourn W station beyond 30 years.
Other coal supply options might be feasible (but probably more costly) for
this life extension. As noted above, the environmental impacts of open cut
coal mines are considerable. Attention would also have to be given to the
noise and visual impacts of a Yallourn F station due to the proximity of
Yallourn North township, to discharge of effluents (including cooling tower
purge water) to the Latrobe River, and to buffer zones separating the
Maryvale mine from the Morwell township and Australian Paper
Manufacturers' Maryvale Mill.
Options based on Morwell open cut would not require the immediate
development of further open cut coal mines, but could be limited to 1000 MW
by the exhaustion of economically winnable coal in the Morwell open cut,
particularly if the life of Hazelwood Power Station is extended.
Alternatively, a 2000 MW development at Hazelwood South would probably
require coal supply from a new open cut mine in the later part of its lifetime.
A Driffield Power Station would involve the development of a new open cut
mine west of the Morwell River, as well as extensive flood control works on
surrounding streams. A 4000 MW development at Driffield would eventually
require a major diversion of the Morwell River. (See the 1981 Driffield
Environmental Effects Statement and the 1983 NREC Report on the Morwell
River Diversion.)
As a final point the first 1000 MW of new plant constructed in the Latrobe
Valley after Loy Yang B Units 1 &: 2 can be accommodated without any
augmentation of the high voltage transmission system between the Valley and
Melbourne. Increases in the Latrobe Valley generating capacity beyond this
initial 1000 MW will require augmentation of this system, and this in turn will
require transmission works within the outer Melbourne metropolitan region,
possibly including the construction of new 500,000 volt overhead transmission
lines. These transmission lines would have visual and land use impacts and
significant community concern might be expected. Prior to any new high
voltage transmission lines being constructed between the Latrobe Valley and
Melbourne, a further public evaluation of the long term development of the
total high voltage transmission system should occur.
64
Oaklands and Yarrawonga
Oaklands would involve establishment of a large scale open cut coal mine and
power station in a rural area. Careful research and evaluation will be
required to ensure that acceptable environmental impacts are achieved. A
particular area of concern is that of water supply and disposal. CRA's
feasibility study proposes a relatively novel method of water management
with the supply being groundwater from mine dewatering and a dedicated
borefield, and disposal of excess mine water and cooling tower purge water
via re-injection to a saline aquifer. Studies of this proposed scheme by CRA
consultants and the NSW Department of Water Resources are continuing.
Water supply and disposal would also be a major environmental factor at
Yarrawonga. Coal supply to Yarrawonga by rail from Oaklands would involve
transportation of approximately 2,500,000 tonnes of coal per year on the
Oaklands-Yarrawonga rail line. Currently the line carries around
200,000 tonnes of grain annually. An increase in rail traffic of this
magnitude would have significant impacts, particularly as the railway line
passes through built up areas of Mulwala and Yarrawonga.
Oaklands or Yarrawonga Power Stations would transmit electricity to the
Victorian grid via new 330,000 volt or 500,000 volt power lines. No definite
routes have been proposed in evidence, but the new lines would probably
terminate at one of the SECV terminal stations north or west of Melbourne
and could cause alterations to the present outer metropolitan transmission
network. Transmission line routes and consequential environmental impacts
would have to be considered in a decision to take supply from Oaklands or
proceed with a Yarrawonga project. However, the deferment of Latrobe
Valley to Melbourne transmission works allowed by supply from Oaklands or
Yarrawonga would have environmental advantages.
65
Natural Gas Fired Options
The environmental impacts of gas fired power stations would be site specific.
Of the notional locations used by SECV, those near the Melbourne
metropolitan area would require more stringent environmental controls on
exhaust and noise emission and visual impacts due to the higher population
densities. Steam cycle and combined cycle options would be more difficult to
locate than gas turbines due to their cooling water requirements.
It is possible that the alternatives of siting a gas fired power station in the
Latrobe Valley, close to Melbourne or in the Geelong region could have
significantly different effects on the future need for additional high voltage
transmission lines, both between the Latrobe Valley and Melbourne and
through the outer suburbs of Melbourne. This will need to be considered when
selecting the most appropriate site for gas fired options.
Hydro-electric and Pumped Storage Options
The larger hydro-electric options identified by SECV would all require new
dams and storages and have significant environmental impacts as a
consequence. Schemes involving extension or redevelopment of existing
works might be considered to have slightly less serious impacts since
infrastructure such as transmission and construction access is generally in
place and the environment is already affected by existing hydro-electric
generation.
A new Victorian pumped storage scheme (e.g. Trawool) would involve
construction of large storages and have associated environmental impacts.
The Yarrangobilly scheme would use existing storages but require extensive
tunnelling with requirements for construction access and waste disposal.
Pumped storage schemes would cause high rates of water level change in
associated reservoirs which could have important physical and biological
impacts.
66
5.9 Preliminary Discussion of Options
As pointed out in Chapter 2, economic electricity generation requires an
appropriate mix of plant types, and the impacts of supply options and the
sequencing of their development should be considered from a wider
perspective than that of the supply system alone. For these reasons, it is not
appropriate to draw firm conclusions on supply strategies simply by
comparison of individual options. Nevertheless, some limited conclusions can
be drawn at this level.
Brown Coal Fired Options
It is evident that Loy Yang B Units 3 & 4 is the most attractive of these
options on cost grounds, as shown by its unit capital and operating costs
which are less than three quarters of any other brown coal fired option. This
option also has a shorter lead time and probably fewer environmental impacts
than any other brown coal fired option. These advantages are reflections of
the fact that Loy Yang was originally conceived as an eight unit development
and SECV has already constructed substantial project infrastructure to
support eight units.
Economies of scale in unit size lead to 2 x 500 MW options at existing open
cuts having unit capital costs over 20% lower than 2 x 350 MW and
2 x 375 MW developments or redevelopment of Yallourn C/D stations.
Operating costs would be similarly reduced. 4 x 500 MW options offer no
further capital savings per MW when compared with the 2 x 500 MW options,
but operating cost economies would occur, particularly at Yallourn F.
Arguments in favour of brown coal unit sizes smaller than 500 MW have been
raised in the past on the grounds of lower risk of over-capacity or
under-capacity and a more stable construction employment situation due to
closer timing of smaller units. Loy Yang A can be pointed to as a project
where an initially high rate of development has now given way to a decline in
construction employment, and resulted in current excess supply capacity.
However, the evidence presented shows that in addition to substantialJy
higher costs, smaller units have construction lead times no shorter than those
67
of large units and so would be subject to similar risks of over- or
under-capacity, given that the same total capacity would be committed for
construction in a given period. A better way to reduce risks is to commit to
smaller projects (e.g. 2 x 500 MW or 4 x 500 MW rather than 8 x 500 MW) and
programme construction flexibly.
From an environmental point of view, neither Loy Yang B Units 3 & 4 nor
Morwell options would require opening of a new open cut, whereas Yallourn F
and Driffield options would require immediate opening of new open cuts.
However, this aspect cannot be fully considered by comparing individual
options because open cut developments will also be affected by the
retirement or life extension of existing stations.
Oaklands Black Coal Fired Options
A 2800 MW (4 x 700 MW) power station at Oaklands would have significant
capital and operating cost advantages over 1400 MW options at either
Oaklands or Yarrawonga. The Yarrawonga option would be further penalised
by higher fuel costs due to the cost of transporting coal by rail. However,
the involvement or non-involvement of New South Wales in an Oaklands
project would be an important factor in determining which of these options
might be available to Victoria.
The unit capital and operating costs of black coal fired options are
significantly lower than those of brown coal fired stations. This is partially
a reflection of the lower moisture and higher energy content of black coal,
which reduces the size and complexity of the boilers and associated
equipment required for a given power output. However, fuel costs must also
be taken into account in comparing the costs of brown coal based and black
coal based generation.
Natural Gas Fired Options
Gas turbines have the lowest capital cost per unit of electrical output for any
of the options presented to the Inquiry. Combined cycle plant has a higher
unit capital cost, but operates more efficiently by converting heat from
68
gas turbine exhaust gases to electrical energy. Steam cycle plant is more
costly than combined cycle plant, less flexible in operation and construction
timing, and less fuel efficient. Further consideration of gas fired generation
should therefore be limited to gas turbine or combined cycle plant.
The short construction lead time of gas fired options, as well as their
flexibility of location and operation are also strategic advantages. However,
natural gas is usually a more expensive fuel than brown or black coal.
Hydro-electric Options
SECV's investigations of larger hydro-electric schemes were only
preliminary, but on the evidence presented to the Inquiry, none of the
identified schemes appears attractive on either economic or environmental
grounds. The high capital costs of dams, tunnels and aqueducts result in
effective energy costs many times higher for these schemes than for
generation from natural gas or coal. Each scheme (except redevelopment of
Rubicon) would involve extensive civil works within or adjacent to National
or State parks or proposed park extensions. With access to over 1500 MW of
existing hydro-electric capacity, the Victorian system would gain little
additional operational flexibility from installation of further hydro
generation.
The lower capacity extension of the existing Kiewa scheme, which would
involve a new water storage on the Pretty Valley branch of the East Kiewa
River, below the McKay Creek Power Station, new tunnels, and a new power
station upstream of Lake Guy, appears to be the most cost effective of the
identified options, but still quite uncompetitive in comparison with low
capacity factor operation of gas turbines. The other schemes identified
would produce more costly energy and would probably have less acceptable
environmental effects.
These larger hydro-electric options should not be further considered for
implementation in the decade beyond the mid-1990's, unless it can be
demonstrated that they would have significant economic advantages not
69
evident in the information provided to this Inquiry, and that their
environmental impacts would be acceptable given the size of any such
advantages.
Pumped Storage Options
Evidence provided by SECV on the possible role of large pumped storage
developments argued that the relatively high capital cost of this technology,
long construction lead times and its dependence on the availability of
significant quantities of low fuel cost generation during off-peak periods
made any potential financial benefit smaJI and uncertain. The financial
attractiveness of pumped storage schemes depends on substantial differences
between average peak and off-peak loads and on the relative costs of base
load and peak load generation. The Victorian system has relatively small
variations in the ratio of peak to off-peak load (i.e. a relatively high system
load factor) compared to, say, NSW, and SECV is undertaking tariff and
demand management measures aimed at improving or maintaining this
situation. Natural gas generation is a relatively inexpensive form of peak
electricity generation in comparison with the options available in systems
which do not have access to substantial gas reserves.
Several submissions to the Inquiry criticised SECV's arguments on the grounds
that SECV had not thoroughly investigated possibilities for lower cost pumped
storage developments (possibly using existing large reservoirs for lower
storage, or as part of multi-purpose water resource developments), that
SECV had not conducted up-to-date system simulation studies to evaluate
the impact of additional pumped storage on system costs and reliability, and
that the relatively low cost of gas fired peak generation is a temporary
situation.
Further information is required before pumped storage can be categorically
ruled out as a medium term supply option. In particular, it should be
established that there are no feasible, environmentaJly acceptable, lower cost
pumped storage options based on existing storages, and that the basis used by
SECV to assess the value of pumped storage in terms of system costs and
reliability is valid given the current and expected future plant/load mix.
70
.5.10 Cost of Delivered Power from Selected Options
On the basis of the cost estimates summarised in this chapter, the
Committee's research staff has derived a "Cost of Power Delivered to
Melbourne" index for a representative set of options. This index takes into
account the level and distribution in time of capital, transmission, and
operating costs, fuel prices and transmission losses, and is presented over a
range of capacity factors for four options in Figure 5.4. Supporting data is
provided in Appendix 7.
The results indicate that gas turbine options would have cost advantages at
lower capacity factor (peak/intermediate load) operation. Oaklands (half
share of 2800 MW) and Loy Yang B Units 3 & 4 exhibit similar costs over a
range of load factors and appear more economic than other options at high
capacity factor (base load) operation. Brown coal fired options other than
Loy Yang B Units 3 & 4, represented by Hazelwood South (2 x 500 MW) are
signficantly more costly than either Oaklands or Loy Yang B Units 3 & 4 •
.5.11 Conclusions
On the basis of initial economic comparison, there could be a role in the
future development of the Victorian electricity system for large scale supply
options based on brown coal, black coal and natural gas. A more detailed
analysis than that provided in this chapter is required to resolve decisively
the possible roles for and appropriate sequencing of these options. Additional
large hydro-electric developments and pumped storage schemes appear
unlikely to be economically attractive in the decade beyond the mid- I 990's,
particularly when environmental impacts are considered. However, some
limited further review of pumped storage options is seen to be warranted.
Interstate contract supplies, particularly from NSW, could have a role which
has not been addressed here, but is discussed in Chapter 12.
71
c w ~ w > ::J w c ~.c w~ ~X O' a..O u. 0 1-(/)
0 0
FIGURE 5.4 COST OF POWER DELIVERED TO MELBOURNE VERSUS CAPACITY FACTOR FOR REPRESENTATIVE OPTIONS
8
7
6
5
4
3
LOT YaneB Units:J & 4
I /
HIJJ!JSJwood Sorztb.
CIIJs t:arbines
Disootmt rate 8%
20 30 40 50 60 CAPACITY FACTOR (%)
72
70 80
Fual cost
$3/SJ
$2/SJ
$17/t
$14/t
It is apparent from comparisons of the kind in Figure 5.4 that future brown
coal fired options after Loy Yang B Units 3 & 4 suffer significant cost
disadvantages in comparison with black coal fired generation. This is a
matter of some strategic importance to Victoria, given its large reserves of
brown coal and paucity of black coal, and should be considered in light of the
State's economic strategy.
It is also apparent from the discussion in Section 5.8 that the eventual need
for, and location of, additional high voltage transmission lines will be
considerably affected by the mix and sequence of future power supply
options. Future review processes will need to consider these implications in
more detail •
.5.12 Specific Recommendations
Prior to any new high voltage transmission lines being constructed, a
further public evaluation of the long-term development of the
Victorian high voltage transmission system should occur. This
should be integrated with a review of the alternative demand and
supply side options and sequences available at that time, together
with consideration of environmental, health and safety issues.
(Recommendation 36)
SECV should carry out a further review of the possibility that
pumped storage options could be developed in association with
existing storages, in particular the Thomson and Dartmouth
Reservoirs. If feasible sites are identified, the capital costs of
their development should be estimated by expert feasibility studies
and they should be subjected to economic and environmental
evaluation. This evaluation should be carried out in a manner
similar to the evaluations of other major supply options presented to
this inquiry so that the value attributed to pumped storage in terms
of system costs and reliability is demonstrably valid given the
current and expected future plant mix and load profile.
(Recommendation 19)
73
CHAPTER SIX
SMALL SCALE SUPPLY OPTIONS
6.1 Introduction
This chapter discusses possible roles for small scale supply options in the
Victorian electricity system, outlines some of the relevant technologies and
opportunities for their implementation, and considers the place of small scale
options in supply planning strategies.
The supply options and technologies discussed in this chapter are classified as
small scale for either economic or technical reasons. Opportunities for
implementation of some options, such as smal.l hydro-electric generators, are
limited by the availability of sites and primary energy sources. Other forms
of generation, such as wind or solar power, could be developed on a large
scale either as central generating facilities or at many distributed sites (e.g.
households), but only at costs which are currently substantially higher than
those of the large scale options described in the previous chapter. This is not
to say that the relative costs of gene,rating technologies will necessarily
remain fixed and that the present economic distinction between large scale
and small scale options will be appropriate for all time.
6.2 Roles for Small Scale Supply Options
Despite being uneconomic for bulk power supply purposes in the short term,
small scale supply options can currently be considered for certain specialised
roles in the electricity supply system. These roles are discussed below under
the general headings of the efficient use of energy and capital resources, and
remote/isolated supplies.
Efficient Use of Energy and Capital Resources
There is a potentially large number of opportunities for generating electricity
on a limited scale as part of another productive process, or at sites where a
75
particularly favourable combination of resources exists. Generation of
electricity in these circumstances for supply to the grid (or to replace energy
that would otherwise be consumed from the grid) may enable an overall
improvement in society's use of energy or capital resources, in comparison
with a situation where all electricity is generated at large scale facilities
dedicated to this single purpose.
Cogeneration, the joint production of heat and electricity where both are
required for some commercial or industrial activity, is a well known example
of such an opportunity. Others would include small scale hydro-electric
generation at existing water supply storages, or the installation of a wind
generator at a particularly windy site.
Remote or Isolated Supplies
There are roles for small scale supply options in areas where connection to
the statewide grid is impractical or highly expensive. Diesel generators are
widely used in such situation, but renewable energy technologies, particularly
solar and wind generation, are becoming more attractive for such supplies as
the technologies develop and their costs decrease.
Some evidence given to the Inquiry indicated that where SECV provides new
connections to remote consumers from its supply system, the overall costs
may be greater than the direct connection costs recovered from the
particular consumer because of additional costs incurred in the overall
distribution network over a period of time. Further subsidisation may also
arise because the higher electricity losses incurred in supplying such
connections are not reflected in SECV tariffs, which are uniform across the
State (in accordance with government policy). In these circumstances, it
could be appropriate for SECV to promote stand alone systems as alternatives
to grid connection in remote areas.
6.3 Small Scale Options and Technologies
In this section, a range of possible small scale supply sources and technologies
are discussed. The range is not intended to be complete, nor the discussion
exhaustive.
76
Cogeneration
There is currently about 300 MW of installed, operating cogeneration
capacity in Victoria (this figure includes 170 MW at the Morwell Power
Station and associated briquette factory). The government and SECV
recently announced an "incentive" scheme to attract up to 150 MW of
additional cogeneration and renewable energy based private electricity
generation into the system under agreements to be signed before June 1988.
Key features of the scheme are revised standby and buy-back tariff
arrangements for generators of up to 10 MW. SECV electricity demand
forecasts allow for additional cogeneration of around 500 G Wh per year by
1995 and around 1000 GWh per year by 2001. There has been considerable
interest in the "incentives'' package and this may indicate that an increased
level of cogeneration may now be economically feasible. The potential for
such an increase should be assessed, following a review of the effects of the
"incentives" scheme and, if appropriate, further restructuring of SECV's
standby and buy-back tariffs should take place.
Emergency and Standby Generators
Modern high rise buildings, telephone exchanges, computer centres and other
facilities. requiring very high levels of eiectricity supply security often have
emergency generating facilities installed to maintain electricity supply in the
event of restrictions or blackouts. In principle, these generators could play a
larger role in electricity supply if they were more readily available for
operation during periods when the electricity generating system was being
stretched to capacity. Such periods can be expected to arise in any
generating system which is not over-capitalised. SECV planning, like that of
all generating authorities, is based on accepting some risk of supply shortage
due to combinations of high demand and plant failures. The basic criterion
for installing new plant on any generating system is to balance this risk
against the cost of providing spare or reserve generating capacity.
If firm arrangements could be made for the operation of emergency
generators during periods of potential energy shortage on the SECV
generating system, then SECV could possibly avoid or defer the installation of
some of its own central generating plant, while still achieving its chosen level
77
of reliability. At present, no such arrangements exist. The total installed
emergency generating capacity in Victoria is not known, but is probably of
the order of several hundred megawatts. Incorporation of even half of this as
a resource available to the generating system could represent an effective
additional use of capital. that has already been spent and avoid some further
expenditure of SECV capital.
Small Hydro-electric Generators
Recent studies by SECV and the National Energy Research Development and
Demonstration Council (NERDDC) have identified potentially economic,
small hydro-electric generation opportunities (less than 20 MW) at a number
of existing water storages in Victoria. One of these, a 5.6 MW scheme at the
Thomson Dam, is currently being constructed by the Melbourne and
Metropolitan Board of Works. It is understood that other previously
identified schemes have been proposed under the SECV /government
cogeneration "incentive" package described above.
Such schemes would have minimal environmental effects and can be more
cost effective than the large hydro schemes described in the previous
chapter, as there is no need to construct new water storages. Schemes
assessed by SECV as more favourable could produce up to 150 GWh per year
if aU proceeded.
The Alternative Technology Association drew attention to the fact that none
of the studies by SECV or sponsored by NERDDC has examined the possibility
that a large number of relatively small potential hydro projects with output
capacities as low as 50 kW could be developed and be economicaUy viable.
However, the Committee notes that the economic viability of such schemes
is very site specific and normally reqires that the generator site be close to
the electrical load because of the high cost of small scale electricity
transmission.
78
Wind Generation
As noted earlier, wind generation can have a role in remote power supply
applications. Grid-connected wind generation in Victoria has been under
investigation through a joint SECV /V SEC coastal wind monitoring
programme, and a demonstration 60 kW aerogenerator installed at Breamlea,
south of Geelong. While large scale wind generation in Victoria does not
appear to be economic given current costs, development of wind generation
technology is continuing throughout the world particularly where wind based
energy can substitute for energy produced from fuel oils. SECV estimates
that by 1995 wind generation may be contributing up to 3 GWh to the grid. In
the medium to longer term, grid connected wind generation could be one of
Victoria's more promising renewable energy options.
Solar Power
As with wind generation, solar electricity systems have current application in
remote power supplies. Grid connected solar generation is presently further
from being economic than wind power, although extensive development work
around the world is reducing costs. SECV has been involved in a number of
solar research and demonstration projects. Consultants are examining the
feasibility of a 50 kW grid connected solar photovoltaic generating facility
for installation in northern Victoria.
Other Renewable Energy Sources
These include tidal, wave, geothermal, and biomass generating technologies.
In the longer term, limited opportunities may be available for generating
small quantities of electricity economically from wave energy and through
the disposal of solid waste,
The opportunity to exploit either tidal or geothermal energy appear to be
limited by the relative availability of these forms of energy in Victoria.
79
6.• Supply Planning and Small Scale Options
Individual small scale supply options cannot be meaningfully incorporated in
strategic electricity supply planning. However, it is important that the
collective impacts of possible small scale supplies are adequately assessed,
since these may have some effect on the timing of future large scale plant
additions. For example, an additional 1000 GWh per year of cogenerated
electricity is equivalent to several months' output from a 500 MW base load
unit. Making firm arrangements for the occasional operation of private
emergency generators could lower (on a once-off basis) the amount of new
SECV plant needing to be installed in a given period to maintain a given level
of supply reliability.
With large scale supply options having long lead times, and considerable
uncertainty inherent in future forecasts of electricity demand, it is important
to retain flexibility in supply development programmes to enable adjustments
for the impacts of small scale supply options.
There is a potential dilemma in pursuing both large scale and small scale
options caused by the very different lead times of typical developments.
Once commitment to a large scale option is made, there is some risk that
development of 11too many11 small scale options could lead to expensive
over-capacity when construction of the large scale option is completed. On
the other hand, there are risks that opportunities for potentially economic
small scale options (or for whole classes of options) could be lost if these are
discouraged by the supply authority on relatively short-term considerations.
The governmment and SECV should take a long-term view on this sort of
problem, just as a long-term view is taken on electricity pricing.
For the purposes of this Inquiry, SECV planning has adequately addressed the
current potential of these small scale supply options, except in the area of
access to private emergency generation. However, the opportunities to
utilise cogeneration and private renewable energy based electricity
generation may increase, and the future potential contribution from these
supply sources will have to be carefully reviewed over the next few years.
Maximum economic flexibility in implementation of large scale options will
80
be important if the less predictable implementation of the smaller scale
options by bodies other than the SECV is to be accommodated.
Organisations and individuals with interests in developing these small-scale
options will, in general, be better placed than SECV to identify, implement
and operate specific opportunities, provided that sufficient information on
SECV buy-back and standby tariffs and connection requirements is available.
However, SECV should continue to encourage the development of these
opportunities through its direct involvement in research and demonstration
projects as well as maintaining a watching brief on overseas developments.
6 • .5 Specific Recommendations
SECV should consider stand alone power supply systems as an
alternative to extending the electricity distribution system into remote
areas. (Recommendation 38)
The Government and SECV should review the effects of the
cogeneration and renewable energy "incentives" package after a
suitable period has elapsed and, if appropriate, further restructure
SECV's standby and buy-back tariffs. (Recommendation 39)
SECV should investigate the possibility of making firm arrangements
for the operation of private emergency and standby generators during
periods of potential energy shortage on the interconnected generating
system. These investigations should consider the possible cost
advantages which might arise from such arrangements through
reduction in SECV reserve plant requirements. (Recommendation lj.Q)
SECV should significantly expand its involvement in research and
demonstration projects related to renewable energy based electricity
generating technologies. (Recommendation lj.l)
81
7.1 Introduction
CHAPTER SEVEN
MODELLING AND ANALYSIS OF SUPPLY
SEQUENCE IMPACTS
This Inquiry has been concerned with the assessment of supply options and
sequences for balancing supply and demand following completion of
Loy Yang B Units I &: 2. In reaching a judgement on the overall advantages
and disadvantages of those options or sequences, the Committee has
examined economic, social, financial, environmental and other impacts.
This chapter discusses how participants in the Inquiry have evaluated the
economic, social and financial impacts and brings together the Committee's
observations and conclusions in this area.
7.2 Scenario Modelling
A substantial part of the evidence to this Inquiry concerned itself with future
electricity supply and demand "scenarios". Scenario planning can be
characterised as the evaluation of numerous alternative plans or strategies
under a range of future sets of conditions (e.g. different economic outlooks}
by considering their overall effects during the time period in question. An
alternative to this approach is the traditional "single project" style of
analysis (of which the Driffield Environment Effects Statement is a typical
example in Victorian electricity planning}.
Two significant advantages of the scenario planning approach are:
Its capacity to evaluate strategies or sequences of decisions and
projects through the use of detailed modelling tools; and
Its flexibiJity in assessing a wide range of possible strategies and
assumptions about the future, allowing a better understanding of
factors such as risk and uncertainty.
83
For example scenario planning has provided the present Inquiry with the
ability to simultaneously consider the role for both new base load and new
peak load plant (e.g. Loy Yang B Units 3 & 4 and gas turbines). While "stand
alone" analysis, which provided the comparative electricity costs illustrated
in Figure 2.2, shows that each of these options is competitive in its
respective role, scenario analysis is able to provide information on the
appropriate mix of base load and peak load capacity and the implications of
different construction sequences and timing.
Scenario planning can be used in a very broad fashion, for example to
consider the implications of very different futures which might range from
high economic and energy demand growth to major recessions or
environmental bans on the construction of new fossil fuel burning power
stations. Some overseas energy organisations currently use scenario planning
this way.
Participants in this Inquiry used a much narrower form of scenario planning,
and concentrated on detailed modelling of the impacts of different sequences
of large scale power supply options under a restricted range of assumptions
about future electricity demand, the economic environment and technological
factors. A list of representative scenarios studied is contained in Appendix 10
and the alternative electricity demand forecasts appear in Figure 2.1.
Figure 7.1 represents in a simplified fashion the common modelling approach
used by SECV, CRA and BHP to support their evidence to the Inquiry on
future supply and demand scenarios. The functions of each of the models
shown are, briefly:
System model - Simulates the development of the electricity
generation system with a forecast demand growth to determine
system reliability, and the expansion plan - the required
magnitude and timing of new supply options and associated works
(e.g. transmission);
84
plant performanoe
load foreoasts
00 I (J1
sequenoe of regional
~~ly op ions impact 1-- employment. population projeotions
model I I I
I system model
L---- ____j '-Ions run marginal oost
~ generation option costs C 0 S t
FIGURE 7.1
fuel costs I model
eoonomia environment finanoial policies ----;
sales ------;
financial model
SIMPLIFIED DIAGRAM OF SCENARIO MODELLING APPROACH
tariff's
debt
rate of re tarn
Generation cost model - Uses the output of the system model,
and detailed cost data relating to the new supply options and the
existing generating system, to simulate the operation of the
electricity supply system and to determine the total financial or
economic costs involved in expanding and operating the
electricity generation and transmission system under the given
expansion plan;
Regional impact model - (SECV only) Uses the expansion plan,
together with workforce and expenditure data to indicate the
employment-related impacts of power station construction and
operation within regions;
Financial model - Takes the expenditure pattern for generation
and transmission and flows this through a model of the SECV
business and financial structure to estimate the ultimate impacts
on financial indicators including ·electricity tariffs, debt levels
and rate of return on assets.
7.3 Scenario Modelling Outputs and Analysis
The models illustrated in Figure 7.1 and described above produce a
substantial body of data - year by year data on energy produced, fuels
used, workforce employed, capital costs, operating costs, debt levels and
so on. These can be aggregated in meaningful ways to produce indicators
that allow decision makers to comprehend the relative impacts of
alternative scenarios. There is no single indicator that can completely
incorporate all of the data produced and be used to choose a "best"
scenario, because there is no objective definition of "best" - this depends
on the weight given by decision makers to each of the economic, social,
financial, environmental and other factors.
Nevertheless, there are certain more or less standardised analytical
techniques for evaluating economic, financial and social impacts in order
to focus more clearly on the trade-offs between scenarios. A number of
these have been used or recommended by participants in the Inquiry and
are discussed briefly below:
86
Cost Effectiveness Analysis
This concentrates on the direct economic costs, on a discounted cash flow
basis, of meeting a projected electricity demand growth forecast. These
costs include capital, operating and fuel costs for proposed supply options and
changes to the operating and fuel costs of existing plants. The benefits of
meeting the given load forecast are assumed to be equal irrespective of how
the forecast is met, as the best scenario is the one resulting in the minimum
cost on a present worth basis. SECV produced a "long-run marginal cost"
indicator for different scenarios on this basis by dividing the discounted sum
of a11 such additional costs above a base level by the discounted sum of a11
additional energy produced. Such an indicator provides no information on the
different patterns or proportions of capital and operating expenditures
incurred under different scenarios over time. More importantly the overaU
financial position of the SECV itself cannot be assessed. This does not
necessarily invalidate the use of this indicator, but iUustrates the need to
consider such issues in addition to a simple economic indicator like long-run
marginal cost.
Financial Analysis
This seeks to estimate the impacts of a given scenario on the enterprise
implementing it (in this case SFCV) in terms of commonly used financial
indicators, such as electricity prices, debt levels, internal funding ratios and
rates of return. This approach concentrates on the cashf1ows required to
implement the scenario and their interaction with the overaU financial
position of the enterprise. CRA's evidence concentrated heavily on this
form of analysis. Financial analysis provides a more detailed and potentia11y
more realistic interpretation of the business implications of scenarios than
does long-run marginal cost analysis, but does not provide a single
unambiguous indicator of overa11 economic cost. The output of the analysis is
also subject to external assumptions. For example, the analyses presented to
the Inquiry by SECV assumed that electricity prices would fo11ow current
Government policy and that the effects of the different scenarios would be
seen in SECV debt levels. It would have been just as valid to have assumed
that electricity prices should be a11owed to float in order to produce a
particular level of debt, rate of return or internal funding for capital works.
87
Cost Benefit Analysis
Many submissions to the Inquiry pointed out that to concentrate solely on the
costs of implementing scenarios to the electricity supply system, or SECV,
would ignore other important economic and social effects of large scale
power station construction and operation. For example, associated with
different options would be socio-economic costs not necessarily borne by
SECV such as health and education facilities for construction workers, or the
less tangible but real costs of unemployment or relocation. Another
frequently-mentioned possibility was that of "multiplier effects" whereby
power station construction and operation would stimulate economic activity
that would not have otherwise occurred leading to benefits beyond the
production of extra electricity.
Cost benefit analysis is a generic term for evaluation methods that attempt
to incorporate estimates of such costs and benefits into an overall measure of
economic value (e.g. a cost/benefit ratio). Such methods frequently rely on
sophisticated econometric techniques such as shadow pricing in order to
represent external, secondary, or intangible costs and benefits as monetary
values.
The only evidence before the Inquiry to take a step in the direction of
performing (rather than suggesting) this form of analysis was that of the
National Institute of Economic and Industry Research (NIEIR) as consultants
to SECV. NIEIR's analysis used a macro-economic model to estimate the
likely magnitude of multiplier effects, but concluded that it was probable
that these would be negligible from a national perspective. While there
would be multiplier effects at a local level, these would be at the expense of
economic activity elsewhere leading to no net gains in an economic sense.
Thus, potential multiplier effects would not change conclusions drawn on the
basis of cost effectiveness analysis.
This leaves the issue of external and intangible costs and benefits which are
not automatically quantified in economic terms. In the current Inquiry,
examples of such costs would be those associated with changes in regional
employment levels, and possibly some advancement of the depletion of Bass
Strait gas reserves which have alternative uses to power generation. The
88
Committee has preferred to consider such issues directly rather than seek to
integrate them into a technical cost benefit analysis, since there is no
generally accepted and uncontroversial method of doing the latter.
Nevertheless, the Committee strongly supports the identification of all such
costs and benefits as an input to decision making.
Regional Employment and Population Analysis
Scenario modelling by SECV produced estimates of power industry
employment levels in regional areas, particularly the Latrobe Region and the
Oaklands- Yarrawonga area. In conjunction with projections of non-power
industry employment, this allowed some estimation of overall employment
and population trends and the effect on these of alternative scenarios. Large
or rapid fluctuations in employment levels would tend to be associated with
social costs such as regional unemployment or dislocations to social networks
and regional housing land and rental markets. These issues are discussed in
Chapter lJ and in a discussion paper prepared for the Committee by the
Melbourne University School of Environmental Planning.
7.4 Influence of Assumptions
Figure 7.1 did not depict the very large number of individual assumptions and
inputs to each model, nor all the possible linkages between models (for
example, load forecasts would vary according to the economic environment
projected, and would also be affected by tariffs).
Summaries of the major assumptions used are to be found in SECV's "Scenario
Study Results - July 1987", CRA's "Third Evidence - July 1987" and BHP's
"Third Public Submission - October 1987".
Because of the many assumptions required to operate a set of models like
that shown in Figure 7.1, the Committee does not believe that it is desirable
to regard their outputs as definite, or even probable, predictions of the
absolute future position of SECV and of the regions concerned. The value of
the results is for comparison of alternative strategies. Provided that all
assumptions are held constant, the differences between results obtained for
89
different supply/demand strategies will be valid indicators of the relative
impacts of these strategies.
7.5 Comparison of Results
Table 7.1 provides an indication of the economic and financial results
obtained by SECV and CRA for a representative range of scenarios.
Approximately 150 scenario studies were carried out, some of these are
reported in later chapters of this report and a complete listing is available
from the Committee's offices.
While using the common framework of Figure 7.1 for conducting scenario
studies, SECV, CRA and BHP used different individual models and presented
results in differing terms. Certain basic data were agreed and used by all
three parties including:
Load forecasts (SECV's 1987 forecasts were used);
Capital and operating costs of supply options;
Performance levels and lifetimes of existing plant.
The detailed nature of each of the models used by those making submissions
and their differing information requirements meant that many other
assumptions were not standardised for the scenario studies. Therefore SECV,
CRA and BHP did not present directly comparable results. Furthermore,
SECV's evidence was the only source of quantitative data on the regional
employment effects of alternative sequences, as CRA and BHP evidence on
scenario studies was confined to financial issues.
Despite this, there was agreement on important aspects of the sequences of
supply options studied by the three organisations:
An all brown coal development sequence would lead to the highest
cost of generation and transmission for a wide range of load
growth and interest/discount rates;
90
<.0 ......
TABLE 7.1 - COMPARISON OF RESULTS FOR SELECTED SCENARIOS
SECV INDICATORS CRA INDICATORS
SCENARIO Long Run Reduction in Present Value Reduction in
Marginal Cost 1999/2000 debt of Total Expenditure 1999/2000 debt level (from -saving on level (from
All Brown Coal) All Brown Coal All Brown Coal) c/kWh $m (19&6) $m (19&6) $m (19&6)
All Brown Coal SECV - 10 5.44 0 0 0 CRA - A2
Oaklands/Loy Yang B3,4 SECV - 30 4.60 1500 1964 1700 CRA - B2
Loy Yang B3,4/0aklands SECV - 31 4.55 1500 1431 1450 CRA - H2
Gas/Brown Coal SECV - 70 4.79 1900 1519 1700 CRA - C2
Gas/Oaklands/Loy Yang B3,4 SECV - 92 4.33 2100 2190 2200 CRA - G2
------ -·-·---~ ----
Sequences including black coal fired and/or gas fired options could
offer significantly lower generation and transmission costs,
particularly through reductions in capital expenditure
requirements. These sequences would offer SECV opportunities to
moderate increases in tariffs and/or debt accumulation and/or to
increase rates of return on assets;
The magnitude of the total cost reductions available over the
period to the year 2000 (as measured by comparative levels of
SECV debt estimated in that year) was in the vicinity of
$1,000-$2,000 million (1986 dollars) for mixed fuel sequences.
This is equivalent to a saving of $300-700 million (1986 dollars) in
1986, using a real discount rate of 896.
There were also some important areas of disagreement, including the
following:
SECV absolute financial position - SECV results indicated that
under the most expensive development sequence (all brown coal),
electricity tariffs could, nevertheless, be reduced in real terms
while debt would not increase in real terms. CRA and BHP
results indicated large real increases in both tariffs and debt
levels for an all brown coal sequence.
The major apparent reason for this difference related to each
party's estimate of future SECV operating costs (exclusive of
finance charges). SECV results were based on continuing real
reductions in this area, while CRA and BHP studies assumed
increasing real operating costs in future years. This is one
example of different modelling assumptions leading to
substantially different results.
Nevertheless, there was broad agreement about the relative
impact of different supply development sequences on SECV's
financial position, as described above.
Sequencing of options - While agreeing on the potential for black
coal and gas fired options to reduce generation and transmission
costs, SECV, CRA and BHP did not agree on the optimum
sequencing of these options. One contentious example was the
relative sequencing of Loy Yang B Units 3 & 4 and Oaklands.
SECV evidence stated that no clear distinction could be drawn on
economic grounds between sequences where these options
appeared in reverse orders, while CRA results indicated a distinct
financial advantage in the case where Oaklands was constructed
first.
The Committee's research staff investigated this matter in
considerable depth and concluded that differences between the
models and assumptions used by CRA and SECV were more than
sufficient to explain the different results. This does not mean
that the order of construction of these two options would have no
economic and financial implications. However, there are still
significant uncertainties about basic data including the capital
and operating costs of both Loy Yang B Units 3 & 4 and Oaklands,
as well as non-financial factors to be taken into account. In these
~ircumstances, the Committee did not consider it worthwhile
attempting to fully reconcile the SECV and CRA models, as it is
probable that no clear conclusion on this issue can be drawn until
the broader uncertainties referred to are resolved.
7.6 SECV Debt Level
A further issue to be considered is that of different interpretations of, or
emphases placed on, similar results by the parties undertaking scenario
modelling. An important example. is the question of relative SECV debt
levels. By any yardstick, SECV is currently experiencing a high level of
debt. This means that the differing capital expenditures involved in different
sequences of generating options, and the implications for SECV borrowing
requirements are important, since a high level of debt exposes an
organisation like SECV to financial risk in the event of increases in interest
rates or downturns in sales (which are likely to occur in tandem).
93
SECV's long-run marginal cost indicator abstracts from the question of the
relative levels of capital and operating expenditure required to implement
different sequences of generating options. High capital cost, low operating
cost sequences may show the same long-run marginal cost as lower capital
cost, higher operating cost sequences. However, there are important
differences between such expenditure patterns, since a higher capital cost
sequence would involve earlier commitment of funds, higher initial debt
levels, and greater exposure to financial risks if economic circumstances
deteriorate after investment decisions are made. Lower capital cost
sequences may provide greater opportunity to reduce operating costs in an
adverse financial and business climate. A further consideration is the
tendency of Commonwealth governments to restrict access by State public
authorities to capital markets during times of economic restraint.
SECV's evidence concentrated on the long-run marginal cost of scenarios as
the major economic criterion for choice. This was illustrated in the
following quotation from its Part Ill Evidence document:
.... debt is not regarded as a primary issue separable from either the SEC's cost reduction or the longer-term macro-economic cost to the whole economy Wlder the balance of payments constraint.
However, where long run marginal costs are not significantly different between alternative sequences, debt considerations including State and national co,1Straints on borrowing may be the determining factor.
{emphasis added)
On the other hand, CRA emphasised the issue of SECV debt throughout the
Inquiry and argued that the lower unit capital cost of the Oaklands project
{relative to other coal-fired options) had advantages beyond those revealed
by a long-run cost analysis.
The level of SECV debt is not inseparable from long-run marginal cost, given
the SECV's current stock of debt and the financial risks associated with high
debt levels in an uncertain economic environment. Consideration of
predicted debt levels in the various scenarios reinforces the attractiveness of
mixed fuel supply development sequences.
94
7.7 Discount Rates
A number of submissions raised the issue of the discount rate used in
economic and financial analysis of scenarios. A discount rate is used in
comparing costs and benefits which wiU accrue at different times in the
future, by reducing future costs or benefits to present day equivalents. The
further into the future a cost or benefit is expected to occur, the smaUer wiU
be its discounted present day equivalent. High discount rates assign lower
values to future costs or benefits than do low discount rates, and make low
capital cost options more attractive than high capital cost options. The
discount rate is not in general identical with the "real interest rate" used to
calculate the interest charges on borrowed funds in business modeHing
studies.
Professor McCoU's discussion paper "The Economic Framework for
Considering Options for Electricity Supply in Uncertain Environments"
canvasses some of the arguments related to choice of discount rate, which
remain unresolved even at a theoretical level. The Committee has concluded
that a range of discount rates should be used to assess the sensitivity of
results to this factor, and notes that the broad conclusions drawn in
Chapte~ 13 from the evidence to this Inquiry are not affected by the use of
discount rates as low as 496 or ashigh as 1296.
7.8 Comments on Scenario Modelling
The Committee considers that the scenario modelling undertaken for this
Inquiry has served a number of useful purposes, not the least of which has
been to ensure that a wider range of issues has been considered, if not
resolved, within an analytical framework. This process has been assisted by
several of those giving evidence using scenario modelling to illustrate their
arguments. The Committee hopes that this approach to planning will
continue to be developed and offers the folJowing comments on scenario
modeHing as suggestions for that development:
Demand Side Measures and Integrated Planning - In Chapter 3,
the Committee has drawn attention to the importance of further
development of demand side measures and energy conservation,
95
and has recommended an extension of the Inquiry to consider this
area in more detail. A major improvement to SECV's scenario
modelling approach would be the ability to consider demand side
and supply side options on a consistent basis. This would assist in
the development of integrated demand side and supply side plans
using the least cost criterion favoured by the Committee.
Broadening of assumptions While the scenarios studied
incorporated a range of electricity demand forecasts and the
presence or absence of demand side targets, a broader range of
forecasts should be considered. Zero growth or high growth
scenarios could occur and their study would shed light on the
contingency measures available to SECV, while more detailed
study of scenarios with non-uniform rates of growth would probe
the flexibility and robustness of supply/demand strategies and
aHow better appreciation of risk.
The retirement dates and performance of existing generating
plants are major influences on supply capability and the
implications of variations in this area should be further explored.
Modelling perspective Analysis of projects (or sequences of
projects) from the viewpoint of a proponent organisation, in terms
of its financial position alone, may not provide the same result as
analysis from the point of view of society as a whole. The
presence of taxes and other transfer payments, costs or benefits
accruing to others for which the organisation pays or receives no
financial compensation, and possible distortions in relevant areas
of the rest of the economy can cause such a divergence. The
perspective of the organisation undertaking the analysis can also
lead to the analysis being mis-specified.
For example, SECV treats coal mining costs for brown coal
developments quite differently from those for a black coal
development at Oaklands. For the former, mine capital and
operating costs are included as part of the relevant power project.
96
In the case of Oaklands, an externally set coal price is used with
no breakdown into capital and operating components. This
different treatment reflects the nature of the ownership and
contractual arrangements expected to prevail, but it is not
relevant for economic analysis from the viewpoint of society as a
whole. It could lead to distortion of comparisons between
Oaklands and brown coal options, particularly when sensitivity to
discount rates is examined. Oaklands could be unduly favoured at
high discount rates and unduly penalised at low rates by SECV's
treatment.
Turning to another area, SECV and CRA have excluded from their
primary analyses some of the costs of "community infrastructure11
for which they would (or might) not be liable to pay. However,
from society's viewpoint, infrastructure in any way associated
with a project represents a real economic cost if it would not
have to be provided (possibly in a different location) if the project
did not proceed. Its cost should then be identified irrespective of
who pays for it. This is done in Chapter 9, where it is shown that
such costs are small relative to the savings in generation costs
arising from the inclusion of the Oaklands plant.
This does not mean that all community infrastructure costs are
relevant to economic evaluation of projects. For example,
although an Oaklands project would require the expenditure of
some tens of millions of dollars on house construction in the
Oaklands region, it would not be appropriate to recognise this as a
cost for evaluation purposes because, if Oaklands did not proceed,
a similar amount would be spent on constructing houses elsewhere
in Australia (e.g. in the Latrobe Valley). Nor is it implied that
project proponents should necessarily be liable for all community
infrastructure costs - the issue of who should pay is separate from
the identification of economic costs for evaluation purposes.
97
The Committee believes that SECV should refine its scenario
modelling approach to explicitly identify possible divergences
between analysis from SECV's viewpoint and that from the
viewpoint of society as a whole.
Interstate modelling - In Chapter 12, the Committee discusses
the broader issues related to interstate electricity trade and
planning. It is essential that the scenario modelling approach be
developed to cover the South Eastern States' interconnected
electricity systems on an integrated basis.
Modelling for future Inquiries - It is understood that some recent
overseas Inquiries have specified both the assumptions and the
specific detailed models to be used in analyses submitted as
evidence. This has the benefit that evidence produced by
different parties is directly comparable.
An alternative to this approach is for an Inquiry to call for the
primary data and to carry out all evaluations using expert
independent consultants employing a defined modelling technique.
Consultants having sufficient expertise and not already aligned to
any of the parties involved are not readily available in Australia.
Both options discussed above, whilst apparently simplifying the
Inquiry process, may not challenge all the assumptions.
This Inquiry has been fortunate in that at least two independent
and technically different systems have been used by competing
organisations to model some of the major alternative scenarios.
This has highlighted differences in the results obtained and has led
to productive detailed questioning of the assumptions being made.
It has also placed the value of the conclusions reached as a result
of the modelling exercises into a more realistic perspective than
might otherwise have been the case. This is a technique which
should be promoted in any future Inquiries of this nature.
98
7.9 Conclusion
Any future Inquiry of this nature should ensure, if possible, that the
major assumptions, techniques and form of output to be used as evidence
are agreed and clearly defined at a very early stage in the Inquiry. It
should also ensure that the more detailed assumptions are chaiJenged
during the Inquiry by analysts using independent and different techniques
to the principal proponent.
99
CHAPTER EIGHT
LOY YANG B UNITS 3 &. 4
8.1 Introduction
Many of the submissions made to the Inquiry expressed the opm1on that
immediate approval of Loy Yang B Units 3 & 4 should result from the Inquiry
process. This chapter discusses the issues related to the early approval of
this supply option.
8.2 Construction and Approval Lead Time
Loy Yang B Units 3 & 4 are the final two units of an 8 x 500 MW project
which has already received statutory and environmental approval. The first
four units which form the 'A' Station have been installed, three are
operational and the fourth is currently being commissioned. The final timing
of the fifth and sixth units (Bl and B2) has still to be determined. The site
for the 'B' station has been levelled and basic drainage works are currently
being installed in preparation for the first two units. The open-cut and coal
handling plant, the water and waste water services and most of the other
necessary operational infrastructure have been installed and currently supply
the Loy Yang A Station; these services have the capacity, and were intended,
to supply both the A and B Stations. Therefore, the lead time from contract
and investment approval to operation of the first unit for Loy Yang B
Units 3 & 4 could be limited to five years if the orders placed for boiler
equipment for Loy Yang B Units 1 & 2 were duplicated. However SECV has
indicated that some potential benefit could be gained from calling for further
tenders for the boilers. This could extend the lead time to eight years. The
work required in the first three years would include one year for tender
preparation, evaluation and acceptance, followed by a further two years of
detailed design work to incorporate the latest experience and technological
developments. The point of final investment approval which initiates site
works and boiler manufacture would still be five years ahead of
commissioning Loy Yang B Unit 3.
101
8 • .3 Earliest Required Service Date
SECV's projections of demand growth and system capability indicated that a
brown coal fired supply option to follow Loy Yang B Unit 2 would be required
for service in May 1996 (under median demand growth) or November 1994 (for
high growth) assuming that no gas or black coal generated supply was
introduced. Therefore, if Loy Yang B Units 3 & 4 were to be the next supply
option after Loy Yang B Units 1 & 2 a decision might be needed in late 1989
to proceed with its construction, should a high demand growth pattern
emerge. Under median growth, commitment to construct would be required
by May 1991. Should the Plant Improvement Programme be totally
successful, both dates could be postponed because the equivalent plant
capacity that can be achieved from the overall programme is of the order of
several hundred megawatts.
8.4 Economics of Sequences with Loy Yang B Units .3 & 4 First
There is no doubt that the substantial investment already in place at the Loy
Yang site makes Loy Yang B Units 3 & 4 the least expensive and most
practicable brown coal option, so it would precede any other brown coal
options if costs are to be minimised.
SECV and other evidence has shown that sequences of power supply options
based on the use of gas, black and brown coal and commencing with either
Loy Yang B Units 3 & 4, gas turbines, or supply from Oaklands, can produce
the lowest long run marginal cost, depending on the precise capital and
operating costs of these options and the negotiated fuel prices. Although
SECV evidence tended to show that it was preferable to proceed with
Loy Yang B Units 3 & 4 before Oaklands, SECV stated that because of the
assumptions built into the economic evaluations it was not possible to
differentiate on financial grounds alone between sequences in which the order
of Oaklands and Loy Yang B Units 3 & 4 was reversed. CRA's evidence tended
to show that it would be more economic to install Oaklands ahead of
Loy Yang B Units 3 & 4. It should be noted that the costs of all these options
(including Loy Yang B Units 3 & 4 capital and operating costs) have changed
at various stages during the Inquiry. It should also be noted that no black
coal or gas price negotiations have occurred and that considerable variation
is possible in these prices.
102
A sequence with some gas fired capacity programmed for installation before
the next black or brown coal fired capacity could increase flexibility to
handle sudden changes in load growth, reduce SECV debt accumulation in the
short term, and possibly have the lowest long run marginal cost (depending on
the cost of gas).
8.5 Capital and Operating Costs
In October 1987, the Unions and SECV jointly indicated to the Committee
that they intended to reach a further agreement on ways to reduce operating
costs and improve plant availability and that they would present this
agreement to the Committee by the end of 1987. In the February 1988
hearings, the Unions and SECV indicated that initial discussions had been held
but that it would be at least a further six months before any detailed
agreement was finalised. The Committee understands the need for very
thorough discussions on these complex issues. Nevertheless, the Committee
stresses the importance of reaching agreement on these matters before any
final commitment is made to Loy Yang B Units 3 & 4. It is also essential that
an ongoing review of potential capital cost savings be maintained.
8.6 Coal Supply for Loy Yang Power Stations
In the light of comments contained in Chapter 4 of this report, the
Committee is of the opinion that there is a strong possibility that it could
prove economic to extend the lives of the Loy Yang power stations to forty
or even fifty years.
The Government has allocated about 150 million tonnes (Mt) of the good
quality coal from the Loy Yang open cut for the "Coal for Industry
Programme". This was done on the basis that the two Loy Yang power
stations would only have thirty year lives.
In evidence, SECV indicated that, if the lives of the power stations were
extended to forty years and the allocation of coal for industry was taken up,
then coal with a high sodium content would start to be used towards the end
of the power station lives. This might lead to reduced plant availability at
that time as the high sodium coal could cause increased boiler fouling.
103
Consequently, in its Preliminary Report and Draft Recommendations the
Committee indicated that it believed that the Government should review the
long term allocation of coal from the Loy Yang Open Cut.
Evidence given to the February 1988 hearings indicated that current
proposals for use of Loy Yang coal by industry will not significantly affect
the coal supply for Loy Yang power stations. It was also suggested that it
was inappropriate to review the Loy Yang coal situation at this time as this
would introduce a further element of uncertainty into current attempts to
develop brown coal based industries.
The Committee has therefore decided not to make any recommendations on
this matter at this time.
8.7 Latrobe Valley Interests
Evidence from organisations with interests in the Latrobe Valley generally
argued that immediate approval of Loy Yang B Units 3 & 4 is required to
maintain confidence and mitigate damaging effects of uncertainty in the
region.
8.8 Other Socio-economic Effects
The major socio-economic effects of building Loy Yang B Units 3 & 4 will
primarily arise because of the increased workforce required to construct the
power station and the subsequent reduction in the workforce on completion of
the power station. The magnitude of the socio-economic impact will depend
on the overlap with or gap between preceding and following power supply
projects in the Latrobe Valley. It will also depend on the overall level of the
workforce employed on other construction projects in the Valley at that time.
The number of people directly affected by this project will be lower than was
the case in the earlier phases of the Loy Yang project because much of the
project infrastructure now exists. The effects of the influx of construction
workers and their families are also likely to be more manageable because the
community infrastructure was developed to cope with more than this scale of
development during the construction of Loy Yang A.
104
8.9 Overall Economic Uncertainty
The current economic climate is very uncertain and this may significantly
affect the predicted rate of load growth. In this situation, the Committee
believes that a final commitment to construct Loy Yang B Units 3 & 4 should
be made at the latest possible time thus providing the maximum scope to
adapt to any changes which may occur.
8.10 Conclusions
At this stage, there is no clear economic difference between completion of
the Loy Yang B Units 3 & 4 and proceeding with the Oaklands project.
However, as will be discussed later in this report, Oaklands is best proceeded
with when a coincident need with NSW exists. The Oaklands project has still
to be approved by the NSW Government and joint negotiations between the
two States will be necessary. Loy Yang B Units 3 & 4 is an approved project
and could proceed immediately, although it would appear that there is scope
for further cost reductions.
The Committee has concluded that Loy Yang B Units 3 & 4 should be the next
base load units committed for construction after Loy Yang B Units 1 & 2.
This is further discussed in Chapter 13 and should not be taken to exclude the
possibility that in certain circumstances the construction of Oaklands might
overlap with the construction of Loy Yang B Units 3 & 4.
8.ll Specific Recommendations
The Committee recommends that:
No final commitment to contracts and expenditure to construct
Loy Yang B Units 3 & 4 should be given until the latest time consistent
with maintaining a reliable electricity supply system. Immediately
prior to authorising expenditure on the major plant items, the
Government should ensure that SECV reviews the capital and operating
costs of both Loy Yang B Units 3 & 4 and other viable power supply and
demand side options. This should include a re-evaluation of the
socio-economic effects of these alternatives in the light of updated
load forecasts and other relevant information. (Recommendation 21)
105
CHAPTER NINE
OAKLANDS
9.1 Introduction
The Oaklands power project is based on a large deposit of sub-bituminous coal
located near the town of Oaklands in New South Wales approximately 100 km
north-west of Albury-Wodonga. A Joint Venture of CRA Ltd. (6096) and
Mitsubishi Development Pty. Ltd. (4096) has been carrying out exploration of
the coalfield under an authorisation from the NSW Department of Mineral
Resources, with CRA acting as managers for the project.
To date a coal resource of some 3000 million tonnes (Mt) has been identified
with up to 1500 Mt capable of economic mining. The coal is located in a thick
seam and should be suitable for large scale open cut mining at a low unit
cost. The coal is not a prospect for export because of its location and
relatively low specific energy (for black coal).
The Joint Venture has been investigating the prospect of a large scale power
station (2800 MW) to be supplied from a new mine located on this coalfield.
Other uses for the coal are not considered prospective at this time.
A feasibility study was initiated by the Joint Venture in June 1985 and
consultants were engaged to carry out the study. Lead consultants were
GHD/Black and Veatch supported by Coffey and Partners on groundwater and
geotechnical studies, and Coleman and Associates on mine planning. Black
and Veatch are power consultants based in Kansas City. Power Technologies
Inc. of the USA have also conducted electrical transmission studies.
The feasibility study was completed in October 1986 and has provided the
basis for CRNs evidence to the Inquiry on the Oaklands project.
107
The study has examined:
A power station of initially two and ultimately four 700 MW
boiler/turbine units, conceptually based on the design of existing
4 X 660 MW power stations in NSW;
An associated open cut coal mine of initial capacity of 5.6 million
tonnes per annum (Mtpa) and later expansion to 11.2 Mtpa;
Infrastructure necessary to service such a development including
water supply, waste water treatment, electrical supply,
transmission line access and local community services.
Coal exploration and mine planning are still in progress. Water supply is
envisaged at this stage to be derived from a mixture of water obtained by
dewatering the mine site and from boreholes. Excess mine water and cooling
tower blowdown would be re-injected into another more saline deep aquifer
24 km from the mine. The water and environmental studies related to these
aspects of the project are still in progress and are to be reviewed by NSW
authorities.
9.2 Costs and Benefits
SECV has also presented evidence on the various Oaklands options. The
capital cost of plant based on Oaklands coal would be lower than that of an
equivalent plant based on Victorian brown coal because of the higher specific
energy and lower water content of the Oaklands coal. However, because the
coal would have to be purchased on contract from CRA, Oaklands coal will
probably cost more on an energy basis than the Victorian brown coal. SECV
has indicated that it would use an Oaklands based plant to supply Victoria as
an intermediate duty plant being scheduled after brown coal fired plants but
ahead of gas fired plant.
Installation of intermediate and peaking duty plant preserves the base load
operational status of existing brown coal fired plant. The economics of the
plant life extension programmes would therefore be enhanced by an extended
base load role for plants such as Hazel wood and Yallourn W.
108
The construction of Oaklands would lead to a strengthening of the
transmission system between Victoria and NSW and would enable a higher
level of interchange of electrical energy to occur with resultant fuel cost
savings to both States. System reliability would also be increased because of
the higher level of interstate support provided. This in turn results in savings
in the long term capital investment programmes of both States.
Oaklands also has the potential to enhance the use of the Snowy Scheme
through the use of surplus off-peak energy for pumped storage and the
availability of a higher level of short-term transmission capacity.
In evidence to the Inquiry, CRA and SECV disagreed over the transmission
voltage and configuration appropriate to deliver Oaklands output to Victoria.
This issue cannot be fuJJy resolved until the precise nature of any Victorian
participation in Oaklands has been agreed.
Possible power station options examined by SECV to serve Victoria's needs
have been:
A 2 x 700 MW unit development with all output exported to
Victoria. i.e. No NSW participation and no strengthening of
transmission links from Oaklands into NSW;
A 2 x 700 MW unit development near TeJford, 10 km south of
Yarrawonga in Victoria with coal supplied by rail from Oaklands.
This development presupposed that NSW opened up the coal field
in order to build a 4 x 700 MW unit development for its own
purposes at Oaklands;
Participation in a 4 x 700 MW unit development at Oaklands on
the basis that a share of the station's output would supply
Victoria's needs. Victoria could be an "equity" partner or could
take a long-term contract supply from the station.
The economics do not favour a development located at Telford nor a two unit
development at Oaklands. Evidence presented by CRA and SECV indicates
that the cost of electricity from a 4 x 700 MW development at Oaklands
109
could be competitive with the cost of energy from Loy Yang B Units 3 & 4
and lower than the cost of energy from other future brown coal options. A
four unit development would require joint Victorian and NSW participation in
the project. As yet there is no commitment to Oaklands by NSW, but the
project promises to be cost competitive with other future NSW power station
options.
The scenario studies presented to the Inquiry by SECV and CRA show a
significant economic and financial benefit to Victoria through participation in
the Oaklands project. The cost savings estimated by SECV, which would
accrue to Victoria's electricity consumers over a thirty year plant life, are
shown in Table 9.1. The savings are shown as a range, dependent on coal
price, discount rate, and position in the development sequence.
9.3 Infrastructure
Employment in the Oaklands region is based on agriculture with the nearest
large centre of industry being Albury- Wodonga. There is 1i ttle infrastructure
or industrial development and no experienced power industry workforce in the
area immediately surrounding the proposed Oaklands site. The construction
and operation of an Oaklands coal mine and power station would require more
expenditure on infrastructure and services than a similar project in an area
like the Latrobe Valley. Infrastructure costs are estimated to be in the order
of $50M to $80M. The influx of workers employed on the project would have
impacts on the cities and towns in the region.
It has been argued that the lack and likely cost of infrastructure for the
Oaklands project are such as to rule out this option. However, despite
disagreement about this aspect, it can be seen that the cost of infrastructure,
even if doubled, is small relative to the potential benefits of the project to
Victoria.
The Committee has concluded that infrastructure costs are not decisive in
the question of whether or not Oaklands should be included as a future supply
option for Victoria. However, in proceeding with an Oaklands development,
infrastructure planning and financing arrangements are an important aspect
which should be addressed in some detail at the project approval stage.
110
TABLE 9.1
PRESENT VALUE OF POTENTIAL GENERATION COST SAVINGS
DUE TO OAKLANDS OPTION; 1986-20U
SECV RESULTS ($M 1986)
Oaklands Coal@ $14/t Coal@ $20/t Position in Discount Rate Discount Rate Sequence 496 896 496 896
$M $M $M $M
First 536 468 382 391
Second 601 497 492 446
Third 537 415 459 381
Notes
1. Results are differences between the present value in mid-1986 of SECV future generation costs (operation and maintenance costs of all existing and future plant, and annualised real capital charges for new plant after Loy Yang B Units 1 &: 2) for an all brown coal sequence and those for brown coal/black coal sequences including a half (1400 MW) share of an Oaklands project.
2. Based on median load growth.
3. Source: Compiled by NREC from SECV data.
111
Oaklands would have regional employment and economic benefits for North
Eastern Victoria. Furthermore, a proportion of the project staff could be
expected to be domiciled in Victorian towns along the Murray River. A
proportion of the equipment for the mine and power station would be
manufactured in Victoria and other indirect activities would be supported by
services located in Victoria. It is expected that the construction of the
proposed Oaklands development would lead to overall benefits for Victoria.
9.4 Potential for Arrangements with NSW
Under its Terms of Reference the Committee is required to "include
recommendations as to whether or not the SEC should pursue the feasibility
of developing a black coal fired power station in northern Victoria, or the
prospects for an arrangement with NSW and/or other partners for either
investment in or purchase of power from a possible Oaklands, NSW power
project".
There has been a long history of interstate negotiations between Victoria and
NSW in respect of the current interchange agreement. Under this agreement
negotiations have recently been examining the prospects for deferral of
expenditure on Loy Yang B Units l & 2 by contract purchase of energy from
the NSW 2 x 660 MW Mt Piper Power Station due for commissioning in
1992-1993.
Negotiations in respect of Oaklands could be an extension of past practice
although ownership arrangements for Oaklands would need to be addressed.
CRA have proposed that the Oaklands mine would be privately owned and
operated to supply coal to the power station under a long-term contract.
This would be in accordance with existing practice in NSW and Queensland.
However, ownership and development of the power station could involve both
public and private participation.
Under recently amended legislation, ECNSW is currently preparing a Draft 30
year Electricity Development and Fuel Sourcing Plan. The Draft Plan is to
be presented in mid-1988 and will then be subject to public review by the
NSW Department of Energy. A Final Plan is to be tabled by mid-1989.
112
The Draft Plan will examine timing for new power stations and the ranking of
Oaklands relative to other NSW power supply options. A Coal Enquiry
Document has been issued by ECNSW to enable all sources of coal to be
assessed for new power supply options. CRA has responded to this document
on behalf of Oaklands. Final selection of power station options to follow
Mt Piper Units 1 &: 2 could require formal coal supply tenders. Such tenders
are not called for in the preparation of the Draft Plan but may be before the
Final Plan is submitted.
In a letter to the Committee, the then NSW Minister for Energy, the
Honourable Peter Cox, MP, indicated his support for joint Victorian/NSW
studies of the Oaklands development. In addition, Mr. Cox mentioned the
wider issues of joint planning and interstate energy trade including possible
NSW access to Bass Strait gas. Following publication of the Committee's
Preliminary Report and Draft Recommendations, Mr. Cox's successor, the
Honourable Ken Gabb, M.P., wrote to the Committee reaffirming these
positions and that -
The NSW Government is basically supportive of the possible development of the Oaklands coal resource to provide benefits to both Victoria and NSW.
Recently, there has been a change of government in NSW. The situation is
therefore not clear; however it may become clearer, particularly with
respect to Oaklands, during late 1988.
9.5 Specific Recommendations
Negotiations should be initiated and pursued by the Victorian
Government with the Government of New South Wales to establish the
prospects for an arrangement with NSW and/or other partners for
either investment in or the purchase of power from a black coal fired
power station at Oaklands in NSW. (Recommendation 22)
The introduction of the Oaklands plant should be primarily determined
by a coincident need for additional sources of power supply in both
Victoria and NSW and an agreement to proceed on a co-ordinated
basis. The Oaklands plant would probably be constructed after
113
Loy Yang B Units 3 &: 4, however, the possibility of the projects
overlapping in certain circumstances, such as a rapid growth in the
demand for electricity, should not be ruled out.
(Recommendation 23)
Prior to the Oaklands project proceeding, a detailed evaluation of the
electricity transmission systems interconnecting the three States and
the Snowy Scheme should be carried out with a view to optimising the
benefits which might flow from the reinforcement of this system as
part of the Oaklands project. This should include a review of the
appropriate voltage levels for the transmission system and the possible
benefits that might arise from strengthening the transmission links in
advance of the Oaklands development. (Recommendation 24)
The following issues should be considered before Victoria makes a final
commitment to an Oaklands project:
The commercial relationships between the parties to the
Oaklands project;
An independent detailed evaluation of the economics
and long-term viability of the Oaklands project
including the proposals for the supply and disposal of
water, and the proposed coal supply arrangements;
The requirements of the appropriate environmental and
resource planning authorities including the
Murray-Darling Basin Commission;
The provision and funding of community and project
infrastructure both in NSW and Northern Victoria;
The arrangements for sharing output both in respect of
Victoria's needs and the possibility of minimising
undesirable employment effects in the Latrobe Valley;
Transmission line routes from Oaklands to Melbourne.
(Recommendation 25)
114
![Proefschrift [drukker] 020210 - LOT Publications · 4.4.1 Eventrepresentation 107 4.4.2 Mainanddependentclauses 108 4.4.3 Generalresultsprogressive 109 4.4.4 Generalresultsresultantstates](https://img.pdfslide.us/doc/110x75/5f895ce53a9e5b5f521b1496/proefschrift-drukker-020210-lot-publications-441-eventrepresentation-107-442.jpg)
![Pop S5570-Android 4.4.3 KitKat CM11 Stable ROM [CM 11].pdf](https://img.pdfslide.us/doc/110x75/55cf9392550346f57b9dd6dc/pop-s5570-android-443-kitkat-cm11-stable-rom-cm-11pdf.jpg)
