National Transmission Network Development Plan AEMO Consultation Paper

Transcription

1 16 March 2011 Ms Natalie Bakas Project Manager AEMO Level 22, 530 Collins St MELBOURNE VIC Dear Ms Bakas National Transmission Network Development Plan AEMO Consultation Paper The NGF welcomes the opportunity to provide feedback to AEMO on the National Transmission Network Development Plan 2010 and modelling approaches proposed for the 2011 Plan. As a general comment, we consider that AEMO s 2010 Plan provides a very useful analysis of potential transmission network development scenarios over the next two decades. The NGF welcomes the public release of an independent, long-term view of the efficient development of the transmission network across the NEM. By incorporating longer term projections of future generation mixes and locations in the NEM, the Plan is able to look at a least cost model for both network and generation investment. The co-development of generation and transmission solutions under different scenarios provides valuable information for both generation and network businesses when considering major long-lived investments in the NEM. The Plan provides a lot of important data and reduces, to some degree, a possible information asymmetry between network and generation investors. This submission puts forward a number of suggestions for further improvements to the Plan and the process for finalising the modelling framework. Our intention is to provide constructive comment to AEMO given that the 2010 Plan was the first full report completed by the National Transmission Planner. Proposed modelling methodology The NGF recognizes that there is considerable uncertainty in the energy sector, mainly around the introduction of some form of emissions pricing. We agree that the use of multiple scenarios is the only effective way of dealing with the problem of uncertainty. Over the longer term we would suggest that AEMO looks to reduce the number of scenarios (possibly to two or three) as the form and level of a carbon price becomes clearer.

2 The NGF supports AEMO s proposal of limiting the number scenarios for the 2011 analysis by focusing on the carbon price trajectory most suited to each particular scenario. The inclusion of an up-front carbon price sensitivity doubled the number of scenarios in the main body of the report and made it more difficult to identify the key results for each scenario. A further suggestion is to consider weighting the scenarios so that the more likely outcomes are accorded greater emphasis in the reporting of outcomes. Alternatively, AEMO could look to the process used by TNSPs that provides a view of the most likely scenario, and a composite, probability weighted view of alternative options. The use of a most likely scenario with a number of sensitivities should also be effective in highlighting the volatility or otherwise of project outcomes. In terms of reporting the outcomes of the various scenarios it would be helpful to provide a table that highlights projects that are common to all or a number of scenarios and require investment at the same time. We support the use of sensitivity analysis for each of the proposed scenarios (possibly included in the attachments to the main report). Of the sensitivities proposed by AEMO in the Consultation Paper, we are of the view that the most important factors to consider for further modelling include: East coast natural gas prices pricing moving to export parity higher gas prices will fundamentally alter the expected pattern of generation development and fuel price differentials between regions. Peakier electricity demands accurate modelling of peak demands will provide early guidance on the size and location of a combination of both generation and network investments. Flatter electricity and peakier gas demand with a high penetration of distributed generation and increased demand response such sensitivity may moderate the perceived urgency for new investment. In terms of the actual development of the NTNDP we request that AEMO remain cognisant of the commercial environment, and achieve a balance between commercial realities, and what may be suggested from a pure economic/theoretical approach. Data inputs and sources The NGF notes that AEMO engaged Worley Parsons to review the 2009 cost and efficiency curves prepared by ACIL Tasman. As opposed to reviewing this data, it would appear that Worley Parsons has actually re-estimated the costs. The Worley Parsons report included non-defined industry bodies, non-cited industry papers and Worley Parsons proprietary data. We are of the view that there is a significant lack of transparency and consultation around the Worley Parsons report. This report includes capital costs that are around 25% lower than those used a year ago but it is difficult to ascertain exactly what has changed in the underlying assumptions and why. By contrast the Supply Assumptions Report (Sept 2010) prepared by ACIL Tasman details the extensive stakeholder engagement process used to verify its assumptions and calculations. While equipment manufacturers are able to provide some indication of costs, it is generation project developers that are best placed to advise on the full cost structure of generation projects. We believe there is a significant benefit in engaging with generation investors, particularly for conventional commercial technologies (CCGT, OCGT, conventional coal and wind). The NGF is unaware of WorleyParsons conducting any significant consultation with generation project developers. The NGF views the costs in the WorleyParsons report as below current market levels.

3 Unlike the ACIL Tasman report, the Worley Parsons analysis of cost curves for each different technology does not specify the factors considered for each particular technology. Worley Parsons simply notes the differences with the 2009 ACIL Tasman data but does not attempt to reconcile the assumptions or calculations used. We are of the view that the Worley Parsons commodity index understates the impact commodity prices have on engineering, procurement and construction costs. Strong commodity prices could offset any technological and productivity improvements, potentially driving up capital expenditure costs in the next five years. The NGF considers that ACIL Tasman s assumptions regarding commodity price impacts are more closely to actual market outcomes. There may be benefit in segregating short and long-term impacts. Our experience would suggest that the technology improvement rate of 20% is high compared to actual cost trends for most plant types. We would like to see the historical data which underpins such an important assumption. While some debate on longer term exchange, commodity and productivity rate forecasts is required, it is fundamental to ensure the starting AUD capital cost components for generation projects align with what it actually costs to build a power station today. Our experience is that such costs are now higher than those in ACIL s report from 2009, and suggest that capital costs would be better obtained through actual EOM/EPCM consultancy reports than solely through theoretical modelling. Given the number of assumptions used in forecasting fuel as well as operating and maintenance costs, it would be worthwhile for AEMO to validate these assumptions by back-casting process to examine how actual costs varied from forecast costs. For the sake of consistency, the NGF requests that AEMO try to use the same modelling package over a period of years. This would allow participants to use a similar package and expand on the NTNDP results. Moreover, given the criticality of these analyses in informing the market, the NGF suggests that there would be substantial value in allowing the NGF access to the PLEXOS data libraries to get a better understanding of the key cost drivers and confirm the accuracy of the modelling datasets. This would give us a greater degree of certainty as to the robustness of the modelling and should enable industry to provide useful feedback to AEMO. A number of further queries regarding modelling is attached in Attachment 1. Transmission costing Probably the most important input to any least cost modelling of a system expansion is accurate costing of any new network infrastructure. We have a concern that the 2010 Plan may understate the full costs of installing and upgrading network assets. AEMO has calculated costs in network costs in some cases using a tolerance of plus or minus 50%. A project with a forecast cost of $2 billion could slip to a $3 billion project, substantially altering the economics of a particular network investment. Attachment A, table A2.2, looks at new Queensland to NSW transmission lines. AEMO estimated that the 330 kv lines from Bulli Creek to Bayswater would cost $950 million. AEMO also looked at a 500 kv line from Western Downs to Bayswater which is roughly 200km longer than the 330 kv option. AEMO reported that the 500 kv line would cost the same as the alternative. At face value, these are curious cost estimate outcomes, which require further review and explanation.

4 Congestion costs The 2010 NTNDP indicated that some parts of the NEM may experience significant network congestion under some scenarios. The 2010 analysis was limited to identifying the number of hours of congestion. The Plan did not attempt to quantify the costs of those constraints. In addition to the number of hours of binding constraint, we would appreciate some estimation of the forecast additional costs of production due to those constraints through time to support ongoing review and monitoring of this dynamic within the market Other market benefit assessments An area for future development, and probably best achieved through working with market participants and TNSPs, is the further development of methodologies to identify market benefits, notably competition and real option benefits. AEMO could also work to investigate and identify which augmentations are required to meet reliability standards, and which augmentations provide market benefits. NEM-link Much of the public commentary on the 2010 Plan focussed on the proposal for a NEM-link project that would eventually connect all NEM regions with a 500 kv network. AEMO provided some indicative estimates of the costs and benefits of the project but observed that given the wide range of uncertainties associated with such an investment it would not be possible to make any informed judgement on the merits of the proposal at this stage. We are concerned that the NEM-link proposal may create false expectations amongst a range of stakeholders as to the possible benefits of a huge capital investment in transmission infrastructure. As noted by AEMO, the net benefits are dependent on the level of any carbon price, trends in technology costs, fuel costs and the costs of building the transmission system to such a scale. The NTNDP recognises that the in addition to the NEM-link lines, significant additional investment in the sub-500 kv (330 kv, 275 kv and 220 kv systems) would be required to achieve the benefits of NEM-link proposal, costs of which are not quantified. We consider that any future assessment of the NEM-link concept needs to clearly represent and detail the scenarios and assumptions that underpin any further analysis. While we accept that one of the key objectives of the Plan is to look at network development opportunities at a national level, this does not mean that a national network option is the long-term solution for the NEM. Some investment on major regional and inter-regional flowpaths may show net benefits in the future, but much more work needs to be undertaken to assess whether the NEM-link option delivers the same result. Moreover, even where NEM-link was found to provide material benefits, given its scale, the NGF maintains that any such investment option should be considered in stages over a period of decades. A key assumption in any analysis of the NEM-link is the assumed level of any carbon price. A high carbon price would make renewable and distributed generation more viable and therefore increase the likely benefit of giving such investments access to a strong national transmission network that runs through all regions. Alternatively, a lower carbon price (generators may have the option of purchasing reasonably priced international emission credits) would mean that conventional plant may remain viable for a longer period of time resulting in more marginal differences in fixed costs and fuel prices across the NEM.

5 The NEM-link proposal is a potential distraction from more valuable work examining smaller scale, discrete investments and upgrades of infrastructure within and across regions. The NEM-link proposal would require an enormous modelling exercise to assess likely energy flows, obtaining rights for new easements, staging of works, managing planned outages and procuring all necessary infrastructure and equipment. With billions of dollars at stake, much more work and analysis needs to be completed before any development proposal could be considered to be anything other than a high level concept at this stage. Generation clusters The NTNDP identifies a number of potential generation zones. AEMO then compares actual connection enquiries from potential investors as a check on the NTNDP results. Interestingly the NTNDP results do not match investor intentions closely, suggesting that the NTNDP fuel cost assumptions have driven projects in particular zones. For instance, in three of the NTNDP scenarios all CCGT capacity in NSW is installed in the Northern NSW zone. The disparity between the results and developer interest in the NSW central, Melbourne and Northern NSW zones may suggest fuel price and availability assumptions in the NTNDP which lead to a rather binary, sequential preference in the development of plant type in particular zones. The following figure is taken from the NTNDP. Of particular interest is the difference between generation interest and results for the NNS, NCEN and MEL zones. For example, there is a significant difference for the NNS zone as to the scale and type of generation investment from that proposed by developers to that report in the NTNDP. It would appear that the connection enquiry clusters are located closer to load centres than the NTNDP clusters. This suggests that investors are seeking to minimise congestion risk, and would prefer to locate closer to load. If this is the case then it might be worthwhile for AEMO to apply some form of penalty to more remote locations to reflect the uncertainty associated with congestion over and above that modelled.

6 The NGF notes that the AEMC have recently released the draft determination of the scale efficient network extension (SENE). The indication of potential generation clusters may provide the catalyst for a SENE study, either by generation developers or TNSPs. Network support and control and ancillary services AEMO notes a need for NSCAS in New South Wales and Victoria. It would be informative if the 2011 NTNDP highlights where the NSCAS needs identified in 2010 had been reduced, and how this reduction was achieved, or if the need for NSCAS remains unchanged or increased. We also note that small scale generation has a role in the provision of NSCAS. Our recent experience and feedback from other parties show that the cost-benefit analysis of these small scale distributed generation is not usually positive, mainly a reflection of network charging regimes. We would suggest that if AEMO does model small scale generation in the power system simulation that a conservative approach is used. Similar comments apply for larger scale generators. Updating the Plan The Plan provides a detailed assessment of possible investment and augmentation projects at the subregional, regional and cross-regional levels under a range of potential scenarios. The Plan requires an in-depth analysis of current and future generation technology costs, fuel costs, carbon price trajectories and the cost of different network assets. We understand that the preparation of the Plan requires a significant investment by AEMO in expert staff and modelling resources. One option may be to produce the Plan every two years rather an annually given that longer-term projections are difficult to accurately measure and are unlikely to change materially from one year to another. Alternatively, AEMO could consider limiting its annual modelling to the existing scenarios and re-run the analysis by updating the Plan every second year to take account of revised load forecasts and new generation entry. Summary The NGF considers that the role of the Plan is to provide detailed information about the various options for developing and strengthening the transmission network over the longer-term in conjunction with investments in generation capacity. Overall, we consider that the initial 2010 Plan provides a thorough and high-quality analysis of possible future patterns of investment, and provides scope for further incremental improvements as AEMO develops its costing and modelling methodologies. We do not see a role for AEMO as an active participant in the policy making process. The jurisdictional network planning bodies are ultimately responsible for applying the Regulatory Investment Test for Transmission when assessing the merits of individual network investment decisions, taking into account the longer-term generation and load forecasts developed and detailed in the Plan. One of the key benefits of the Plan is that it can give guidance to regional planners when considering how best to coordinate the five-yearly investment cycle with an eye to the future network needs, particularly those projects that cross regional boundaries.

7 The NGF appreciates the opportunity to make this submission to the Consultation Paper on the NTNDP. If you have any queries in respect of this submission, please feel free to contact Lana Stockman ( or Yours sincerely Malcolm Roberts Executive Director Attachment 1: Further modelling queries

8 Attachment 1: Further modelling queries A.2.2 Production and use of hourly demand traces AEMO Comment The demand traces are generated by adjusting demand patterns for a historical year to achieve the target energy and MD projections. Both the 10% and 50% POE demand traces are based on demand profiles for 2005/06, as previously agreed by the JPBs through the Market Simulations Working Group (MSWG). It is not intended that the market simulations will modify demand traces further in response to simulated electricity prices. For the time sequential studies, results from both demand conditions are aggregated by applying a 30.4% weighting to the 10% POE simulations, and a 69.6% weighting to the 50% POE simulations. A Other system normal assumptions A Backcasting process A Bids from new entry OCGT generation NGF The use of one year for both 10% and 50% has not been well justified, can AEMO please explain the reasons for applying this methodology. In the high carbon price scenarios it could be expected that demand responds to higher price outcomes, But based on demand reduction outcomes over the last 2 years in response to large price increases I would question this approach this may not hold true in reality. Demand maybe more inelastic than believed. Following their argument of allocation 30% to 10% POE on the same basis you would also allocate 30% to the 90% scenario. This would leave 40% to cover the area 10% to 90%, I question this strongly. Can AEMO explain why any more than 15% is required for the 10% POE with 85% allocated to the remaining. Given the NCAS scheme to support increased flow from Vic to NSW is included I believe the assumptions should also include the scheme to increase imports from Vic to NSW which has been used the last few years otherwise will overstate benefit of any Vic to NSW upgrade There could be considerable merit in AEMO supplying the set of bids to the relevant generator for review and comment before including in modelling. Is it possible for each Generator, that AEMO send the bid set they are proposing for review before they use it. The bid set to be used by AEMO does not appear to reflect historical outcomes for a number of recent OCGT additions. A practical solution could by 90% of the bid at heat rate multiplied by forecast fuel cost for that location with balance at $300. The reality is that the market does not bid any of the recent new entry OCGT the way AEMO details in their document which if used in the modelling would tend to significantly overstate the benefits on any interconnector upgrades