Written Comments and Consultants Reports
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CODE CHANGE PANEL
ANCILLARY SERVICES
Volume II Written comments and consultants’ reports
National Electricity Code Administrator Limited ACN 073 942 775 August 2000
2 AGL Limited
Ancillary Services Review: Summary AGL supports the principle of “causer pays” and the development of market based arrangements for the provision of ancillary services. It is hoped that such arrangements will deliver the following benefits to the users: reduce the total costs through competitive provision of ancillary services, allow risks to be managed by consumers, provide an economic based charging regime, and encourage new entrants.
It is important that each transition stage is implemented fully, allowed to be operated and reviewed prior to progressing to the next stage. There needs to be adequate assessment of existing arrangements.
Importantly, there needs to be competitive market for the provision of the various ancillary services. Discussion Objectives of this paper This submission wishes to consider the aspects put forward in the ‘Ancillary services review – Recommendation’ publication by NEMMCO. In particular, the first transitional phase – 1 July 2000 aspects. It is essential that this phase is successfully implemented and demonstrates a favourable cost benefit before progressing to further reform. General concerns: The general concerns of the recommendations of the first transitional phase are: cost/benefit of the proposal retail price controls ability to hedge current charging of some of the services
Cost/benefit of the proposals All the proposals should have a demonstrable cost benefit. If the industry is to embrace the proposed changes, there must be some basis for assessing that the changes will provide a net benefit. The current recommendations do not provide any quantifiable benefits.
The transitional arrangements should have a robust cost/benefit analysis, such that is clear that there is an overall net benefit.
The cost/benefit analysis also needs to address the incremental benefits represented by the move from the transitional to the Light on the Hill (LOH) proposals. It is possible that the major part of the expected benefits will be delivered by the move to competitive purchasing, while the LOH position represents significant additional costs to industry participants for relatively little return.
Retail price controls Presently, retailers operate in a partially regulated retail market, limiting the amount retailers can charge franchise customers. Currently the franchise market has set retail tariffs. There are charges such as ancillary services that impact on the costs of supplying the franchise market, but these extra charges can not be passed through to this segment of the market. The time frame for the transition to the fully contestable market is variable and uncertain in most states. While these regulatory restrictions may finish once the market becomes fully contestable, there is no guarantee that some form of price regulation may not be in operation.
The existence of price regulation inhibits the retailer’s ability to pass on the price signal to the beneficiary of the service. This scenario is exacerbated when Ancillary Services are dispatched as a result of a decision taken by a market participant, which is authorised by NEMMCO with little or no regard for the effect on the cost of the Ancillary Service provision. The net impact can significantly affect retailers’ commercial viability, having to fund these market services yet operate under retail price control. However, one objective of the new arrangements is that costs will reduce through competitive provision of such services. AGL is concerned that the ancillary service costs for the current year are anticipated by NEMMCO to significantly increase over the 1998-99 levels. It was anticipated that the second round of contract negotiations would have reduced the costs of ancillary services through improved competitive tendering.
The costs for ancillary services in the Southern region are tabulated below. Fiscal Year Average Peak Period Off-Peak ($/MWh) ($/MWh) Period($/MWh) 98/99 Since NEM 1.02 0.94 1.12 (December 13 1998) ($58 M) 99/00 YTD (Jan 2000) 1.64 1.31 2.01 ($91M) % Change 99/00 to 61% 40% 80% 98/99
Ability to hedge The proponents of an ancillary services market anticipate that once a market is established, the risk management tools will follow. It is questionable whether a liquid two-way market in the proposed instruments will emerge, limiting the likelihood of the instruments providing a useful hedge market.
Effective retail participation depends on the ability to forecast price and volume. In the short to medium term, the absence of relevant information is likely to prevent retail participation. The proposals should be accompanied by a more detailed assessment of the potential for hedging, looking at likely demand by retailers and consequent market liquidity. First Transitional Phase: FCAS 1. The frequency standards appear too high compared with other electricity systems. A wider tolerance could possibly provide significant cost saving, as the requirement for FCAS would be lower.
2. There needs to be more incentive for TNSP’s to schedule transmission maintenance in periods that have minimal effect on the requirement for FCAS. A causer pays approach would provide such an incentive. 3. The small deviation service is heavily reliant upon NEMMCO ‘s load forecast, which drive the generator dispatch targets. To assist in NEMMCO forecasting load more accurately, large load variation should be notified to NEMMCO. At present large load variations would include smelter pot-lines and ripple controlled hot-water loads.
By notifying NEMMCO of these large load variations, the cause for load forecasting errors will be reduced, and hence the possible cost for FCAS. The deviations from the load forecast will be due to generator non-conformance of dispatch targets, and load variations from the non-large component of the total system load. Possible reasons for these variations could range from plant/fuel related problems to weather related. Overall there will be a reduction in forecast error as a result of this extra information being provided to NEMMCO.
3. There needs to be a commercial basis for payment of load shedding ancillary services such as an ‘Availability and Compensation’ payment structure. Provision of a load shedding ancillary service is essentially the provision of an insurance product and accordingly, a premium should be paid to the provider of this product to ensure it is available. A payment for availability represents the benefit of the expected outcome of making this service available. It is an appropriate inclusion in the structure for payment for load shedding ancillary service. This service would then be treated in a like manner to system restart, which has a similar insurance product characteristic.
NCAS 1. The preference is to have TNSPs take more commercial risks in the market place. There needs to be more incentives for TNSPs to make commercial decisions in the market. They are best placed to handle the risks in the area of NCAS. Until NSPs take on more commercial risks, any costs/profits that they incur should be part of the regulated charges that they pass through the TUOS fees. It is recognised that some steps are foreshadowed in future plans towards achieving some of these reforms.
2. The contract for the provision of reactive power is paid on an availability basis. This arrangement leads to successful generator suppliers receiving continuous payments whenever they are synchronised. This is not the most economic method for sourcing a service that has a peaky load factor such as reactive power. It costs all participants well in excess of what an enabling regime would cost.
Reactive power is only required from generators above codified minimums for typically less than 24 hours per year. The current regime compensates the contracted generators for the rest of the year, whenever they are synchronised. NEMMCO pays for the peak requirement for the whole year.
The sourcing arrangement by NEMMCO for reactive power would be more transparent if it were achieved through an enabling mechanism. Enabling is already used to source most of the other services, and it would be more appropriate in this instance.
By removing this barrier for peak load generators to offer reactive power on an equal basis, a more competitive market in reactive power provision will be delivered. An enabling payment regime may also lead to self-commitment by peak generators if there is an expectation of possible enabling during high reactive demand periods.
SRAS 1. The proposed move to equal cost sharing between generators and retailers is justified, subject to concerns held that no payments is intended to be made by TNSPs. It would be desirable for TNSPs to be more incentivised to make commercial decisions and be able to gain from such responses. The concept of causer pays appears not to have been applied for this ancillary service. 2. Customers benefit by having power restored and the generation sector benefits by, and is reliant on being able to bring its product to market and to obtain a revenue stream. The costs should be allocated equally between market generators and market customers. Conclusion Most importantly, there needs to be competitive market for the provision of the various ancillary services. AGL supports the principle of “causer pays” and the development of market based arrangements for the provision of ancillary services. It is essential that the first transitional phase is successfully implemented and demonstrates a favourable cost benefit before progressing to further reform. Any price signals created from the implementation of ancillary service reform needs to have a means to be passed through to the beneficiaries of the service. To assist manage risks associated with ancillary service purchases there needs to be a competitive liquid market in financial instruments to manage risks in the ancillary service markets. AGL response to questions by Graeme Longbottom at the ancillary services forum
RETAIL CONCERNS OF AN ANCILLARY SERVICE MARKET
Material Nature of Ancillary Service Costs: Whilst the costs in absolute terms faced by retailers are many times greater, the issue at stake can be considered with a few simple examples. The purchase of energy to retail to end-use customers in reality is never a flat load. There is a load factor, and most retail loads have a higher usage in the peak periods than in the off-peak. There are also variations due to seasonal influences on the consumption of energy by end-users.
Annual Basis: Weekly ancillary purchase costs rates vary between $0.78/MWh to $5.42/MWh. This represents nearly a 7-fold variability between weeks. The annual time weighted average Victorian regional reference price was $22.55/MWh, for 1999 calendar year. The cost of ancillary service as a percentage of the energy cost can vary between: At $0.78/MWh with an annual average pool price of $22.55 => 3.46%, At $5.42/MWh with an annual average pool price of $22.55 => 24.04%. If you assume a hedged retail load, with the following energy purchase costs: Energy Hedge cost : $28/MWh(swap) +$4/MWh(Cap) = $32/MWh Retail Income from selling to End-Use customer: $34.00/MWh Ignore regulatory charges that are passed through. Ignore meter charges, NEMMCO fees, and business overhead costs etc. Assume a 1 MW flat load contracted for 1 year. Over the course of the contract, the retailer would see: Income from retail activity: 1 MW * $34.00/MWh * 8760 = $297,840 Expense from purchasing energy: 1 MW * $32/MWh * 8760 = $280,320 Profit from energy purchasing: $17,520 If ancillary service cost was $0.78/MWh, the profit earned from energy trading: $17,520 - $0.78/MWh * 8760 = $10,687 If ancillary service cost was $2.10/MWh $17,520 - $2.10/MWh * 8760 = ($876.00)
If retailers knew how much to cost ancillary service purchases at, and could purchase an instrument to manage this risk, the end user benefits due to the actions of the retailer in managing that risk.
Weekly Basis: Whilst a retailer can manage not to incur a loss on an annual basis, there a cash flow issues to consider on a weekly basis. If the purchase costs of ancillary services can vary by 7 fold from week to week, the cost of short-term liquidity incurred by retailers can be significant. The exact magnitude will depend on a variety of factors including: the cost of short term capital at the point in time (interest rates, inflation, etc), the credit rating of the retailer, the financial management strategies adopted by the retailer. Using the above example, for 1 week: Over the course of the week, the retailer would see: Income from retail activity: 1 MW * $34.00/MWh * 168 = $5,712 Expense from purchasing energy: 1 MW * $32/MWh * 168 = $5,376 Profit from energy purchasing: $336 If ancillary service cost was $0.78/MWh, the profit earned from energy trading: $336 - $0.78/MWh * 168 = $204.96 If ancillary service cost was $5.42/MWh (As seen in early February 2000). $336 - $5.42/MWh * 168 = ($574.56)
If retailers knew how much to cost ancillary service purchases at, and could purchase an instrument to manage this risk, the end user benefits due to the actions of the retailer in managing that risk.
Load Weighting Effect: If the end-user consumes more energy in the peak periods, there is a greater purchasing of ancillary services in these periods as well. At present the payment to the suppliers of the ancillary payment is calculated as supplied, but recovered from consumers on a weekly average price. This smearing of the costs loose the prices signal to the causers of the ancillary service requirement. No withstanding the above point, the costs of purchasing ancillary services during extreme demand periods will be material. For example: If the cost of ancillary services was $4900/ If retailers knew how much to cost ancillary service purchases at, and could purchase an instrument to manage this risk, the end user benefits due to the actions of the retailer in managing that risk. Lack of Liquidity in Risk Management Instruments: At present there is a very limited market for the supply of ancillary services. A few parties supply most of the requirements. Given the non-firm nature of the provision of ancillary services, the ability to hedge this cost is extremely limited. It is not practical to simply hedge some of the ancillary requirements in the energy market. Of further consideration is the fact that hedging ancillary service costs in energy hedges prevents retailers passing on ancillary service costs to end users as a fixed charge. In the current market where ancillary services are sourced on availability basis does create some problems when the system is in close demand supply balance. The situation creates high energy market prices, and reduces the supply into the ancillary services market. Hence having a non firm ancillary service contract does fail to provide the cover that it was intended to provide to the purchaser. If there was a competitive market for the provision of ancillary services, and there was a liquid market in financial instruments to effectively manage the retail load requirements, one would be in a much more tenable position to have an ancillary services market. Ref: 379/168/2 CS Energy Letter No: MT076 16 February 2000 Dr Stephen Kelly Managing Director NECA Level 5 41 Currie St ADELAIDE SA 5000 Dear Stephen ANCILLARY SERVICES REVIEW - CS ENERGY COMMENTS In response to the LECG Navigant and EMC report commissioned by NECA, CS Energy makes this submission. CS Energy supports the introduction of a market-based approach for procurement of ancillary services. You will be aware that the NGF have made a submission on this topic on behalf of Generators. CS Energy endorses and supports the NGF submission in most aspects including who should pay for services but does not agree with the direction of the review in relation to frequency control service prices. CS Energy has two major concerns in this area. Firstly we believe the methodology proposed for the determination of a Common Clearing price (CCP) will not lead to an efficient market for these services. Secondly we are concerned that the 4 second analysis of SCADA data to determine the causers of frequency deviation will not achieve the desired outcome. These concerns where raised in our submission to the NEMMCO consultation process but we feel that they were not given due consideration. Detailed comments on the proposed frequency control arrangements and an alternate construct for an ancillary services market are attached. Nothing in this submission is confidential. Yours sincerely Richard Cottee CHIEF EXECUTIVE Encl Enquiries: Ron Roduner Telephone (07) 3222 9361 Facsimile (07) 3222 9343 Attachment 1 – CS Energy Comments on Proposed FCAS Arrangements NEMMCO PROPOSED COMMON CLEARING The methodology described in the IES reports and the NEMCO final report provides for a common clearing price (CCP)for frequency control services as follows: Common Clearing Price CCP = Marginal FCAS Bid + [Energy Market Price (RRP) – Eligible Bid Price (EBP)] With reference to this formula and the example in Table 5 of the NEMMCO final report (included below for ease of reference) we make the following comments: The proposal combines the energy market and frequency control market to the extent that the effect of the frequency control service, which the CCP is intended portray, becomes negligent ($0.10 in $77.28) The total cost of providing this service will be dramatically higher than in the current arrangements. Currently only the constrained units receive compensation for lost opportunity in the energy market. With the proposed approach all generation dispatched for this service will receive the marginal frequency control service price plus the energy lost opportunity cost for the constrained generator. The IES Options report (page 44 last paragraph) predicts higher total costs for services but states that this may be outweighed by increased competitiveness and price stability in a market situation. This view is disputed as the CCP will be a function of RRP whenever generation needs to be constrained to provide the service. Generators dispatched but not constrained would receive windfall gains, as they would not have any lost energy opportunity costs but receive payment for the same. The result will be that the marginal plant will have the incentive not to remain in this position and make itself unavailable with a cascading effect to other plant until there is insufficient services dispatched in the market. The alternative is that the marginal plant will rebid to a fuel cost based bid to maximise revenue. This raises the potential for a cascading effect which collapses the energy price and not provide for the real cost of providing energy or ancillary services. Volatility in the cost of these services is already seen as excessive in the current regime. Greater volatility will result from the proposed regime because the relationship with the RRP will be amplified as shown in Table 5 where the CCP is greater than twice the RRP. This regime encourages continuous rebidding which adds to the volatility and costs of participating in the market. One of the principals established to provide guidance to the ASRG for pricing and dispatch was: “No energy Market Participant is adversely affected by providing ancillary services at any time (i.e. the Participant receives payments which fully remunerate for the provision of ancillary services and foregone opportunities in the energy spot market for the current dispatch interval). Whether the above arrangements should apply to connection agreements and mandatory services will need further consideration.” CS Energy believe the proposed methodology is not consistent with this principal. Generators constrained will not be fully remunerated for lost opportunities in the energy market because of the inappropriate use of eligible bid price (EBP) and caps on the CCP . For a generator to be fairly remunerated for being constrained off in the energy market it must maintain the same gross margin as it would have achieved in the energy market. i.e. RRP-Short Run Variable Cost (SRVC). The constraint portion in the calculation of CCP inappropriately assumes the marginal bid price of the constrained generator (EBP) equals the SRVC. If the SRVC for the constrained generator in Table 5 is less than $18, the generator will be suffering a loss for providing services. It is CS Energy’s view that generator bids attempt to achieve long run costs plus an acceptable rate of return and this especially holds true for price setting units which are most likely to be constrained. The proposed arrangements will strongly discourage generators to set price and provide ancillary services. A cap on the CCP will also lead to generators being unfairly remunerated. Consider a similar example to Table 5 where the RRP is $3000. Using the same methodology the CCP should be $7815. With a cap on the clearing price (Initially $500), the particular generator constrained will suffer significant losses in revenue as a result of being constrained in the energy market. Inadequate remuneration for constrained generators will lead to generators making themselves unavailable for these services and result in a supply shortage requiring NEMMCO to direct generators to maintain system security. This is because compensation payments as a result of a direction will fairly compensate generators allowing them to maintain their gross margin. SCADA Analysis 4 SEC CS Energy are concerned that the 4 second analysis of SCADA data to determine the causers of frequency deviation is overly complex and data intensive and will not achieve the desired outcome. No evidence has been presented of analysis of real data which indicates the extent to which dispatchable generators and loads cause frequency deviations. We are particularly concerned about the extent to which the EMS modifies the SPD output to individual generators and what effect this will have on the frequency control performance of those generators. It is our understanding and observation that the SPD Target modified by AGC frequency action is further modified by the EMS to include leads, lags and dead-bands in an attempt to pre-empt the generator control system response. This type of control is inappropriate as it overrides generator control system action and deteriorates frequency control performance and lead to penalties under the proposed SCADA analysis Another concern with the 4 second SCADA analysis is that it not consistent with the time constants generally achieved by generators and those provided in the current ancillary service contracts. Generally generators are contracted for aggregate performance over a 5 minute period not a guaranteed performance for each 4 seconds within the 5 minute period. ALTERNATE APPROACH It is our view that the common clearing price should be for the frequency control service only. i.e. CCP = Marginal FCAS Offer Price. If there is a requirement to constrain particular generators to allow sufficient services to be dispatched, then only those generators should be remunerated for their loss in the energy market. Fair remuneration could be achieved by generator making confidential bids representing the discount on the RRP they are prepared to accept for being constrained off. Providers offer a price to provide a quantity of FCAS ancillary services ($FCAS) and the CCP would approach the marginal cost of providing the service. Service providers would receive the CCP X MW of Service Dispatched. Because the costs for providing FCAS ancillary services are expected to be low, in a competitive market the value of $FCAS is also expected to be low. Generators constrained off to provide FCAS Ancillary services would receive the following revenue: Payment per MWh = (RRP – marginal price P*) $FCAS = price offered by the generator EMCP = electricity market clearing price P* = price offered by generators representing the marginal price of generation. It would not be necessary to provide any checks on this price because competition would drive it down to a reasonable approximation of marginal cost. The value of ancillary services can be maximised by co-optimising the Service Costs and constraint costs with the energy market. The benefits of this approach include: Payment to providers is fairer Constrained plant will genuinely be indifferent to whether they are constrained for ancillary services or generating in the energy market. The overall cost of services will be significantly lower. Current SPD functionality provides for optimisation of dispatched services and constraint payments with the energy market. RISK MANAGEMENT Proponents of the proposed single CCP for the service and constraint claim that it is necessary to enable hedging of ancillary service costs. With the CS Energy alternate approach ancillary service costs can still be hedged. There are two components that will require to be addressed in a risk management program: The $FCAS component, which may have limited price volatility and some quantity volatility, could be hedged with other market participants. The natural counter-party being participants providing FCAS. The compensation component, is likely to be volatile both in quantities and price if generators are, from time to time, constrained to provide FCAS. Once a participant has estimated the likely quantity for this component of FCAS, then it could be hedged using energy market swaps or options. This hedge could be established with any other market participant. The natural counter-party for the hedge would be participants in the energy market. FUTURE DEVELOPMENT OF MARKETS FOR ANCILLARY SERVICES CS Energy has considered a simplified and alternate construct for ancillary service markets. Outcomes would be consistent with competitiveness and CS Energy’s view of fair compensation. An outline of this concept is shown in Attachment 2 for information. CS Energy consider this concept should be considered and developed further as an alternative in future ancillary service reviews. Extract from NEMMCO Ancillary Service Review Final Report Table 1: Common Clearing Price – a worked example This example is based on the actual results for dispatch interval 0855 hours on 21 June 1999. This analysis was carried out using an off-line SPD facility. For this interval the Raise 6 Second price calculated by SPD was $77.28, even though the highest cleared R6 service provider was priced at $2.57/MW. The R6 supply prices for the southern interconnected regions were the same at $77.28. At the same time, energy prices in NSW/Snowy/Victoria ranged from $45.18 to 48.88. The “marginal” unit in the energy market was in the Snowy region at $46.66. In this example, SPD needed to constrain a unit off in the energy market to provide the service. This unit had the following standing or bid data: R6 Max 20 MW The maximum level of service available from the unit R6 Breakpoint 450 MW For outputs above 450 MW, the service capability reduces R6 Capacity 500 MW At 500 MW, the service capability is zero R6 Contract Price $0.10 Energy bid price $18.01 SPD Cleared MW 470.64 For outputs between 450 MW and 500 MW, there is a trade-off between energy production and FCAS capability is 2.5 MW, that is for every 2.5 MW increase in energy production the amount of FCAS capability decreases by 1 MW. In calculating the shadow price for any constraint (in this case, the constraint is the FCAS Raise 6 requirement), the requirement is reduced by 1 MW. The change in the total SPD objective function (the calculated value of trading in the electricity market) is the shadow price. For this example, the following factors influence the FCAS price: The (contract) cost of the service for the unit being reduced; The opportunity cost of reducing the output of the unit (which equals the cost of the extra production of the marginal energy unit less the energy cost saved by reducing the unit being constrained). Because of losses, a reduction of output of 2.5 MW on the “constrained” unit resulted in an increase in production of 2.62 MW on the marginal energy unit. Thus, the price was Contract cost of the service $ 0.10 + Cost of marginal energy unit $46.66/MW x 2.62 MW - Energy cost saved $18.01/MW x 2.5 = Raise 6 FCAS Price $77.32 The difference with the actual result being due to rounding errors. Note: The principal is the same for all FCAS services. although the trade in MW between FCAS provision and energy is different for each unit.. The price for each service will be the same across all interconnected regions. The price inherently includes the cost of being reduced in the energy market as well as the cost of the service (compensation payments are not required) Interpretation of prices when suppliers are being reduced is not straightforward. Attachment 2 - Alternative Ancillary Service Market Construct for Future Reviews. MARKET CLEARING AT DEMAND + ANCILARY SERVICE REQUIREMENTS (CS Energy View) Issues Simplify Ancillary Service Dispatch of AGC and Gov. Could be extended to constraints for reactive power constraints Caters for frequency control regulating and contingency requirements. This combines energy and ancillary services market. Prices ancillary services at the same cost as energy. Allows hedging of ancillary services risk. Combine enabling, usage and compensation payments Concept Price Clearing Price to clear at Demand + Ancillary Service AS Requirements. Amount of AS Requirements will be transparent. Ancillary services effectively costed at energy price so providers are indifferent as to weather they are providing ancillary services or energy. Enough capability secured to meet demand and ancillary services requirements. Decide on plant to be Constrained Having secured capacity, determine which plant best provides ancillary service requirements and dispatch the rest for energy. Most flexible plant should be enabled for Ancillary Services and not dispatched in the energy market. Use telemetered ramp-rates and load limits or Energy market bids to determine limits of ancillary service capability. Enabling includes constraint if required. Send Combination of dispatch targets and AS Targets Dispatch targets are as per current practice. AS Enabled amount for information only. Settlement Energy - Demand metered values and RRP (No change) Ancillary - Average of AS Enabled Targets for period * RRP*LF Benefits Simple and transparent No separate enabling or compensation payments No separate bids for AS No ITT Contract to be negotiated. Will be competition to provide AS i.e. Get RRP with no fuel cost. If greeters bid too high they will miss out. Cost of AS easily hedged. Other Cost is estimated to be similar to current ancillary service review recommendation. Alternative would be for generators to offer a price that they are prepared to be off loaded and settlement for Ancillary Services would be AS Enabled*RRP*LF-offload price. The cost of AS could be optimised by the dispatch algorithm. Delta Energy 3 March 2000 Dr Stephen Kelly Managing Director NECA Level 5 41 Currie St ADELAIDE SA 5000 Dear Stephen ANCILLARY SERVICES REVIEW COMMENTS Thank you for the opportunity to provide comment on the proposed ancillary service arrangements. Delta supports the National Generator Forum (NGF) submission made in parallel to this document. We are committed to this important reform. Consistent with the NGF position the following key points are raised. Who Pays The smearing of frequency control ancillary service costs across generation as appropriate (rather than down the supply chain) fails to account for the distortionary effect on the co-optimisation of energy and reserve. We believe this will see extra reserve being held back by efficient energy producers at the expense of higher energy prices. It is our view this is not efficient and will result in higher end use prices to customers. However, without prejudice to our preferred position, if any ancillary service charges are paid by generators we support them being made on an energy basis. Market Operation At the public meeting held on 18/2/00 Snowy Hydro Trading gave a presentation that referred to “sovereign” risk issues. The point was clearly made that if generators are to sell “fair” value reserve hedges they must have access to dispatch reserve volume (just like the energy market). If the systems, NEMMCO processes or NEMMCO intervention do not allow generators to dispatch reserve then this will be reflected in significant risk premiums for ancillary service hedges. This is the same principal of self commitment in an energy only market. (The contract, like energy swaps, should create incentives and not require technical/physical intervention.) The parallel being selling an energy hedge for say $35 and being unable to dispatch physical volume as spot price rises above $35 – in the long term the hedge price must rise to cover such risks. The success of the proposed arrangements will depend upon generators being able to dispatch reserve volume without technical intervention. The arrangements will fail (eg hedges only offered with large risk premiums) if intervention by NEMMCO becomes a material factor. Proposed Transitional Cap arrangements At the NECA public forum mention was made of the possibility of a transitional price cap – we caution such considerations. The current arrangements have shown inefficient (higher prices to customers) outcomes can occur when distortionary pricing practices are used (eg current compensation regime which relies only on data from the first 5 dispatch interval being used for an entire trading interval). Care needs to be taken to ensure any cap arrangement does not create an incentive for the service provider to withdraw it’s service from time to time. SCADA Approach We are concerned that the proposed use of SCADA measurements to determine the causer of frequency deviations will result in an extremely complex and data intensive settlement arrangement. We are further concerned about the practicality of such an approach and encourage NECA to explore alternate simplified options. The NEMMCO AGC system is not a transparent process and has influenced plant performance in the past. For example “tuning” of the AGC system by NEMMCO has occurred on several occasions which has seen Delta units take unusual dispatch paths. This raises the question of how SCADA measurements and AGC performance will be used to validate plant performance and what auditability exists. Concern about the use of SCADA data have been raised by several participants with NEMMCO and at the NECA public forum but we feel these concerns have not been addressed at this point. We would be pleased to provide any further information if required. This submission is not confidential. RODNEY WARD GENERAL MANAGER/MARKETING NEMMCO’s Review of Ancillary Services & Associated Code Change Proposals Comments to the Code Change Panel by the Energy Users Group of Australia Contact details for the Energy Users Group of Australia: Telephone: (03) 9841 8202 Facsimile: (03) 9841 7834 Email: [email protected] March 2000 TABLE OF CONTENTS Introduction...... 19 Level of AS Costs & Fees...... 20 Volatility...... 20 What Are the Reasons?...... 22 Impact of 50/50 Cost Allocation...... 23 Overall Comments on NEMMCO’s Review...... 23 Disappointed at the lack of market incentives proposed for TNSPs...... 23 Support the thrust to stages 1 & 2...... 24 Not certain about “The Light on the Hill” and Two-way Market...... 24 Who Should Pay?...... 25 FCAS Proposals...... 26 Network Control Proposals...... 27 System Restart Proposals...... 28 Summary of EUGA Position...... 28 Ancillary Services Review: Submission to NECA Code Change Panel Introduction Whilst ancillary services (AS) represent a relatively small part of customers’ electricity bills, they are important from the point of view of the smooth operations of the electricity system and their costs have risen dramatically since the National Electricity Market (NEM) commenced on 13th December 1998. AS are also important to end-users because of the close relationship that exists between the production (and cost) of energy and some AS, particularly at times of system stress and associated high demand for both energy and AS. This allows some providers to exercise extreme market power and force up AS costs dramatically. The Code Change Panel would know that contestable end-users and retailers1 currently pay all the costs of providing AS, notwithstanding that they are not the only causers or beneficiaries of AS. End-users also recognize that there is a potentially important role that the demand-side can play in offering competition or substitution for AS. This could have an important impact on reducing the need for AS and/or promoting additional competition. The under-developed nature of the NEM in this area and lack of incentives for demand management are a cause of some of the problems observed in the AS market.2 Given the above, we welcome the NEMMCO review of AS and the opportunity to provide comments to the Code Change Panel on the recommendations of that review. However, we must register our strong disappointment that NEMMCO refused our offer to participate in the reference group it established as part of its review. This completely ignored the fact that end- users pay for AS and is, in our view, symptomatic of NEMMCO’s lack of accountability to end-users. We hope for better treatment in future. Our comments below address those matters that are of most concern to customers: The escalating costs of AS and the quantum of AS fees; Who pays for AS now and who should in future; NEMMCO’s recommendations to the Code Change Panel and their implications for end- users; and Our comments to the Code Change Panel. 1 Retailers generally absorb the franchise customer share of AS costs. When these customers become contestable, beginning on 1 January 2001, they will have to pay AS charges. 2 NECA is currently reviewing the scope for greater demand-side participation in the NEM. The EUGA is represented on NECA’s reference group and sees this review as being particularly important. Ancillary Services Review: Submission to NECA Code Change Panel Level of AS Costs & Fees AS costs have skyrocketed since the start of the NEM. This is a cause of significant and frequently expressed concern by end-users. NEMMCO’s AS costs have risen from $95m in the first year of the NEM to $125m budgeted for this year (an increase of 32%). In fact, NEMMCO’s latest estimates suggest that its AS payments for 1999/2000 will top $150m. NEMMCO have also publicly refused to give assurances that AS costs will not increase further. Contestable customers have born the brunt of these increases, which makes internal budgeting for EUGA members a nightmare. Pre-NEM contestable customers in NSW and Victoria paid approximately 50cents/Mwh for AS. Whilst there were some cost caps involved and some additional services are now being provided that were not then, AS charges rose to about $1/Mwh immediately post-NEM. More recently, AS charges have been in the region $2-3/Mwh. One large customer has recently reported an AS charge in the Southern Inter-connected NEM of over $4/Mwh. Not surprisingly, customers are asking why? Consequently, the EUGA wrote to NEMMCO for detailed explanation and subsequently meet their experts to discuss the matter. Chart 1 below provides a breakdown of AS payments in the NEM. The top seven items make up 99 per cent, whilst frequency control (FCAS) items make up about 60 per cent and network control items (NCAS) about one-third. System restart (SRAS) comprises 6 per cent. Volatility The extreme volatility of AS charges is also a frequently expressed concern of end-users. Chart 2 below shows the volatility and increasing cost of AS over the period from late 1998 when the NEM started to the beginning of February 2000. These costs translate through directly into higher payments by end-users. Whilst we appreciate that some volatility is inevitable given the nature of NEMMCO’s call on AS (i.e. when the NEM is operating under some stress) and the fact that many providers of AS can switch between providing AS and energy, this is not well understood by customers, nor has it been well-explained to them. Hence, they are effectively buying a product, the nature of which is not very well understood. Again, this volatility makes internal budgeting difficult. Chart 1: Break-down of Ancillary Service Costs in the NEM3 3 AGC = Automatic Generator Control (FCAS); RP = reactive power (NCAS); RGUL = rapid generator unit loading (FCAS); R6 = 6 second raise (FCAS); SR = system restart (SRAS); FCAS = frequency control (FCAS); and R60 = 60 second raise (FCAS). Ancillary Services Review: Submission to NECA Code Change Panel R60 Other FCAS SR 2% 1% 3% 6% R6 9% AGC RGUL 47% 11% RP 21% Chart 2: Ancillary Service Costs in the NEM Southern Interconnected Regional Payments $14,000,000.00 $12,000,000.00 $10,000,000.00 $8,000,000.00 Preliminary $6,000,000.00 Final $4,000,000.00 $2,000,000.00 $- Week Number Queensland Payments $ 1 0 , 0 0 0 , 0 0 0 . 0 0 $ 9 , 0 0 0 , 0 0 0 . 0 0 $ 8 , 0 0 0 , 0 0 0 . 0 0 $ 7 , 0 0 0 , 0 0 0 . 0 0 $ 6 , 0 0 0 , 0 0 0 . 0 0 Preliminary $ 5 , 0 0 0 , 0 0 0 . 0 0 Final $ 4 , 0 0 0 , 0 0 0 . 0 0 $ 3 , 0 0 0 , 0 0 0 . 0 0 $ 2 , 0 0 0 , 0 0 0 . 0 0 $ 1 , 0 0 0 , 0 0 0 . 0 0 $ - Week Num ber Ancillary Services Review: Submission to NECA Code Change Panel What Are the Reasons? The EUGA had a legitimate expectation that competitive supply would reduce AS costs, not increase them, as has clearly been the case. We are most concerned about this and have sought to understand why it has happened. The following are possible reasons why there has been such a dramatic increase in AS costs since the NEM started: As mentioned above, AS costs have previously been hidden in tariffs and capped; NEMMCO’s existing procurement process are inefficient and forestall entry by additional competitors; Whilst NEMMCO is a monopsonist in the procurement of AS, it is not at all effective; NEMMCO has insufficient incentive to minimise the costs of AS, is not required to, acquires AS without referral to KPIs and any increases in costs are simply passed through to contestable customers (NEMMCO is not accountable to these customers); The acquisition of AS is vulnerable to generators with market power; The critical nature of AS to system security, the fact that large draws on AS are usually associated with system stress and the ability of generators to withdraw from AS at critical times,4 results in exponential cost increases; Barriers to entry, e.g. the need to be a Market Participant (involving substantial registration and prudential costs for providing a limited but critical service) and a lack of demand-side response, limit provision to relatively few players There is also limited competition in some areas of AS, which allows providers to exercise market power and force up charges; We understand that generators with a capability of providing significant additional AS, will not do so because they feel that the risks of the current system are too great; There is a lack of effective information about energy generated and consumed, which makes the AS market less efficient; and An increased demand for some AS, e.g. FCAS and AGC in the SIC and Queensland respectively, due to the some problems in the operation of the NEM has been responsible for substantial increases in AS costs. Unfortunately, NEMMCO’s review did not address all these issues, which we see as a major 4 NEMMCO market notice issued on 3rd February on 3rd February expressing concern that some generators had withdrawn from providing AS and seeking their re-entry into the AS market. The EUGA has asked the ACCC and NECA to investigate this episode. Ancillary Services Review: Submission to NECA Code Change Panel failing of the review. We would be very concerned if the Code Change Panel simply accepted NEMMCO’s recommendation without fully considering these factors and responding to each of them. Given that they pay for AS, contestable customers have a legitimate expectation that these matters will be addressed by the Code Change Panel and any reforms will help to overcome such problems. Customers want to be assured that this will be done.5 Impact of 50/50 Cost Allocation Following recent ACCC code change authorisations, from 1st July this year, AS costs will be shared 50/50 between generators and customers. The EUGA made numerous representations to the ACCC on this matter and strongly supports it. However, we have been informed that new contracts negotiated with generators to cover AS after 1st July have resulted in the doubling of some costs. We are therefore very concerned that there will be a substantial over- recovery of AS charges after 1st July that will be passed through to end-users. This would defeat the purpose of the ACCC authorisation and we request the Code Change Panel, NECA and the ACCC to investigate this issue, including whether there are any anti-competitive effects. Overall Comments on NEMMCO’s Review As mentioned earlier, the EUGA is disappointed that no end-users were involved in NEMMCO’s review. Effectively, those who pay had no say. Consequently, they will have more difficulty in understanding and supporting the recommendations. Nevertheless, we do support principles such as the “causer” and “beneficiary” pays, as well as the emphasis on economic efficiency and competitive supply, which have been used to guide the review. We particularly look to these to minimise AS costs and charges, to increase competition and to improve the existing charging regime for AS. Disappointed at the lack of market incentives proposed for TNSPs We are disappointed that the NEMMCO review has not made further progress towards requiring TNSPs to pay a share of AS costs. This is particularly so given that it is generally agreed that TNSPs are significant causers and beneficiaries of AS. For example, the EUGA is aware that many of the peaks in AS costs in the SIC NEM (see Chart 2) are caused by transmission outages. This seems to be yet another example of how TNSPs continue to operate without regard for how their actions impact on the energy market. NEMMCO has unfortunately failed to apply one of its fundamental principles for this review to TNSPs. NEMMCO maintains that the impact of regulation on cost pass-through is unknown and that 5 Following a recent meeting with the EUGA, NEMMCO has undertaken to provide better early warning of likely increases in ancillary service costs as system operating conditions change, as well as providing analytical reports of high priced events aimed at end-use customers. We welcome these steps. Ancillary Services Review: Submission to NECA Code Change Panel there are several reviews underway that make it impossible to know how a recommendation to require TNSPs to pay a share of AS costs can be implemented. We do not accept this as a sufficient reason for not coming up with recommendations on how to improve the present situation – even if the recommendations were made conditional on certain outcomes in the area of TNSP regulation. These deficiencies need to be addressed by the Code Change Panel or made subject to a further firm review. Support the thrust to stages 1 & 2 Whilst we support the thrust of NEMMCO’s proposed stages 1 and 2, we have some difference of view on details, particularly in relation to the practical application of two-way markets (see below), in relation to the treatment of TNSPs (see above) and in relation to some of the “who pays” proposals (see below). Not certain about “The Light on the Hill” and Two-way Market NEMMCO is supporting gradual movement towards a “Light on the Hill” involving a two- way market for AS. This would see all AS assessed as capable of being traded in a five- minute spot market move to this approach over time. It would be very similar to the way energy is currently traded in the NEM. Whilst the principles may be sound in economic theory, the costs and benefits are not so clear and NEMMCO has not done enough to demonstrate what these might be – beyond asking customers to accept them as an ‘act of faith’. Consequently, the impacts on customers are not clear. There are a series of questions that the EUGA would require more information about before it could support the wide application of a two-way market in AS. Will it create competition and lower AS costs/charges? In theory, it may well do so. It might also do so in practice, but there needs to be sound evidence of this presented before the EUGA could accept it. We have seen very little evidence of this in any of the information available to us, other than the following comment the Murray-Mather report to NECA: Total payments for instantaneous reserves have fallen correspondingly from around NZ$12 million per annum in 1996 to about NZ$5 million per annum in 1999.6 (Murray-Mather, p. 24) This in itself is insufficient evidence as the report was not asked to investigate this matter and there would need to be a more thorough assessment of the New Zealand experience and how it might relate to the NEM. 6 Murray, K. & Mather, J., Who Should Pay for Ancillary Services? An Independent Appraisal of NEMMCO’s Recommendations, A report to the NECA Code Change Panel, 25th January 2000. Ancillary Services Review: Submission to NECA Code Change Panel We have contacted our counterpart organization in New Zealand and they have confirmed that market provision has been a factor in reducing AS costs in NZ, providing us with the following comment: Instantaneous Reserve costs have started to come down as competition bites, but in frequency keeping there is little or no competition and prices have risen (or at least not dropped to reflect the opportunity cost to generators of energy sales foregone). (Pers communication from Major Electricity Users Group to EUGA, 21st Feb 2000) Will there be barriers to competition? Our concern here is that a two-way market, in itself, may not remove sufficient barriers to competition and that other measures may be needed. For example, NEMMCO registration procedures and fees, prudential requirements and other transaction costs associated with operating in the NEM may be a barrier to competition. It may be necessary to introduce concomitant reforms in these areas to lower entry barriers and ensure adequate competition in AS. If there is a residual concern about competition in some AS areas, there may be a need for special market monitoring against abuse of market power, particularly during any transition. We would suggest that this be done through the ACCC, NECA and NEMMCO, perhaps by extending and strengthening the existing Memorandum of Understanding. Will these arrangements be too complex for the task? End-users and retailers have both expressed a concern that the proposed arrangements may be too complex given the size of the AS market (i.e. around $150m pa). Will there be sufficient liquidity and hedging instruments available? Closely related to the above point, end-users and retailers have both expressed a concern that the proposed two-way market may be too small to ensure sufficient liquidity and availability of hedging instruments. In NZ, the MEUG shares these concerns and reports that over the past year there has been “mixed success” in NZ. NEMMCO has advised the EUGA that: This does present a new challenge to the market traders in the industry, but NEMMCO has been given re-assurances from several existing market traders that hedging of the new ancillary service markets will be feasible. (Pers communication, 24th Feb 2000) Given that liquidity problems still exist in the NEM today, we remain somewhat skeptical about this comment. However, the possibility has been raised that hedging instruments can be developed, which would cover both energy and AS. Who Should Pay? A two-way market (where feasible) will allocate direct costs to the consumer of the service. In the NEM, this would be a mix of generators and Market Customers. Ancillary Services Review: Submission to NECA Code Change Panel In this sense, the allocation of costs is efficient. In a one-way market, costs will still need to be allocated according to some specified decision- rule. The EUGA agrees with NEMMCO’s finding that the ‘causer’/‘beneficiary’ pays principle should apply. However, we also agree with Murray-Mather that confusion between these terms and efficiency/equity concepts exists and that where it does those best placed to lower costs should pay. In our view, end-use customers, being removed from the AS market and poorly organized, would be particularly badly placed to lower these costs. On the other hand, the small number of highly organized generators (and TNSPs) already participating directly in the NEM, would be very well placed to ensure costs are kept to minimum efficient levels. Even with the full implementation of NEMMCO’s proposals, there would be “common” or residual costs to allocate. We agree with the Murray-Mather view that it is best to minimise distortions and allocate such costs as broadly as possible. We take this to mean across all Market Participants, that is, generators, Market Customers & TNSPs. NEMMCO’s proposals also involve the allocation of some mandatory services. We support the Murray-Mather view about the need to develop a better decision process for these, which ensures total costs (production and “other”) are minimized. This would involve allocating such costs to those best able to influence them. FCAS Proposals NEMMCO’s proposal to spread FCAS costs broadly and give generators incentives to minimise costs are strongly supported. However, its proposal to allocate all residual costs of small deviation FCAS is contrary to this principle and is not supported. In addition, the creation of eight spot markets for FCAS seems complex. This raises issues such as those mentioned above including: Will there be enough competition? Will costs/prices fall? Will transactions costs increase? Will the needed response always be there in time? NEMMCO has informed us that they expect FCAS costs to reduce when spot markets are introduced for several reasons: Current contract prices are locked in for a substantial period, which leads to a risk and uncertainty component to be loaded into the price tendered by service providers, Lack of hedging arrangements under present contracts encourages service providers to increase their offer price, Ancillary Services Review: Submission to NECA Code Change Panel Moving from fixed price contracts to regular price offers through a market, is likely to encourage greater price competition for these services. Encouraging new technologies and demand side response will increase the number of potential service providers, and hence reduce costs. We recognise that these factors could have this impact, but require some additional factual evidence of the likelihood of such impacts. In addition, the reason for and impact of the cost allocation of ‘contingency raise’ to generators and ‘lower’ to customers is not clear. Consistent with our comments above about TNSPs and AS, a further review of including TNSP in contingency FCAS is needed. Network Control Proposals NEMMCO’s proposals on NCAS do not go far enough and are disappointing. NCAS is the second biggest component of AS (see Chart 1), but NEMMCO has not treated these with sufficient importance. The point is also made by Murray-Mather, who comment that: “NEMMCO’s review appears not to have reached a clear view as to how charges for NCAS could be structured to create incentives to minimise costs, nor identified the regulatory changes required to achieve this outcome” (Murray-Mather) Additionally, allocating residual NCAS costs wholly to customers is not supported. This would be contrary to economic efficiency, including tests used in NEMMCO’s report and identified by Murray-Mather. Ancillary Services Review: Submission to NECA Code Change Panel System Restart Proposals We support the NEMMCO conclusion that ‘basic’ SRAS is best treated as a universal service (i.e. common cost). We therefore urge the Code Change Panel to apply a broad-based cost allocation proposal to basic SRAS. In saying this, we take ‘basic’ SRAS to mean what is provided in the NEM now, although this is not clearly spelt out by NEMMCO. The Code Change Panel should clarify both the nature of the service and that there will be no diminution in this service. Under the NEMMCO proposals, ‘Supplementary’ SRAS would provide a premium service to those willing to pay for it. We support this proposal and believe that those requiring only basic SRAS should not be required to subsidise those wanting a level of service over and above this. However, Murray-Mather point out that State intervention to protect supply may impact on this proposal. We share their concern. Generally, if a State wishes to intervene in such a way as to create a demand for SRAS over and above the basic level provided, it should also be required to pay for this. Summary of EUGA Position Notwithstanding its reservations about some of NEMMCO’s proposals and concerns about a lack of clear evidence on the practical implementation of two-way markets for AS, the EUGA is strongly in favour of AS reform. In summary, our position is that: We are very concerned about the rising cost of AS and the impact of this on contestable customers; We support the need to review AS and the general thrust of NEMMCO’s proposals; However, we are concerned about some aspects of NEMMCO’s recommendations to NECA, including: o The practicality of its spot market in all circumstances and given present information gaps; o The complexity of the FCAS proposals and their impact on competition, costs and liquidity (these matters require further elaboration and information); o The limited changes to NCAS, the second most important AS; o The exclusion of TNSPs from AS payments; and o The proposed allocation of some residual costs contrary to sound principles, including those guiding the NEMMCO review. We support several of the Murray-Mather comments on shortcomings in the NEMMCO recommendations to the Code Change Panel; We suggest that reforms be accompanied by stronger market monitoring; and We believe that NEMMCO needs to develop KPI’s on AS to help it contain costs, ensure efficiency in delivery and provide greater accountability on AS. Ancillary Services Review: Submission to NECA Code Change Panel We would also like to know how the existing breakdown of AS translates to NEMMCO’s proposals and what is the likely impact on costs to be borne by end-user if implemented, including the net difference after implementation of the ACCC’s condition that AS costs be shared 50/50 between generators and customers from 1st July 2000? This is not clear from NEMMCO’s papers. Given the above comments, the EUGA’s position on cost allocation for AS is summarized in the Table below. Shaded areas indicate where there is a difference with NEMMCO’s proposals. The table does not include an allocation to TNSPs, but the EUGA strongly supports moves in this direction. We also request the Code Change Panel, NECA and the ACCC to investigate the apparent doubling of some AS contract costs from 1st July this year, the date from which generators will be required to pay 50 per cent of AS charges. Table: Who Should Pay for Ancillary Services? The EUGA’s Modified Proposals AS type NEMMCO EUGA Generator Customer Generator Customer Small dev FCAS Causers Residue Causers + Causers + 50% residue 50% residue Large dev FCAS (Raise) 100% 0% 100% 0% Large dev FCAS (Lower) 0% 100% 100% 0% Flinders Power Pty Ltd NCAS (TNSP) 0% 100% 50% 50% Adelaide Office NCAS (mandatory) 0% 100% 100% 0% 168 Greenhill Road NCAS (NEMMCO) 0% 100% 50% 50% Parkside SA 5063 GPO Box 2535 SRAS 50% 50% 50% 50% Adelaide SA 5001 Tel: (08) 8372 8600 Fax: (08) 8372 8610 FLINDERS POWER PTY LTD ACN 082 988 270 Stephen Kelly Managing Director NECA Level 5, 41 Currie Street Adelaide SA 5000 7 March 2000 Subject: Ancillary Service Submission Dear Stephen In response to the ancillary services code change proposal as published by NEMMCO, Flinders Power makes the following comments. We fully support the submission forwarded to NECA by the NGF in relation to the ancillary service review, however we submit the following variations on that submission. 1. The NGF submission puts forward the argument that the interim allocation mechanism for large deviation FCAS is “crude, simplistic and inaccurate to ascribe all large deviation raise services to generators and all large deviation lower service to loads”. We support this view and put forward the supporting argument that large deviation FCAS in South Australia is often caused by a sudden down rating of the interconnector or by transmission network problems. Examples of this include the events of 23 October 1999 and 2 December 1999. We therefore believe that the interim allocation mechanism should not only be ascribed to generators and loads, but should also be ascribed to transmission networks and the interconnector, which have the ability to (and have since market start shown its ability to) cause large deviation FCAS situations in South Australia. 2. The NEMMCO report also recommends that the largest contingency or group of contingencies incur the full costs of large deviation FCAS costs. We believe that this is unreasonable and that the alternative “Runway” methodology as outlined in the LECG/EMC independent report to be a more appropriate mechanism for allocating costs. We believe that allocating the full costs of large deviation FCAS to the largest contingency will lead to an inefficient price signal for new generation investment. If you have any questions please do not hesitate to contact either Reza Evans or myself. Yours sincerely Mark Williamson General Manager Marketing & Strategy Stephen Kelly NECA Level 5, 41 Currie Street Adelaide SA 5000 Thursday, March 3, 2000 Delivered via e-mail to [email protected] RE: Ancillary Service Review – Comments on Code Changes Dear Stephen, Loy Yang Power supports the NGF paper sent to you by Jim Twomey and is deeply concerned with the status of the current ancillary services review. We believe the impetus and momentum originally established for the review is diminishing and the confusion and uncertainty within the market increasing. As we fully support the NGF submission, our comments here will be short and seek to emphasize a number of issues. The principles as espoused in the NGF document should be fully implemented. In particular, participants should be able to tell in advance and at the time, what Ancillary services they are being paid for and the quantum of this payment. The situation we have at present where neither NEMMCO operations nor a generator can accurately determine the usage nor value of any Ancillary Services until well after the fact is totally unacceptable. The whole process has potential to stall without agreed and codified dates for Light on the Hill objectives. NEMMCO does not seem to have developed a robust, realistic plan or implementation program for the introduction of Ancillary Services. Without such a plan, it is unlikely that any reasonable system will be successfully implemented. We are running the risk of having ongoing delays to the commencement of the Ancillary Services market, in much the same way that the start to the Energy Market was delayed several times due to apparent uncoordinated planning and goal setting. The general move to market based systems has been discussed and recognised as very likely for some time now, however there seems to have been very little, if any, work done on how these markets might actually run. Issues such as what participant input will be required, what systems will be used and how will a participant monitor what services he is providing/using and the remuneration for /cost of, those services. Loy Yang Power again reiterates its support for appropriately planned and implemented market based solutions to the current ancillary services arrangements and support the NGF recommendations to : Include the principles for ancillary services market development in the Code. Provide a more appropriate assessment of the causation of Large Deviation FCAS; Implement a market in the provisions of Network Control Ancillary Services; and Remove the requirement for an interim change to cost allocations that will otherwise occur on 1 July 2000. Please feel free to contact me if you have any queries regarding this submission. Yours sincerely Terry Killen Manager, Regulation and Pool Operations Loy Yang Power Management Pty.Ltd. Email: [email protected] Phone: 03 5173 2533 GPO Box 1045 Adelaide SA 5001 ER00D02910 DX56205 Telephone: (08) 8204 1740 Facsimile: (08) 8204 1730 3 March 2000 Mr Greg Thorpe C/- Code Change Panel NECA Level 5, 41 Currie Street ADELAIDE SA 5001 Fax: 8213 6391 Dear Mr Thorpe Ancillary Services Review – Code Change Proposals I note that the Code Change Panel has sought comment in relation to Code changes emerging from the above Review by 3 March 2000. I understand that the outcomes of the review are being pursued in three transitional phases, the first of which is the subject of the present consultation. ERSU provides the following comments in relation to these proposals. ERSU is broadly comfortable with the thrust of the first phase proposals emerging from the review, and can see merit in the concept of introducing market based mechanisms for the provision of ancillary services in the NEM. However, such reforms clearly need to be introduced in an effective manner that captures competitive benefits and improves the efficiency with which these services are delivered. In particular, analysis of the liquidity and depth of the proposed markets is important to establish the scope for competitive outcomes. Before being in a position to support these proposals, ERSU would therefore seek further information on the practical scope for competition under the model proposed, in which eight separate markets for the delivery of the distinct frequency control ancillary services would be introduced. These proposals envisage that separate half-hourly clearing prices would be established for each of the eight new sub-markets in each region of the NEM. I note that regional price differences would be expected to occur only when regions are separated from other regions. Having regard to the number of service providers in each region, ERSU believes that the scope for effective inter-regional trade in the provision of frequency control ancillary services should be further explored, particularly during periods when an interconnector is constrained at capacity. In particular, ERSU would seek advice as to whether the operating constraints applying to an interconnect would act to restrict such competition in practice. I note also that the Code change proposals anticipate the extension of current arrangements for the delivery of network control ancillary services presently provided for under Schedule 9G (including mandated levels of reactive power capability) as a standard provision of the Code. ERSU would seek advice on the proposed timeframe for the continuation of these arrangements, particularly given the subsequent changes contemplated in this area. Given that the proposed changes emerging from the review may supersede Schedule 9G of the Code, ERSU will also be reviewing South Australia’s derogations in detail in light of the recommendations of the review for any potential impacts. Yours sincerely Tim Spencer EXECUTIVE DIRECTOR MARKET AND REGULATORY REFORM Corporate Office Marketing & Trading 34 Griffiths Road LAMBTON NSW 2299 Phone: 02 4968 7429 Mobile: 0412 510 563 Greg Thorpe Associate Director National Electricity Code Administrator Level 5, 41 Currie Street ADELAIDE SA 5000 FAX: 08 8213 6300 Dear Greg PROPOSED ANCILLARY SERVICES CODE CHANGES RESPONSE TO ISSUES RAISED AT FORUM ON 18TH FEBRUARY 2000 Macquarie Generation would like to comment on the proposed code changes in relation to Ancillary Service, which in summary would: Introduce a number of markets for FCAS Maintain the status quo for NCAS and SRAS Macquarie Generation has major concerns about the proposed code changes and also the process that has led us to this point. Process concerns Derogation 9G requires the introduction of a revised ancillary service regime by December 2000 and if this is not achieved 50% of the current cost of ancillary services will be levied on generators. As a result of this timetable there has been a lot of pressure to deliver an outcome. In our view this has not provided the appropriate time for the industry to understand and debate the issues adequately. Our observation in discussions with a wide range of industry participants is that the current proposals are not well understood. Given the vital role that the delivery of ancillary services play in ensuring that system security is maintained it appears to be a very high risk strategy to introduce a significant change to the provision of these services that the industry does not appear to be able to understand. The consequences of any unintended outcomes could be severe. Macquarie Generation is of the view that NECA should support the extension of the deadline in derogation 9G to ensure that the changes required by this derogation are introduced in a more measured fashion. The other major concern with the process to date is the total absence of any attempt to determine if the benefits of introducing the proposed new regime will worth the investment required given the significant costs and disruption that will be incurred. The new regime will require significant systems developments for both NEMMCO and all market participants – particularly generators who will have to modify existing bidding systems. Some very simple and preliminary analysis we have completed indicates that a 50% reduction in the cost of provision of FCAS would result in a saving of less than $10 per customer per year (on average). This does not appear to us to be a significant saving. Macquarie Generation is of the view that some form of cost benefit analysis must be completed before any commitment is made to proceed with the proposed changes. Another process issue is the manner in which the consultation process is conducted. There is no real opportunity for people who are not sure of their views to raise their concerns in an environment where they will not feel threatened by the presence of others who may not respond sympathetically to them raising these concerns. The use of public forums whilst it may be more efficient in terms of the use of NECA’s resources we believe, tends to create an environment where only the brave and noisy are heard. This can clearly lead to NECA not appreciating the concerns that may be held by significant parts of the market. Response to proposed code changes Whilst Macquarie Generation is supportive of the application of “market based” solutions wherever possible it is clear that markets do not always deliver the most appropriate outcome. This is particularly true where there are “free rider” issues and where providers of services can exert significant market power. This would appear to be the case for at least some of the ancillary services required by the market. Hence market based solutions for the provision of these services would be inappropriate. FCAS It would appear that it would be possible for some form of market to be created for the provision of FCAS as all generators could provide this service and hence the market should be as liquid as the energy market. However the current proposals seem far too complex and in reviewing these proposals and discussing them with market participants and regulators some key areas of concern are: It is obvious that how this market will work is not understood by a wide range of market participants – including Macquarie Generation. We have major concerns about introducing a market for provision of a critical ancillary service if it not clear how it will work or even if it will work. The provision of FCAS is too crucial to be provided by a market that we are expected to believe will work because we have to take this on trust from those who are proposing it. We are of the view that the advocates of the introduction of this market have a responsibility to educate the market on how it can work. If the market proposed couldn’t pass the simple test of being understood by those who will have to participate in it, we believe that we have a major issue. What would appear to be the unnecessary complexity of creating what are in effect 8 markets for FCAS. The division of this market will reduce liquidity and increase transaction costs. There are concerns about the allocation of the costs of the provision of some aspects of FCAS -– particularly the large deviation FCAS. This may be resolved by the “runway method” of cost allocation proposed. At this stage it is not clear to us (or to anyone else that we have discussed this with) how a hedge market in FCAS can be facilitated. Given that a major concern of retailers is their inability to manage the variations in costs of ancillary services in the current regime it is crucial that any new proposal give them the ability to be able to manage these costs. NCAS & SRAS Macquarie Generation is of the view that creating an effective market in NCAS and SRAS would be very difficult given the problems of “free riders” and providers with effective regional monopolies and hence we support the proposal that the arrangements for the provision of these services do not change significantly. Recommendations Macquarie Generation would recommend that NECA: 1. As a matter of urgency commence a process that will ensure that the deadline contained in derogation 9G is extended to allow adequate time for further discussion and debate within the market to develop a well supported and well understood approach to improving the provision of ancillary services. This should also allow for timely development of the necessary systems, both by NEMMCO and market participants. 2. A simple cost benefit analysis of the benefits of introducing the proposed changes is completed before any further investment is made. 3. The FCAS market as proposed be further discussed and reviewed until it can be clearly demonstrated that a simple, well understood market model can be developed. 4. That the proposals for no changes to NCAS and SRAS remain. Yours sincerely RUSSELL SKELTON MANAGER MARKETING & TRADING 3 四月, 2018 National Generator Forum (1) 11 February 2000 Dr Stephen Kelly Managing Director NECA Level 5, 41 Currie St ADELAIDE 5000 Dear Stephen ANCILLARY SERVICES – PRELIMINARY NFG RESPONSE Thank you for the opportunity for comment on the draft Code changes relating to Ancillary Services. As discussed between you and Stephen Orr on 9 February 2000, the NGF is anxious to assess the outcomes of the proposed forum on 18 February 2000 before finalising its submission. However, the following are the critical initial comments on the proposals, endorsed by a majority of NGF members7 1 PRINCIPLES The following principles were developed by the Ancillary Services Reference Group that was convened by NEMMCO to assist it in progressing the Review. They were published on the NEMMCO website, and it was stated there that: The purpose of the set of principles is to provide guidance to the ASRG and the broader market place in developing appropriate ancillary service arrangements for the various services. These principles will be used throughout the Review to both guide and to clarify the most appropriate path to be taken for each particular service. The principles are set out below: (i) Competitive services Achieve competitive pricing outcomes where appropriate via the most suitable mechanism 7 At the time of publication, members who have formally expressed alternate views are CS Energy and QTPTC. Members who have formally endorsed this position are Hazelwood Power, Loy Yang Power, Yallourn Energy, Energy Brix, Southern Hydro, Delta Electricity, Pacific Power, Flinders Power, Synergen, HEC, Stanwell and Tarong Energy. Some members have prepared alternate or complementary submissions to NECA. for each particular service which reflects the value of the service. (ii) Pricing and Dispatch Services priced and quantities determined on an economic basis: a) Consistency between dispatch and pricing. b) Co-optimisation of ancillary services and energy market where possible with the objective of maximising value of spot market trade considering network and other constraints. c) No energy Market Participant is adversely affected by providing ancillary services at any time (i.e. the Participant receives payments which fully remunerate for the provision of ancillary services and foregone opportunities in the energy spot market for the current dispatch interval). Whether the above arrangements should apply to connection agreements and mandatory services will need further consideration. d) Sufficient information, regarding ancillary service requirements, quantities, prices, bids, offers and contract prices etc. is published in a timely manner for the market to be efficient. As a minimum the market is informed as to the cost of consuming, and the value of providing ancillary services. e) Consistency and transparency in the criteria for determining the ancillary service requirements of the market, and in the procurement and the use of directions in procuring ancillary services. f) Ancillary services should not systematically substitute for energy in the spot market. NEMMCO will ensure that the dispatch arrangements for energy and ancillary services achieve this aim wherever possible and that there is both sufficient transparency in NEMMCO’ s operations and sufficient information available to the market to independently gauge its performance in this respect. (iii) Access All areas of the market including networks participate in the provision of and payment for ancillary services. a) Mechanisms will allow for non-Code Participants to participate in procurement processes. b) Providers must be Code Participants. c) Equal treatment of available technologies. (iv) Non-Competitive services If, after considering: industry structure; demand and supply-side options; feasibility and timing of new entrants and any substitute ancillary services capable of meeting the requirement; the market is deemed to be non competitive for the provision of an ancillary service then: a) Wherever possible, commercial arrangements acceptable to both NEMMCO and the supplier will be used to purchase the ancillary service. The parties shall act reasonably in negotiating these arrangements. b) For Code Participants, where mutually acceptable arrangements cannot be agreed, an independent expert may be requested by either party in order to determine binding terms for the provision of an ancillary service at a fair value. c) For Non Code Participants, where mutually acceptable arrangements cannot be agreed, an independent expert may be requested by either party with the consent of the other party in order to determine binding terms for the provision of an ancillary service at a fair value. (v) Compensation in the event of direction Where NEMMCO directs a Code Participant to provide an ancillary service, the Code Participant shall be compensated at fair value for the service as determined by an independent expert that is appointed with the consent of both parties. (vi) Ancillary Service Requirements As part of the statement of opportunities ancillary service requirements will be identified in sufficient detail to facilitate a competitive market and to allow informed decisions in relation to both supply and demand. (vii) Settlement Whenever NEMMCO dispatches and/or procures an ancillary service NEMMCO will be responsible for settlement of these services. The NGF strongly supports these principles and wishes to see them reflected in the proposed changes to ancillary services. We are therefore gravely concerned with the observation that, in the interim between production of the recommendations and the presentation of NEMMCO’s final recommendations to NECA, significant changes have been made which result in many aspects of the proposal failing to meet NEMMCO’s own criteria. For this reason the NGF wishes the above principles to be included in the Code as a guide to future development of ancillary services markets, along with a commitment to the continuing program of development. The following are detailed comments regarding the proposed changes, and the development of the treatment of Ancillary Services in general. 2 FCAS 2.1 Small Deviation FCAS The NGF supports the direction for small deviation FCAS put forward in the proposed Code changes. This service is referred to as regulating raise service and regulating service in the Code change proposals. It will send market signals to both providers and consumers of this service and will allow consumers of the service to modify their behaviour to reduce the need for the service. This will lead to lower overall costs of service provision. The proposed clause 3.15.6A(k) should be modified as it presently limits the use of the contribution factor to paragraph (h) of the clause. It needs to also include use in paragraph (i). For certainty and transparency in the market it is essential that the contribution factor be both forward looking and also apply for as long a period of time as practicable. We can not give unqualified support at this time, as the analysis of real data to prove the viability of the recommended approach has not yet been forthcoming. Pending the release of this information and the analysis supporting the proposed approach, then subject to the comments noted above, the NGF supports the proposed Code changes for small deviation FCAS. 2.2 Large Deviation. FCAS The NGF supports the moves to create a market for large deviation FCAS. However, the NGF can not support the interim allocation mechanism proposed. It is crude, simplistic and inaccurate to ascribe all large deviation raise services to generators and all large deviation lower service to loads. There have been numerous actual incidents in the NEM to date when frequency has fallen outside the standards set by the reliability panel purely as a result of unexpected or sudden load increases. The proposed interim allocation mechanism would do nothing to curb this behaviour of the demand side, and would penalise generators. In contrast to the arrangements for small deviation FCAS there is no scope for behaviour modification to reduce the need for the service, a fundamental feature of an economic proposal for allocation of costs. The approach of apportioning an arbitrary allocation in proportion to energy produced or consumed suggests that we have learnt nothing from the current arrangements. The requirement quantum should be dynamically determined within SPD and co-optimised with the energy market. This more appropriate approach has been marked down by NEMMCO for phase 2 of the ancillary services market development process, but the NGF can see no compelling reason for delaying implementation to an unspecified future date. The NGF believes that apportionment amongst causers should account for the probabilistic nature of the cause of the requirement. It is also important that networks are included when considering contingencies that set the quantum of large deviation FCAS required. 3 NCAS The NGF does not support the proposed Code changes for reactive power. They appropriate the property rights of participants by mandating the provision of the reactive power. Participants signed on to the Code understanding they would be required to have a reactive power capability, not that it would be dispatched without compensation. The proposed Code changes perpetuate the present unsatisfactory arrangements and do nothing to promote efficient operation of the network. There are no market signals as to how much reactive power is required, because there are no market signals as to what the network capability needs to be at any point in time to support the activities of the market. Network capability needs to be defined as a function of the reactive sources available and those reactive sources need to be dynamically priced. Without this, NEMMCO or the TNSPs have no idea whether purchasing additional reactive to increase network capability at particular times is for the overall good of the energy market, or not. At present they appear to do what they have always done, because they see large quantities of reactive power as being provided at no cost through mandatory provision. It is imperative that the recommendations from the IES reports should be implemented. Purchasing reactive power in a dynamic environment that is reflective of, and responding to, market conditions, will ensure that reactive power is not over purchased. This will lead to a lower overall cost of service provision and will start to bring network capabilities more into line with the requirements of the market. The argument that networks are regulated businesses and shouldn’t be exposed to the market is false. Networks are regulated to prevent them from extracting monopoly rents, not to insulate them from valuable market signals that they can respond to in order to benefit the market as a whole. The Code makes this clear in clause 6.2.3(a) which states: Concerns over monopoly pricing in respect of the transmission network will, wherever possible and practicable, be addressed through the introduction of competition in the provision of transmission services. While the IES recommendations would be likely to change the cost structure and the WACC of the networks, it should be open to them to approach their regulator following a significant change in circumstance to revisit their revenue determination. Clearly the NGF would actively support such a review. The debate about networks being exposed to some extent to the market has been in progress for over two years now, so this concept is not unexpected. An alternative would be to remove reactive power control plant from the regulated asset base of the network owners and have them as part of an unregulated business. Initially this may need to be limited to those localities where network owned reactive sources are in competition already with unregulated sources. 4 SCHEDULE 9G The ACCC has made it clear that the purpose of implementing a change to the basis of allocation of ancillary services costs was to ensure that the market as a whole, but generators specifically, proceeded expeditiously to the development of a new approach to the treatment of ancillary services. It is the strong view of the NGF that not only was this pressure unnecessary given the strong commitment of the generators to the process prior to the imposition of this incentive, but also that since that time, the generators have continued to deliver all that is required of them, and more, to achieve a timely outcome. Given the progress of the Ancillary Services Review with considerable effort on the part of all sides of the market, it appears the main impediment to achieving implementation by 1 July 2000 is now the required time for consultation, approval and development of the details of the changes. In these circumstances, the NGF considers that the change in cost allocation for the existing arrangements that is due to occur from 1 July 2000 should be dispensed with. Firstly, the new arrangements will be in place shortly after the original target date, in part as a result of the strong commitment of generators. Secondly, the multiple changes in cost allocation that will occur within such a short space of time, as a result of the combination of the current Schedule 9G and the proposed Code changes, will cause unnecessary confusion in the market, and additional cost for NEMMCO. On a related matter, NECA should approach the Queensland jurisdiction to secure changes to clause 9.35.7 to ensure a smooth transition from the purely contract based arrangements provided for by Schedule 9G to the mixed spot market and contract arrangements that would result from the proposed Code changes. The present wording of this clause appears to limit Queensland, before interconnection, to contract based arrangements only. In summary, the NGF has supported and continues to support, the development of the proposals originally developed as through the Ancillary Services Reference Group process. In our view, is has been inappropriate for NEMMCO, on the basis of a largely undisclosed element of its consultation process, to partially implement the outcomes of the Review. The NGF therefore recommends that NECA introduce additional Code changes to this package to – Include the principles for ancillary services market development in the Code along with the obligation to make further changes into the future; Provide a more appropriate assessment of the causation of Large Deviation FCAS; Implement a market in the provisions of Network Control Ancillary Services; and Remove the requirement for an interim change to cost allocations which will otherwise occur on 1 July 2000. Yours sincerely JP Twomey CHAIRMAN, NATIONAL GENERATOR FORUM National Generator Forum (2) 3 March 1999 Dr Stephen Kelly Managing Director NECA Level 5, 41 Currie Street ADELAIDE SA 5000 Dear Stephen ANCILLARY SERVICES – FINAL NGF RESPONSE Thank you for the opportunity to make further contributions regarding the proposed Code changes, following the informative seminar conducted on 18 February 2000. This submission should be read as supplementary to the National Generator Forum’s (NGF) preliminary response, and seeks to highlight some key issues, and to include some changes which increase the level of common purpose on the issue throughout the NGF8. 1 Principles As stated in our preliminary submission, the NGF wishes to see the principles laid down by the Ancillary Services Reference Group incorporated into the Code together with a firm timetable for the introduction of market based arrangements for (Network Control Ancillary Services (NCAS). We believe this is necessary to guide further development and enhancement of the ancillary services market. Furthermore the Code should include an ongoing commitment to such further development in line with similar provisions relating to the development of the energy market. 2 Frequency Control Ancillary Services (FCAS) 2.1 Small Deviation FCAS – Regulating Raise Service and Regulating Lower Service The NGF strongly supports the establishment of spot markets in these services and believes that the cost allocation methodology that is proposed is sound. In particular the cost allocation process will send market signals to both providers and consumers of this service and will allow consumers of the service to modify their behaviour to reduce the need for the service. This will lead to lower overall costs of service provision. Again, we must register our disappointment that the much-promised analysis of SCADA data has still not been published by NEMMCO. As with our preliminary submission, our support is conditional on this analysis proving the suitability of the recommended approach to measuring the causers of these services. 8 As it stands, this submission represents the views of the NGF, with the exception of Macquarie Generation, who will make a separate submission. QPTC also has a concern with one aspect, which is specifically addressed in the text, and otherwise is in full agreement. 2.2 Large Deviation FCAS – Fast, Slow and Delayed Raise and Lower Services In contrast to the arrangements for small deviation FCAS there is no scope for behaviour modification to reduce the need for the large deviation services, a fundamental feature of an economic proposal for allocation of costs. The proposed allocation of 100% of raise service costs to generators and 100% of lower service costs of customers is simply inaccurate and ignores actual experience in the NEM. There have numerous incidents when frequency has fallen outside the prescribed limits due purely to the impact of rapid increases in load, typically hot water switching. The NGF believes that the allocation of costs to causers of large deviation FCAS should account for the probabilistic nature of the cause of the requirement. It is only with such an allocation methodology that the causers of the requirement for these services will have the incentive to modify their behaviour to reduce the need for the services. As we stated in our preliminary submission it is essential that networks be included in the range of potential causers for these services. This would need to include regulated NSPs as well as market NSPs. If poor performance of network elements is identified as a causer of the need for large deviation FCAS it is important that the network owner see the cost of that poor performance. This would then allow for a more complete and transparent cost/benefit analysis of investment options to improve network performance, especially when such investment is regulated. 3 Network Control Ancillary Services (NCAS) The NGF remains wholly opposed to the NCAS proposals put forward by NEMMCO. The proposed Code changes would appropriate the property rights of participants by mandating the provision of reactive power. This is totally at odds with the principles set out by the ASRG and is why the NGF wishes to see these principles included in the Code. The NGF also believes that the proposed Code changes do not provide market signals as to how much reactive power is required, because there are no market signals as to what the network capability needs to be at any point in time to support the activities of the market. Network capability needs to be defined as a function of the reactive sources available and those reactive sources need to be dynamically priced. Without this, NEMMCO or the TNSPs have no idea whether purchasing additional reactive to increase network capability at particular times is for the overall good of the energy market, or not. At present the networks appear to do what they have always done, because they see large quantities of reactive power as being provided at no cost through mandatory provision. The proposed Code changes will perpetuate this inefficiency. The NGF strongly believes that it is necessary to specify a firm timetable for the removal of the mandatory provisions and for the introduction of market based arrangements for NCAS. As we stated in our preliminary submission the NGF considers it important that networks be participants in the market for reactive power and not receive regulated income from reactive power control assets that compete with unregulated sources. While this would be likely to change the cost structure and the WACC of the networks, it should be open to them to approach their regulator following a significant change in circumstance to revisit their revenue determination. Clearly the NGF would actively support such a review. 3 System Restart Ancillary Services (SRAS) With the exception of QPTC, the NGF does not support the 50/50 cost allocation for system restart services. As the ultimate beneficiaries of the power system we strongly believe that customers should pay for the bulk of the costs incurred in maintaining a system restart capability. 4 SCHEDULE 9G As explained in our preliminary submission, the NGF believes that generators have contributed significantly to the progress of ancillary services review process. In light of this contribution and considering the reasons given by the ACCC for changing the payment arrangements for ancillary services, the NGF strongly urges that the changes proposed from 1 July 2000 be dispensed with. With the new arrangements already progressing through Code change consultation, it does not make sense to impose the costs of an unnecessary change in payment arrangements upon NEMMCO and the market at large. I myself, and the NGF experts in ancillary services, would be pleased to amplify the above, or the content of our original submission, as required. Yours sincerely J P Twomey CHAIRMAN National Retailer Forum 21 八月 2000 Mr Stephen Kelly Code Change Panel NECA Limited Level 5, 41 Currie Street Adelaide SA 5000 Dear Mr Kelly Code Change Panel - Ancillary Services I refer to the document entitled “Code Change Panel - Ancillary Services” issued in January 2000. The National Retailers Forum (NRF) has considered the document and wishes to provide the following comments. NRF does not support the Code Change Proposal The NRF has closely considered the development of the proposals for the new competitive arrangements for the provision of ancillary services to the National Electricity Market. It is the firm view of the NRF that the proposed arrangements will not be successful and accordingly does not support the Code Change Proposal under consideration by the Code Change Panel. General The NRF supports the principle of “causer pays” and the development of market based arrangements for the provision of ancillary services, which: reduce the total costs through competitive provision of such services, encourage new entrants, provide an economic based charging regime, and allow risks to be managed by participants at all times. Where the market based arrangements are not demonstrably available to meet the above criteria, or are unlikely to become available, the NRF considers that retailers are entitled to an approach which allows regulation of prices with direct retailer input into the setting of the cost of a particular service. The recommendations contained in the document are broadly consistent with the above criteria, however, there are a number of areas of concern to the NRF. Of particular concern are: the perceived difficulty in risk management, and the inadequate proposal for transition to uncapped market ancillary services. General concerns The general concerns fall into the following categories: cost/benefit of the proposal implementation program retail price controls ability to hedge accountability and market confidence 1. Cost/benefit The NRF has been concerned since the establishment of the NEM with the spiralling costs of ancillary services and the inappropriate method applied for the allocation of costs arising from the provision of ancillary services to the market. The existing arrangements are fundamentally flawed resulting in a significant, permanent and detrimental impact on all retailers. Despite concerns being raised, the costs have risen unchecked without any appropriate economic signals to manage the level of ancillary services being provided. The NRF was disappointed to hear NEMMCO at the Code Change Panel Forum held on 18 February 2000 appear to indicate that, because ancillary services represented only 5% of the energy market, it was becoming a larger issue than it should have been. This was a clear indication of NEMMCO’s lack of sensitivity to the spiralling costs of ancillary services and the significant impact it was having on the retail sector of the NEM. All the current proposals should have a demonstrable cost benefit. In many instances this is not an easy task to perform, however, if the industry is to embrace the proposed changes there must be some basis for assessing that the changes will provide a net benefit. If there is not a demonstrable net benefit, the existing procurement arrangements should remain and be improved as far as possible. Many of the Light on the Hill (LOH) proposals are very ambitious and potentially costly. For example, the proposed load flow model for NCAS is a major exercise potentially requiring a research project and advanced software developments. This is likely to be expensive and needs detailed cost/benefit analysis prior to commencement of the work. The transitional arrangements should also have a more robust cost/benefit than is contained in the consultation document, such that it is apparent that there is an overall net benefit reasonably expected. The cost-benefit analysis also needs to address the incremental benefits represented by the move from the transitional to the LOH proposals. It is possible that, for instance, the major part of the expected benefits will be delivered by the move to competitive purchasing, while the LOH position represents significant additional costs to industry participants for relatively little return. Regrettably no cost-benefit analysis has been undertaken resulting in the Panel being asked by NEMMCO to accept the proposals under a theoretical basis. This alone should be sufficient grounds for not proceeding with the proposals at this stage. 2. Implementation program The NRF has concerns that there is a clear trend in the current market, which has only been operating for fifteen months, to seek change rather than to allow the existing arrangements to be adequately assessed. A pragmatic approach is needed for the implementation of each element. It is important that each transition stage is implemented fully, allowed to bed down then reviewed prior to moving to the next stage. This will allow the benefits of the measures to be realised and the real impact of the new arrangements to be analysed. The market should not attempt to implement too much too quickly and end up either delivering nothing or the costs of implementation escalate such that the cost/benefit is compromised. This is particularly relevant in the case of NCAS where the proposals, even for transition, are complex and not fully defined due to other reviews being carried out. A pragmatic approach is needed such that each step is fully delivered, even if this means that the transition is carried out in more stages over a longer timescale. The current timetable of NEMMCO appears to indicate that the implementation of the current proposals would be likely at best by October 2000. NEMMCO is clearly being pressed to implement the new proposals as soon as possible, whilst indicating a valid concern to ensure that the appropriate systems are developed and fully tested prior to implementation. Regrettably, there is also a concern for NEMMCO that the existing ancillary services contracts expire on 31 December 2000 providing a time imperative on NEMMCO to commence the new arrangements. NEMMCO describe this as its “Drop Dead Date”. Concern is expressed that there is a possibility that a less than optimal First Stage will be commenced prior to 31 December 2000 in an effort to eliminate the need to conduct a new Ancillary Services ITT. The Code Change Panel should consider the potential ramifications of new arrangements implemented under strained conditions. 3. Retail price controls Currently, retailers operate in a partially regulated retail market, limiting the amount retailers can charge franchise customers. The time frame for the transition to the fully contestable market is variable and uncertain in all states except Victoria. Whilst these regulatory restrictions may finish once the market becomes fully contestable, there is no guarantee that some form of price regulation may not be in operation. The existence of price regulation inhibits the retailer’s ability to pass on increases in ancillary service costs to franchise customers. However, one objective of the new arrangements is that costs will reduce through competitive provision of such services. There is considerable NRF concern that the ancillary services costs for the current year are anticipated by NEMMCO to significantly increase over the 1998-99 levels. It was anticipated that the second round of contract negotiations would have reduced the costs of ancillary services through improved competitive tendering. The reverse has occurred. There is, at present, no detailed assessment of the likely level of prices and cost at each stage of the implementation. Given that mandatory provision, particularly of FCAS, is proposed to be removed then the costs may rise in the short term. Analysis of price impacts is required given the retailers’ inability to pass additional costs through whilst there are price controls in place. 4. Ability to hedge The proponents of an ancillary services market anticipate that once a market is established, then hedging activity will follow. This may be the case, however, the NRF is doubtful that a liquid two-way market in the proposed instruments will emerge, limiting the likelihood of the instruments providing a useful hedge market. To the extent that the costs of ancillary services such as FCAS have a relationship to energy consumption, retailers may be able to more inexpensively hedge through energy contracts rather than specialised instruments, preventing the emergence of a two way market. In addition, effective retailer participation depends on an ability to predict amounts and costs. In the short to medium term, the absence of relevant information is likely to prevent retailer participation. The proposals should be accompanied by a more detailed assessment of the potential for hedging, looking at likely demand by retailers and consequent market liquidity The lack of liquidity for energy hedges in some regions of the National Electricity Market suggests a potentially low availability of ancillary service hedge instruments. It appears that the proposed Code Changes have sought to limit the financial impact through the operation of a transitional relaxation of a price cap for “market ancillary services”. Proposed Clause 3.9.2A provides for the following transitional price capping: First 30 days - $500/MWh Next 30 days - $1,000/MWh Next 30 days - $2,500/MWh Thereon – VoLL It is noted that under the anticipated time line for commencement of the new arrangements, the price cap would disappear in the middle of summer. It is strongly submitted that this proposal be rejected as inadequate and inappropriate and replaced by a price cap of $300 for the two years. It is submitted that it would be appropriate to conduct a review of the development of the hedging market after the first eighteen months with a view to reassessing the level of the cap at the end of the two-year period. The NRF has significant concerns that the current proposal presumes that a hedging market will develop quickly (within one to three months). It is submitted that this is clearly unlikely and should be carefully managed until there is clear evidence that it has developed. Experience is required to be gained by all participants in the market to enable a secondary market to develop. Without experience, liquidity will not develop resulting in significant risks for retailers and loss of confidence in the market arrangements. The development of a “market ancillary services” market is a significant change in the market environment. It is instructive to see the existing NEMMCO proposal in the market for participant fees arrangements, which does not include a similar level of impact on market arrangements, provides for a three year phasing period. The Panel should carefully consider the provisions of the Clause 3.9.2A proposal and provide a measured introduction to ensure that the introduction of the market ancillary services arrangements are well managed. 5. Accountability and Market Confidence The NRF recommends that, following commencement, NEMMCO be required to provide regular and detailed information to the market regarding the actual expenditure, and allocation thereof, on ancillary services under the proposed arrangements. This reporting would comprise part of the MNRF proposed quarterly reporting to the market by NEMMCO of financial information. This would provide sound information upon which to review the operation of the new arrangements and the achievement, or otherwise, of the established objectives as well as building market confidence in the new arrangements. The market needs to know the extent of “causers” paying, which causers are objecting, proposed reallocation of payments and similar issues to ensure that the necessary confidence can be established. In addition to the above general concerns, there are specific areas of the recommendations regarding each ancillary services grouping where the NRF has specific comments. These are set out below. FCAS 1. The frequency standards appear onerous compared with other electricity systems. A wider tolerance would provide significant cost savings as the requirement for FCAS would be lower. An early review of standards should be undertaken. The latest time for completion and implementation of such a review is the date for interconnection between the Queensland and NSW systems. The removal of mandatory provision and the use of a common clearing price for the market may provide the most economic outcomes. The cost of what is allegedly currently provided “free” to the market is not known, therefore the level of the price is unclear. The NRF does not accept that the generation sector has been providing “mandatory ancillary services” without remuneration to date. That mandatory provision is currently part of the requirements for registration as a generator. It is a service provided in part exchange for the ability to operate in the NEM. That is, it becomes part of the costs of a generator to be recovered through energy revenue streams. The difficulty faced within the market is that if the proposal is implemented, it will not be possible to ensure that the generator energy revenue streams will be reduced following the change in arrangements. In effect, there will not be a compensating reduction in energy prices for the increase in ancillary services revenue streams of generators. 2. The small deviation service is heavily reliant upon NEMMCO’s load forecasts which drive the generator dispatch targets. The proposed deviation market identifies non- conformance of generators relative to their dispatch targets and attributes cost to them if they are performing to the detriment of the system. The balance is currently assessed as being attributable to loads, being the difference between the NEMMCO’s forecast and actual load after adjusting for dispatch non-conformance. There are two primary issues to be considered. Firstly, there is a clear inequity in that generators can directly address the non-conformance issue by ensuring that they actually meet their dispatch targets. Loads cannot respond in a way which ensures that NEMMCO’s load forecast is actually met. It is a desirable feature of the market that those facing the economic consequences can actually respond to mitigate those consequences. This is not the case here. Approximately fifty percent of the market load is regulated and there is no opportunity for retailers to influence customer behaviour of this segment of the retail market. To impose costs on retailers, and theoretically (only) customers, in circumstances where behaviour cannot respond or be modified is illogical. Secondly, the accuracy of NEMMCO’s forecast is a key driver of how much FCAS is needed and consequently what cost the retailers/loads incur. There must be a discipline on NEMMCO to make the load forecasts as accurate as possible. This cannot be a financial incentive as NEMMCO would merely pass this on via participant fees. Having retailers providing their own forecasts to NEMMCO would probably not improve the overall accuracy either. A best endeavours obligation on NEMMCO is the most likely outcome. To link the forecast error to load “non-conformance” seems inappropriate as only some is likely to be due to load “non-conformance”. The generators dispatch targets are also set at the “wrong level” due to forecast error such that it is inequitable to attribute, as proposed, the cost of forecast error only to loads. If the forecast were to be 100% accurate there would be no charge to loads. The question is how much is due to unforeseen load variation and how much to forecast error. The forecast error gives rise to erroneous dispatch targets which are as much a cause of the FCAS requirement as the loads. It is understood that NEMMCO proposes to develop a model to allocate, under the causer pays principle, costs for small deviation FCAS as there is likely to be no alternative method available in late 1999. It is of concern that the NEMMCO time imperative is controlling the type of facility implemented, rather than the best solution. The NRF proposes that the charging regime should be as follows: charge non-conforming generators which are performing to the detriment of the system the appropriate proportion of the costs (as proposed), and charge the balance which is due to forecast error on an equal basis across all market participants (generators and loads) according to the energy consumed or supplied. This would provide an equitable allocation of the load forecast error. This would also ensure that all market participants provide a suitable level of scrutiny of NEMMCO’s load forecast. NCAS 1. The proposals for NCAS are the least well advanced due primarily to the uncertainty around the outcome of other reviews which directly impact upon the ancillary services review. This area has the most complex proposals and care must be taken not to try to introduce too many complex measures too soon and end up delivering nothing. There is a clear dependency on a number of other reviews. Hence the changes that can be made should be very limited until the outcomes of other reviews are known. 2. The transition recommendations allow for a move to 50/50 charging between retailers and generators together with the removal of the mandatory provision. With the other changes being dependent upon other reviews. Removal of the mandatory provision cannot take place until the TNSPs negotiate with each generator the basic level of service that must be provided by the generator to safely allow the generators to be connected to the system. This is expected to be very similar to the current level of mandatory provision, however, an indication of this would be useful. In view of the lack of reform in this area, it is submitted that the first stage of the transition should move to a 50/50 charging regime – as per the existing ACCC ruling, a review of generator constraints and the networks to commence negotiation of the base level requirements of connection. The subsequent transition stages should be reviewed in the light of the outcome of the other reviews and a work program drawn up at that stage. SRAS 1. The “basic restart service” should cover the vast majority of customers. There will be a small number of special customers who require a premium service and are prepared to pay for this. The concept of a basic “minimalist” type of service for system restart is unrealistic and should not be considered. It may be that the basic service which satisfies all reasonable requirements is perfectly in order. 2. As outlined above, the basic service should cover the vast majority if not all cases. Thus the new regime is very similar, if not the same as the current service. The proposed move to equal cost sharing between generators and retailers is justified, subject to concerns held that no payment is intended to be made by TNSP’s. The concept of causer pays appears to have been overlooked for this ancillary service. Where a causer can be identified, the principle of causer pays should apply. Customers plainly benefit by having power restored and the generation sector clearly benefits by, and is reliant upon, being able to bring its product to market and to obtain a revenue stream. 3. It is submitted that the existing SRAS provided under the ancillary services contracts be declared as the proposed basic ancillary services which are allocated equally between generators and retailers. Given that there is very little proposed change from the current regime, a revised cost sharing arrangement could be implemented in advance of the balance of the other ancillary services arrangements. It does not involve the development of new systems – merely a change in allocation of costs. The following NRF members support the issue of this correspondence: 1. ACTEW Energy Ltd 2. Advance Energy 3 AGL (including AGL South Australia) 4. CitiPower 5. Energex Retail 6. Energy Australia 7. Ergon Energy 8. Great Southern Energy 9. Integral Energy 10. PowerCor 11. TXU Retail 12. United Energy The NRF would be pleased to discuss this letter at your convenience. Should you require further information or assistance, please contact me. Yours faithfully Tom Walsh Manager Retail Regulation Pacific Power On behalf of Pacific Power, I wish to express our full support for the NGF position on ancillary services. It is our view that the current code proposals with respect to NCAS are totally unsatisfactory and that all reactive capability should be purchased from the market and that there should be no mandated ancillary services provision under the NEC. Furthermore, we are concerned that the current Schedule 9G derogation which imposes substantial costs on generators from 1 July 2000 is inappropriate given the very substantial progress that has been made by the generators to date and that approaches should be made to extend the current cost recovery arrangements to a point when the new market is put in place. Russell Petch MANAGER/ENERGY TRADING PACIFIC POWER Submission to NECA Code Change Panel Ancillary services ultimately underpin a secure and reliable power system for all energy consumers. This principle is accepted and entrenched in the National Electricity Code. Security and reliability to a large extent has been provided by FCAS. Often the real value (like the usage) of ancillary services will be low, with occasional short periods of extreme requirements (when they are really valued). Requirements are high during low reserve periods, when is load changing and during frequency disturbances. During other periods ancillary service requirements are marginal. Therefore, the development of the proposed ancillary services market should focus on the product as insurance rather than a commodity. Addressing the Large Deviations Proposal End users will pay more for distortions LEGG in their report recommended that the cost of Ancillary Services should be born by those who are able to react on them. However, the consequences of this approach may be perverse as one of the methods that generators can reduce the cost 'they must pay' is by reducing production on large units - hence lowering their requirements for ancillary services. However, in doing so energy prices will be necessarily forced higher, leading to significantly higher overall costs for consumers (600MW FCAS lower cost vs. 17,000MW higher cost). The second perverse outcome would be for generators to increase their units’ commitment to avoid volatile cost on raise reserve. This would significantly increase costs, and volatility for lower reserve requirements during the low demand periods overnight. One of the very possible situations that can occur in the off-peak is the potential for prolonged spikes to occur because of a lack of “lower” reserve - because it is economically inefficient to shut down thermal units overnight. Generators in their push to reduce ancillary services costs (because they are being asked to pay) will move a proportion of their energy bids into higher price bands. Hence, these incentives will force low energy priced producers into the high priced reserve market, which will increase the overall marginal cost of energy. End users will 'pay for what they get' One of the fundamental economic principles in the COAG reform agenda is that, the beneficiaries of competition should bear the costs of providing the benefit. In electricity reform, if consumers wish to be provided with cheaper and more reliable electricity, they should bear the costs of this quality supply. It is economically illogical for enterprises acting in the commercial interests of its shareholders to assume additional risks to its operations but not the compensation for doing so. The reference is to the risk of underwriting the costs to end users associated with a system failure. Here, the associated losses in industry income can accrue to hundreds of $millions per day, while the average losses to generators amount only to the marginal loss in spot revenue (which is usually less than a million to many generators). Accordingly, the real value of ancillary services is its capacity as an insurance product, against power system failure, demanded by end consumers to ensure certainty of its energy requirements. A consequential outcome is that the equilibrium value for maintaining system security is not reached and therefore supply not efficiently addressed – resulting in greater exposure to the risk of “system blacks”. In such events, who will bear the cost liability to the economy (class actions)? Are we knowingly or unknowingly transferring the risk from customers to generators with a different risk profile? And who will be responsible for the costs involved and the result of long term market outcomes? This state will also increase the potential number of interventions by NEMMCO to rescue the system, amounting to increased evidence of market failure. Increased Volatile Spot Prices Another major concern is that this paradigm of a commodity- like spot market for ancillary services is inappropriate because ancillary services are required only for certain short periods that will create frequent price spikes in the ancillary service market which might be passed through to the energy market. Addressing Small Deviations Proposal It is extremely difficult to provide a detailed example of possible problems due to a lack of NEMMCO implementation document, please find below general concerns: Technological Bias Any 4s measurement may incur disputes regarding technological bias as they are in conflict with 1.3.b(5) objectives of the Code. In the control of Active and Reactive Power, different generators support system frequency in varying degrees of response time, therefore it is unjustified to use a single measure for response time as it unfairly penalises certain classes of generator technology (ie. Hydrolic turbine with reheat, turbine with our reheat, etc). Refer to P. Kundur, “Power System Stability and Control”, McGraw Hill, Inc. (pg.600, figure 11.21.b, and pg 594, figure 11.15). Misallocation of Cost for Providing Service The allocation methodology that NEMMCO seeks to implement will manifest an illogical situation where some providers of the insurance (ancillary services) may be in a position of paying for the very services provided. This may trigger some providers to withdraw or significantly reduce services. Has NEMMCO done any studies or analysis on system security and stability for the case of significant govenor retuning. System Security at Risk This misallocation of cost may cause significant change in the dynamics of the power system, which may increase system security risk. Providing less reliable services because of perceived risk, reduced reliability of services due to lack of funds for maintenance, deterioration of equipment without new capital invested. Potential for Energy Marginal Cost Increase We may see the marginal cost for generating units increase since they have a perception that they will be obligated to pay for ancillary services (generation units are unable to instantaneously generate at dispatched targets, ancillary services modulate the frequency deviations that are caused by changing targets). They may avoid to be marginal. Inconsistent AGC Tuning Parameters The physical performance of generators are significantly affected/dictated by NEMMCO’s remote operation of its AGC tuning parameters. A noted result of any parameter changes issued by NEMMCO, is the significant expenses incurred by generators re-tuning their generating units. Who will bear the cost for change in every AGC parameter? Technology driven market Arrangements will put NEMMCO in the position to intervene (which they admit publicly they do not want) at a technical level which fall outside market mechanisms. Such interventions will distort the market and decrese long term market liquidity. Some further questions: Has anyone established the value to customers in proposing such a market because the possible costs for this arrangement are: Cost for generators to retune governors Potential increase in marginal energy cost Potential system security at risk Significant cost for changes in AGC parameters We are seriously concerned that to date, we have not seen any documentation of detailed studies into the impact of the proposed Ancillary Services Market arrangements, and its impact on both system security and market design. These studies must be released for public information. Summary Recommendation Please find detailed recommendation in presentation attached as a part of submission Auction is established to ensure fixed cost for end users and provide initial market liquidity Customer pays both for large deviation (raise/lower) and small deviation Any requirements on 4sec basis are tested and studied before implementation Spot market as proposed by NEMMCO A subsidiary TransÉnergie Australia Pty Ltd of Hydro-Québec ACN 084 240 602 Level 11, 77 Eagle Street, GPO Box 7077, Riverside Centre, Brisbane, Qld, Australia 4001. (07) – 3211 – 8614 Fax: (07) – 3211 – 8619 email: [email protected] 3 四月, 2018 Mr. Stephen Kelly, Managing Director, National Electricity Code Administrator Ltd, Level 5, 41 Currie Street, Adelaide, SA 5000. Dear Mr Kelly, Re: Ancillary Service Review Introduction In its final determination on the National Electricity Code the Australian Competition and Consumer Commission (ACCC) stated: “The development of a market in the provision of ancillary services is desirable to generate the right market signals to achieve productive and dynamic efficiency with respect to investment decisions.….. Market signals are enhanced if ancillary services are recovered from the parties responsible for creating the need to the greatest extent possible”9. An outcome of this statement is that Clause 3.11.1 of the National Electricity Code (“Code”) requires the National Electricity Market Management Company (NEMMCO) “to investigate … the possible development of market-based arrangements for the provision of Ancillary Services”. The desire for more efficient outcomes (and the attendant lower prices for consumers) is evident in the National Electricity Code’s commitment to promoting competitive processes. TransÉnergie firmly believes that better outcomes for electricity market participants (both suppliers and consumers) will be produced through competitive market based processes. Consistent with the desire for better outcomes for electricity market participants TransÉnergie firmly supports: encouraging competition in the provision of network services where ever possible, encouraging market-based outcomes to planning and investment decisions in all parts of the electricity supply business, and 9 ACCC Applications for Authorisation, December 1997, p. 96. ensuring the alignment of the costs and benefits of investments in network assets, i.e., promoting the ‘user pays’ principle. The Review Process And Recommendations In order to assist with its review of ancillary services NEMMCO established the Ancillary Services Reference Group (ASRG) comprising NEMMCO, the National Electricity Code Administrator (NECA), Market participants and the ACCC. The ASRG prepared a framework for the review and then commissioned Intelligent Energy Systems (IES) to evaluate options and make recommendations in a two-stage process as follows: an evaluation of and recommendations on the mechanism that should apply to the classification, procurement, pricing and dispatch of each defined ancillary service; and a framework and recommendations for which Code participants should be charged for each ancillary service and appropriate charging mechanisms. For the purpose of analysis Ancillary Services were classified as follows: Frequency Control Ancillary Services (FCAS) are concerned with balancing power supply and demand over short time intervals throughout the system; Network Control Ancillary Services (NCAS) are concerned with maintaining and extending the operational efficiency and capability of the network within secure operating limits; and System Restart Ancillary Service (SRAS ) are concerned with recovery from a partial or total power system failure. FCAS and NCAS are further divided into those required for continuous operation and those that are required to deal with contingencies. It should be noted, however, that these services would begin to overlap if steps are taken to utilise networks more intensively. In other words, the various services that constitute FCAS would be used both in continuous operation and in the event of certain contingencies. Having the “continency” services “on-call” would in itself constitute a continuous service. The ASRG’s recommendation is that costs incurred by NEMMCO for the purchase of Ancillary Services should be assigned, where possible, according to the ‘causer pays’ principle. Consistent with that recommendation it proposed that costs be allocated as follows: Where two-way markets can be established the requirement for the service and the costs of provision will be determined by competitive supply and demand rather than centrally, the service should be priced according to normal competitive market principles. No external funding or central planning for the provision of those services would be required. In other cases there may be no prospect of establishing two-way markets. In these cases the costs will be allocated according to those who caused the need or who are assessed as the beneficiaries of the service. Where security and reliability standards are breached or threatened some additional costs might be incurred by NEMMCO. These costs would first be allocated according to those who caused the need for them or who are the beneficiaries of their provision. Where causers or beneficiaries cannot be determined, residual costs will be allocated according to metered energy on both sides of the energy market. IES finalised its review in August 1999 with the publication of two Reference Group Reports. NEMMCO presented its final recommendations (based on those reports) to the National Electricity Code Administrator (NECA) in October 1999. NEMMCO has recommended that ‘the greatest scope for competition to be introduced in Ancillary Services’ is in the area of Frequency Control Ancillary Services (FCAS)’. In addition NEMMCO recommended that ‘the existing NCAS arrangements will initially remain in their present implementation10’. NEMMCO’s primary concern regarding new arrangements for NCAS appears to be that there are a number of regulatory and policy issues concerning Transmission Network Service Providers that need to be ‘clarified and bedded down’ before it can recommend establishing market based arrangements for the provision of NCAS. In particular, there are reviews in the areas of transmission pricing, regulation and Code responsibilities. NEMMCO’s concern appears to be that if it makes recommendations based on assumed outcomes that the recommendations will need to be revised if its assumptions are incorrect. Consequently, NEMMCO is recommending no immediate action in this area. TransÉnergie’s primary business focus is the development of market based network services. To date TransÉnergie has focused on the development of network services for delivery of energy. However, consistent with its business focus TransÉnergie also has an interest in market based arrangements for the provision of Network Control Ancillary Services (NCAS). While FCAS may have the greatest scope for introducing competition TransÉnergie is concerned that giving FCAS the greatest scope in NEMMCO’s ‘First Transitional Phase’ would mean that essential work developing NCAS markets might well be unnecessarily delayed, with an attendant loss of efficiencies in both the short and long term. Benefits of an NCAS Market In TransÉnergie’s views there are very good reasons not to delay the implementation of an NCAS market. NCAS Costs Recent NEMMCO publications forecast the total cost of providing Ancillary Services to both the Southern interconnected system and the Queensland region in the 1999-2000 financial year as being in excess of $200 million (a marked increase over the previous forecast). These same publications estimate the cost breakdown between the three categories of Ancillary Services as: Frequency Control Ancillary Services 65% (ie. $130 million) Network Control Ancillary Services 25% (ie $50 million) System Restart Ancillary Service 10% (ie $20 million) 10 ‘Ancillary Services Review – Recommendations, Final Report, NEMMCO, 15 October 1999, Executive Summary’. However, while the breakdown above accurately reflects the costs of Network Control Ancillary Services (NCAS) as contracted by NEMMCO, it does not reflect the total cost to market participants of providing all NCAS services ie voltage control continuous and contingency, stability and network loading control and spot market trading benefits. This is because additional NCAS services are also provided by the Network Service Providers through investments in capacitors and static var compensators whose costs are recovered through transmission use of system (TUOS) charges. While the total value of these investments is not known, it is noted that the total New South Wales expenditure on new system reactive plant over the period 1999/00 to 2003/04 is estimated to exceed $32 M11. NCAS Investments to Increase Incumbent Network Service Providers have recognised that increasing the utilisation of existing networks assets is encouraged under the NEM asset valuation and network pricing arrangements. Furthermore, the difficulties in permitting new overhead transmission facilities further encourages the deferrals of environmentally difficult investments, and favors higher asset utilisation through “point source” investments that effectively provide NCAS. These strategies are more likely to minimise the risk of stranded network assets. Options for increasing the utilitisation of existing network assets include arranging for demand side response to contingencies and/or network support by generators and careful attention to reactive and voltage control ie the provision of ancillary services. In fact in a recent publication Powerlink indicated that the first step in their preferred approach to network augmentations is: ‘Installation of SVCs and/or shunt capacitors to increase the capacity and utilisation of the existing transmission assets to the maximum practicable level12.’ Therefore it needs to be recognised that investments to provide reactive support are likely to increase above present levels. The need for, and efficiency gains from, competitive processes in both the pricing and provision of NCAS will be greater as increased use is made of these processes. NCAS Requirements will Vary Ancillary Service requirements will vary with the power generation profile in response to the outcome of the generator bidding process. This means that potential security problems due to unacceptable voltage profiles may be hard to predict ahead of time. Therefore the need for compensation could move between critical points in the network. It has also been pointed out that NCAS requirements will vary if they are used as a short term mechanism to increase the level of utilisation of assets until an investment in (for example) a new transmission line is justified. The value of several NCAS services is thus a function of the level of new transmission investment. Novel solutions to providing NCAS at the lowest cost to the market should be encouraged through competitive processes. At the end of the day, NCAS provide additional transmission capacity to market participants. With these services, more energy can be transmitted from producers to consumers. Consistent with the trend to provide transmission capacity through market mechanisms (e.g., the introduction of Market Network Service 11 ‘New South Wales Annual Planning Statement 1999’, Appendix C2, Transgrid 12 ‘Transmission Planning in the Queensland Electricity Market’ P. Wright, 12 th Conference on the Electricity Supply Industry, Nov 2-6, 1998, Pattaya, Thailand. Providers and the consideration of nodal energy pricing), pricing for and provision of NCAS should be shifted to a competitive market basis wherever possible. Energy Trading Limits NCAS inherently define secure network operating (and therefore energy trading) limits. IES has observed that13: ‘there is no basis for believing that [present network operating limits] currently define limits that reflect the priorities of Market Participants in the current market-trading regime….’ and ‘Once these [network] operational constraints are defined, there is an identifiable trade- off between the provision of these services and the ability for [energy] trade to occur over the network…’. That is, intelligent investment in NCAS services could lead to an increase in energy trading with consequential benefits to all market participants. For example, TransÉnergie is presently developing Murraylink as an HVDC underground interconnection between South Australia and Victoria. Murraylink will be in parallel with the existing Heywood interconnection. It is expected that such a configuration could enable power transfers across Heywood to be increased above present levels, to the benefit of all market participants. This increase would arise from specific NCAS that could be provided by Murraylink. If NCAS are priced and provided on a market basis, TransÉnergie can evaluate the cost effectiveness of providing those services, and thus increasing the effective capacity of the Heywood interconnector. NCAS Services The Ancillary Service Reference Group Reports proposed NCAS arrangements for voltage control continuous and contingency, and stability and network loading ancillary services to support energy transfers across the network (in the face of possible contingencies) through competitive two-way spot markets, coordinated with the energy spot market and dispatched by NEMMCO. The Reference Group Reports also identified spot market trading benefits as an Ancillary Service which included any service that shifted the technological and economic boundaries that constrained market operations in the NEM at any given time. IES observed that its proposed arrangements would support long term contracting either by NEMMCO, Network Service Providers, entrepreneurial NCAS providers or parties in the business of selling network hedges. That is, there are potentially multiple NCAS service providers. Recommendations IES has suggested5 a series of manageable steps towards establishing an NCAS market. Committing to a feasible implementation of these steps from July 2000 would immediately lead to better outcomes for electricity market participants. In particular, TransÉnergie agrees with IES that: As current operating limits were determined in a closed process, the trading limits that 13 ‘Evaluation of Options for an Ancillary Services Market for the Australian Electricity Industry” IES August 1999, Section 7.4 they define need to be better understood. As a matter of urgency it should be confirmed that the present trading limits reflect the priorities of Market Participants in the current market-trading regime. For example, TransÉnergie understands that there is some evidence that the limits as currently defined do not reflect the potential for demand-side response. Once these operational constraints are defined, there is an identifiable trade-off between the provision of these services and the ability for trade to occur over the network. This trade-off supports the possibility of two-way markets in NCAS. This review of operational constraints should be carried out through a public process by an Independent Third Party with no financial interests in the outcome of the review. In the short term, and on a regular basis (eg not longer than six monthly) NCAS services should be provided through a competitive tender process. This approach recognises additional work may need to be done to provide a foundation for more competitive NCAS provision. The NCAS services tendered should be for all NCAS services, including those presently supplied by equipment whose costs are recovered through TUoS charges by Network Service Providers. NEMMCO should extract and publish the pattern of shadow prices from the SPD process for different NCAS, to the extent that such shadow prices can reasonably be determined from the nodal energy prices. These shadow prices would reflect the costs associated with each (or at least the most significant) generic constraints used in the SPD process, and would thus provide initial price signals for the competitive provisions of NCAS. NEMMCO should take account of this shadow price information when determining the appropriate quantum of NCAS to acquire in its contract tenders and negotiations, and the various options available to supply the required ancillary services. To support later development of an NCAS trading regime, and in particular arrangements for continuous voltage control and enhanced spot trading: NECA should implement the Code changes necessary to ensure that currently regulated network facilities, retailers, distributors and end users that participate in ancillary service provision and consumption are treated on the same basis as other Participants; and NEMMCO should develop an SPD model based on AC load-flow analysis and operate it in parallel with the current SPD for testing and evaluation purposes. Conclusion TransÉnergie views the establishment of competitive markets for provision of Ancillary Services as essential in order to lead to better outcomes to all market participants. Consistent with that view TransÉnergie fully supports the establishment of competitive markets in both Frequency Control Ancillary Services and Network Control Ancillary Services. Regards, Dr. A. Cook Managing Director Rachel Playford NECA Level 5 41 Currie Street Adelaide SA 5000 Dear Rachel Code Change Panel: Ancillary Services Thank you for the opportunity for TransGrid to pass comment upon the Code Change proposals in relation to the important subject of Ancillary Services (AS). Please find attached TransGrid’s general and specific responses to the Code Change proposals, and our concerns in particular upon the impact of these changes upon connection agreements, and the added discretionary powers NEMMCO are contemplating in relation to AS standards. TransGrid has no specific comments on provisions relating to market AS, but we would like to draw NECA’s attention to some general theoretical concerns as to the position taken both by NEMMCO and NECA on various FCAS and NCAS proposals14. TransGrid would also like to express our concerns with the possible changes to TNSP service level requirements and risk profiles (eg the possible TNSP liability for large scale NCAS as proposed by NEMMCO in phase 2 commencing in July 2001), that have not been included in the recent ACCC revenue cap decision that will apply until 2004. As it stands there is no recognition in NEMMCO’s reform program of this issue and their program should be reviewed to satisfactorily address this matter. In conjunction with this submission, TransGrid is also deeply concerned with the lack of analysis of the specifics or practicalities of a ‘two way’ market for NCAS and large scale FCAS in the LECG/EMC “Who Should Pay For Ancillary Services” (January 25, 2000 paper). I trust that these comments are of assistance and provide NECA with a clear understanding of TransGrid’s stance on the proposed evolution of ancillary services in the National Electricity Market. Yours sincerely Garrie Chubb 14 A full transcript of TransGrid’s concerns in response to the 1999 Ancillary Services Review, dated September 1999, is attached as an appendix for your reference. TransGrid Submission – Code Change Panel (Ancillary Services) – February 11, 2000 A/Manager / Regulatory Affairs. FCAS In general, TransGrid believes that there are significant challenges, in implementing a ‘causer pays’ environment in relation to large scale FCAS. It should be noted that the LECG/EMC paper makes only limited progress on this matter (see Appendix IV). For example how would the prospect of an interruption of more than 600MW due to a transmission system failure be treated? The paper makes no comment on an assertion that it is the users of the transmission system that are the basic cause of the need for FCAS not the transmission system itself. TransGrid is also not convinced of the theoretical soundness of the proposed “causer pays” principle as it relates to network contingencies. The only circumstances where a network contingency can be involved in a LDFCAS “event” is where a single network contingency results in the disconnection of a large generator or load, or causes the power system to split into islands. In all cases it is the pre- contingent power flow over the network element that drives the need for the service. In most cases it should be possible to identify the parties that require this flow (ie those who benefit from it, to the extent that they should be willing to pay). In relation to Small Deviation FCAS, there are possible flow-on implications for support systems such as SCADA that TNSPs generally provide for NEMMCO. TransGrid is aware of there being many delays and errors in the signalling of dispatch instructions, and measurement through SCADA that need to be carefully evaluated. These problems could well result in an unfair allocation of the costs of such services. NCAS TransGrid support’s NEMMCO’s caution in relation to taking NCAS reforms too fast. In addition, it should be noted that the LECG/EMC paper (published by NECA, January, 2000) does not address practical implementation issues or seriously describe any examples from around the world where NCAS markets operate in the way proposed in the light on the hill ‘ideal’ model. It is also important to realise that the NSW Government public policy position is strongly opposed to complementary developments such as full nodal pricing, which may circumscribe the capacity of models underpinning these Code Changes. Other related TransGrid concerns about NCAS policy and proposals are succinctly addressed in the discussion upon NCAS in the attachment. Comments on Proposed Code Changes General TransGrid Submission – Code Change Panel (Ancillary Services) – February 11, 2000 In this regard the powers of NEMMCO for determining, acquiring, and dispatching non-market ancillary services needs further checks and balances that have not been included (eg proposed new sections 3.11.4, 3.11.5, 3.11.6, and 3.11.7). This is an important point, as TransGrid’s experiences with other regulators eg. IPART and ACCC suggest that due process and transparency are vital to achieving effective regulation. Anywhere that NEMMCO receives powers to determine procedures, the process for arriving at those procedures must provide reasonable opportunity for affected parties to comment and NEMMCO must be obliged to publicly and transparently address any comments. For example sections 3.11.3, 3.11.4 (b), 3.11.6, and 3.11.7 each need to include a requirement for NEMMCO to provide a reasonable opportunity for comment on any new proposed procedure and to publish its reasons for any decisions in relation to any comments received. This is particularly relevant in 3.11.4 (b) because of the flow on effects to connection agreement negotiations. NEMMCO should also be required to conduct a fair and reasonable tender process under Section 3.11.5. As it stands NEMMCO has very broad powers to conduct any ‘ill-considered’ process it chooses. Specific Network Control Ancillary Service (NCAS) Comments re proposals put forward by NEMMCO. Clause 3.11.4 – NEMMCO to set Minimum Standards The proposal contained in clause 3.11.4(b) provides NEMMCO with the right to set the minimum standards for ancillary services to be contained in connection agreements. This is unacceptable and the standard should be embodied in the Code. The arguments for this are as follows: NEMMCO is responsible for the operation of the market to defined standards which have been established through consultation with impacted Code participants; NEMMCO should not have the right to set the standard to which it operates the power system; NEMMCO is not paying for the acquisition of ancillary service through the connection agreement. It is an obligation placed on the network operator and network user. If NEMMCO is not paying for the service, then it is inappropriate that they have the sole determination of what should constitute the standard; If standards are changed, then this should be via a code consultation process. NEMMCO’s proposal gives them absolute power to change the standard. Connection Agreements are binding, but are structured to ensure they cope with changes in the code. Should NEMMCO amend ancillary service standards, TransGrid Submission – Code Change Panel (Ancillary Services) – February 11, 2000 which is not a code change, it will make renegotiation of the connection agreement difficult. NEMMCO’s proposal effectively gives them the right to amend a contract to which they are not a party. TransGrid therefore strongly supports the NCAS minimum standards for connection agreement should be defined in the Code, rather than at NEMMCO’s discretion. Section 3.11.4 (d) absolves NEMMCO from any obligation ‘for payment to a Code Participant’ for services provided under a connection agreement. This clause needs further review before going to the ACCC for authorisation. It must be amended to ensure that TNSPs are not commercially disadvantaged as a result of NEMMCO decisions affecting the terms of connection agreements. Other Clauses and Schedules Clause 4.3.4 (d) It makes reference to “ or similar service”. This is far too non-specific, and NEMMCO should clearly specify what this relates to. Clause 4.5.1(f)(3) TransGrid only agrees to clause 3.11.4(b) provided the minimum standards are embodied in the Code. Clause 5.3.6(c1) TransGrid does not believe this clause is necessary if the minimum standards are defined in the Code, and on this basis believes the clause should be deleted. Clause 5.4.2(c) TransGrid does not believe this clause is necessary if the minimum standards are defined in the Code, and on this basis believes the clause should be deleted. S5.2.5.1 TransGrid agrees with the code change put forward as it removes the ambiguity in interpretation which previously existed, where some generators were putting forward an interpretation based on the ‘wedge’ which would have resulted in unnecessary additional ancillary service payments to generators. Other Editorial Comments & Suggestions on Code Changes 3.11.3 (d) add … subject to following the consultation process under 3.11.3 (e). 3.11.4 make explicit the term Network Control Ancillary Services (NCAS) TransGrid Submission – Code Change Panel (Ancillary Services) – February 11, 2000 3.11.6 (c) add … subject to following the consultation process under 3.11.6 (d). There appears to be an inconsistency in the use of TSFCAS in clause 3.15.6A (h) and TRFCAS in 3.15.8(h) (2) to denote amounts for the regulating services. There appears to be an inconsistency with the use of TASP in 3.15.8(h) (2) compared to 3.15.6A. (c) which uses TNCASP in the equation. It also would be beneficial in Chapter 10 to clarify, which definitions are amended or new, change marks should be shown on the amendments. Should you wish to discuss any aspect of this submission, please contact the Manager/Regulatory Affairs at TransGrid on 02 9284-3434. TransGrid Submission – Code Change Panel (Ancillary Services) – February 11, 2000 Attachment: TransGrid Comments on “Ancillary Services Review – Recommendations”, Sent to NEMMCO September 1999. Small Deviation FCAS TransGrid is not convinced that the theoretical basis for the proposed energy (power) deviations market is sound. It is recommended that more work be done on this, including the conduct of trials, before committing the market to move in this direction through a Code Change. In particular, it should be noted that: 1. The calculation does not attempt to measure frequency response: rather this is inferred by the measurement of power deviations. 2. Measurement of load demand is not attempted: rather the total generation is taken as a surrogate for total load. This assumption is incorrect if frequency is changing. 3. Deviations of load (total generation) from the dispatch reference are taken to be evidence of load response: in fact what is being measured is the error caused by the approximation of a linear progression of the generation target, plus the error in NEMMCO’s load forecast. 4. If load variation was random, and there was no systematic bias in the load forecast, one would expect these deviations to sum to zero over a reasonable period. Hence the reset period for successive calculations needs to be carefully considered. 5. There are many delays and errors in the signalling of dispatch instructions, measurement through SCADA and computation of targets that need to be carefully evaluated: these could well result in an unfair allocation of the costs of the service. Large Deviation FCAS TransGrid is not convinced of the theoretical soundness of the proposed “causer pays” principle as it relates to network contingencies. The only circumstances where a network contingency can be involved in a LDFCAS “event” is where a single network contingency results in the disconnection of a large generator or load, or causes the power system to split into islands. In all cases it is the pre-contingent power flow over the network element that drives the need for the service. In most cases it should be possible to identify the parties that require this flow (ie those who benefit from it, to the extent that they should be willing to pay). The SPD formulation of this problem should be such that there is an optimal trade-off between the provision of FCAS and the power flow, and hence upon the dispatch of generators and loads. These trade-offs would be entirely settled within the energy market, and would not involve the network (apart from MNSP’s). This solution would be sub-optimal if it did not also include potential usage costs, suggesting either that there should be no separate payment for usage costs, (other than that provided via the market), or that the problem should be formulated to include usage costs. The fact that this may be difficult is no reason to default to the theoretically unsound approach of charging the network for usage costs. The payments for large deviation FCAS need further consideration on two grounds. 1. Although frequency is the same throughout an intact network, it would be expected that NEMMCO would require that the FCAS service be distributed across the network. For example, it may not be practical to cover the loss of a TransGrid Submission – Code Change Panel (Ancillary Services) – February 11, 2000 660 MW unit in NSW entirely by an FCAS service in South Australia (whatever its bid). There would therefore be interactions between FCAS, NCAS and security considerations that have not been taken into account in the simplistic example given. At the very least, the impact of these factors on the setting of the common clearing price needs to be considered. It would appear that regional FCAS prices (and settlement residues) might be involved. 2. The concept of “sudden death`’ payments by particular participants for FCAS is at variance with the basic principle of consistency between dispatch and pricing. There needs to be at least recognition of this fact, and some consideration of its impact. A special framework for rebidding may be an option. NCAS Matters of Principle TransGrid is concerned that a “full AC nodal pricing” solution is being proposed for the Light on the Hill while there has been insufficient debate about the public policy and market benefits of such an approach, The conduct of an ancillary services review is certainly not the forum for such a debate, but we are left with no alternative approach to NCAS if it is, in fact, concluded that nodal pricing is not a desired outcome. There is also a concern with the assumption that all future provision of NCAS must be entrepreneurial, when there has not been adequate debate about the policy aspects of this position either. It is possible to conceive of a model where entrepreneurial NCAS provision co-exists with regulated services within a linked regional pricing model. This is merely an extension of the hybrid AC interconnector concept. This should at least have been put forward as an option for discussion. It would not require the development of an AC nodal SPD model, so long as NCAS can be equated reasonably well with their effect on the level of inter-regional constraint. The latter concept may break down where increments of interconnector capacity due to various NCAS sources are not linearly additive (for example, where the value of one service depends upon the presence of another). Note, however that this could be a challenging task for an AC nodal model, based on linear programming. Clearly there needs to be further consideration of this before a commitment is made to the development of a costly replacement for SPD. Funding The concept put forward by IES of funding NCAS through a tax on inter-regional residues is also theoretically unsound, and NEMMCO should have rejected it outright rather that suggesting that it may have been a way to head had there not been other constraints. The only circumstance where funding in this way is acceptable is where it relates to a residue that has been created by bidding a price difference for the release to the market of an increment of inter-regional capacity (ie a situation analogous to a hybrid market network service). In this case the service is only dispatched in the presence of a price TransGrid Submission – Code Change Panel (Ancillary Services) – February 11, 2000 difference between the regions, and a positive income stream is both assured and directly related to the service. In the case of a regulated service, or a service provided under contract that is not bid in this way, the dispatch takes place at zero price difference. Consequently unless the link fortuitously constrains, the whole service may be dispatched without creating any income stream at all. It is clearly incorrect to pay for this service by “raiding” the inter-regional residue that has been created at other times and in other circumstances. Rather, the situation where the service was dispatched at a price should be emulated as far as possible. In this regard it is observed that the result of dispatching “at a price” is that the clearing price in the receiving region would be higher and, possibly but not certainly, the price in the sending region lower. Thus the dispatch of the service at zero price will have resulted in a saving in energy price in the receiving region, and customers in that region should be billed for the provision of that service directly, rather than through any adjustment of the settlements residue. They should only be unwilling to pay if the amount of the payment was in excess of the saving in energy. The benefit of the bid at price approach is that this is assured. The down side is that the price may be higher than that appropriate to a regulated framework. Unbundling of mandatory provision The re-negotiation of generator reactive power provision, although attractive as a concept, will have practical difficulties, and should not be trivialised. This is particularly the case where several generators share all or part of a network to get their product to market. In this situation, trade-off between the providers is possible, and there will be a natural inclination for generators to attempt to free-load off each other. It is not clear whether the suggested presence of NEMMCO, as a third party, will help or hinder these negotiations. The role that NEMMCO should take requires further consideration before commitment to this model. 6 March, 2000 Mr Stephen Kelly National Electricity Code Administrator Limited Level 5, 41 Currie St ADELAIDE SA 5000 Dear Stephen, Ancillary Services Review I appreciate the opportunity to comment on the proposed changes to the Ancillary Services arrangements currently being implemented. VENCorp’s comments on the Ancillary Services proposals, in general, have already been provided to NEMMCO in the initial round of their consultation process. I provide these comments as a follow-up to the recent forum on 18 February, where there were strong views presented, disappointed at the slow progress of formation of an NCAS market. I do not believe that the views of TNSP’s were properly represented. VENCorp generally supports the formation of markets in FCAS and NCAS, where there is a clear benefit to the industry. We strongly agree with NEMMCO’s recommendation to postpone the proposed NCAS arrangements, at least until the NEM Governance Review process is completed and the relative roles of NEMMCO and the TNSP’s is better understood. The Ancillary Services proposals do not adequately address the nature of the role of the TNSP and there is insufficient clarity on the transitional arrangements to have confidence that the transition will be smooth and in the best interests of customers. In order that there are no price shocks to particular sectors of the industry, each stage of the NCAS proposal would require strong transitional arrangements. This is not clear from NEMMCO’s proposals. This would require a progressive transition from the current mandatory provision of service to one where there is a flow through of payment for those services from the retailers to the generators via the TNSP. It is envisaged that at a later stage those services could be withdrawn by the generators. Such a transitional arrangement must, therefore, provide the TNSP sufficient lead time to install reactive support devices where generator services are declined or are too expensive. It is hoped that this would not be necessary and that the market would deliver the necessary reactive support services from the existing sources. I also agree with NEMMCO’s position on the requirement for full AC nodal dispatch in order to move to the final stage – the “light on the hill” NCAS spot market – to optimise dispatch for both the active and reactive markets. I would see this as a necessary pre-requisite. I am concerned, however, at the possibility that the formation of an NCAS market will require a re-definition of the role of the TNSP. The TNSP currently provides a level of energy transport services to the retailers as defined in his connection agreements with them and through various Code provisions. These define the level of security and reliability required by the end- use customers. The TNSP does this through the procurement of transmission lines, capacitor banks and other transmission support plant. The provision of reactive support (NCAS) devices is integral with energy transport services provided by the TNSP. Transmission lines can have a massive impact on an NCAS market, as transmission lines themselves provide significant reactive support. How will the effect of these be included in the spot market? There are complications also in relation to the TNSP having two revenue streams. How will the ring- fencing of a TNSP’s NCAS business from the regulated business impact the revenue test defining a TNSP’s income? On what basis could (or should) a TNSP carry out his transmission 82. planning in isolation from his ring-fenced NCAS market business? Can a monopoly TNSP maximise his profit by delaying the construction of a transmission line in favour of building more capacitor banks? Why should a TNSP strand his own capacitor bank assets by building a transmission line? On the other hand, can a TNSP reduce his risk by bringing forward transmission lines in favour of building capacitor banks? Bringing the TNSP into the market must diminish his responsibility for provision of sufficient services to maintain an appropriate level of security and reliability; or will the TNSP be required to be the “provider of last resort”? These issues are not brought out in the Ancillary Services Review and must be properly addressed before any Code changes can occur. The issue of the value of formation of an NCAS market has not been addressed in any forum. While a competitive market will generally lead to the lowest price – has anybody bothered to quantify this? The primary benefits obtained by the formation of an energy market, through the reduction of overheads and the significantly improved reliability and capacity factors of generation, would not be so apparent for an NCAS market. Capacitor banks are extremely reliable (far more so than generators) and the provision of capacitor banks is already achieved through competitive tendering. Considering the relatively low annual cost of such services, it would seem that any cost benefit would be absorbed by the significant increase in overheads throughout the industry to operate such a market. I hope that my comments have at least provided you with some food-for-thought and I look forward to hearing from you. If you have any queries, please feel free to give me a call. Yours sincerely John Howarth Manager Electricity Transmission Services, VENCorp Who Should Pay For Ancillary Services: An independent appraisal of NEMMCO’s recommendations A Report to The NECA Code Change Panel Kieran Murray, John Mather 25 January 2000 EMC Table of Contents I. EXECUTIVE SUMMARY...... 82 II. INTRODUCTION AND SCOPE...... 86 1. Introduction...... 86 2. Background...... 86 3. Approach and Structure of Report...... 87 4. Meetings with industry representatives...... 87 III. REVIEW OF DECISION HIERARCHY...... 90 1. The hierarchy...... 90 2. Two way markets...... 90 3. One way market and causer pays...... 91 4. Remaining costs allocated equally between participants...... 92 5. Mandatory standards not addressed in decision hierarchy...... 94 6. Decision hierarchy may founder on hard issues...... 94 IV. RECOMMENDATIONS ON FREQUENCY CONTROL ANCILLARY SERVICES...... 96 1. Applying the decision hierarchy...... 96 2. Small frequency deviation capability...... 96 3. Large deviation capability...... 99 4. FCAS recommendations advance efficiency, but need fine-tuning in phase two 101 V. NETWORK CONTROL ANCILLARY SERVICES...... 102 1. Applying the decision hierarchy...... 102 2. NCAS that effect power transfers...... 102 3. NCAS that support access...... 103 4. Progress on NCAS disappointing...... 105 VI. SYSTEM RESTART ANCILLARY SERVICES...... 106 1. Description of services...... 106 APPENDIX I: GAINS FROM OPENING FCAS TO CONTESTABLE SUPPLY – AN EXAMPLE ...... 107 APPENDIX II: CREATING INCENTIVES FOR COST REDUCTION IN NCAS...... 109 APPENDIX III: MINIMISING EFFICIENCY LOSSES WHEN ALLOCATING COMMON COSTS...... 110 APPENDIX IV: PAYMENT FOR LARGE DEVIATION FCAS – WHAT PROPORTION SHOULD THE LARGEST CONTINGENCY BEAR?...... 112 EMC Executive Summary Who should pay for ancillary services is as contentious in Australia as it is in every other electricity market. This appraisal reviews the recommendations relating to who should pay for ancillary services, which emerged from NEMMCO’s recent review. In particular, it assesses whether the proposed cost allocations provide participants with incentives to undertake an alternative action when that alternative would lower costs overall in the NEM. The appraisal does not consider other aspects of NEMMCO’s recommendations, and in particular, does not comment on the design of the proposed two-way or one-way markets. The appraisal: Evaluates whether the decision hierarchy adopted for the NEMMCO review is robust in terms of producing outcomes that are consistent with accepted principles of economic efficiency. Reviews whether the decision hierarchy has been applied consistently and appropriately in determining the recommendations in each stage, and whether the recommendations contained in the transitional phases are consistent with progress toward the ‘Light on the Hill’ recommendations. Frequency Control Ancillary Services (FCAS), Network Control Ancillary Services (NCAS) and System Restart Ancillary Services (SRAS) are considered in turn. The key conclusions from this appraisal are as follows: Decision Hierarchy Where two-way markets can be established effectively, the decision hierarchy is unambiguously in accord with achieving least cost outcomes while preserving price signals for future investment. However, where one-way markets are established and costs must be allocated, the ‘causer’ or ‘beneficiary’ tests may fail to identify a clear path forward, especially in complex areas such as NCAS. A better approach would be to allocate costs to provide participants with incentives to undertake actions that lower cost overall in NEM. As outlined below, NEMMCO’s recommendations largely achieve this outcome for FCAS, but considerably less progress is made with regard to NCAS. EMC Allocating any common costs equally between participants (i.e., over a broad base) is consistent within objective of minimising distortions to production, consumption and investment decisions. The decision hierarchy does not provide a basis for making decisions as to whether a specific service should be mandatory or not. Frequency Control Ancillary Services – Small Deviation NEMMCO’s recommendations relating to small deviation FCAS capability should enhance the efficient recovery of ancillary services costs. In the first transition FCAS phase, incentives will be created for generators to act in ways that lower the overall cost of maintaining the frequency standards. If the costs of measuring small deviations by market customers are prohibitive as stated, then spreading the costs of FCAS attributable to those deviations over market customers should minimise distortions to decisions during the transition. As a refinement, market customers who install acceptable mechanisms for measuring FCAS deviations should have an opportunity to participate in the same cost allocation or incentive regime as generators. The proposed two way market for the second transition period and light on the hill would lay to rest the contentious issue of who pays for this ancillary service. Frequency Control Ancillary Services – Large Deviation Spreading the cost of large FCAS deviations over as broad as base as possible until more sophisticated mechanisms are implemented should minimise distortions to decision-making during the transition. Substantial progress is envisaged in the second phase toward a structure where costs are borne by entities that can act to reduce the costs of ancillary services. The detail of how costs will be allocated amongst generators in the second phase should be revisited. The intra-generator allocation appears to create incentives for generators to second-guess the clearing price and may bias future grid and generation investment. Expected gains from allocating network contingency costs to TNSPs may be muted because the regulatory regime places constrains on the ability of TNSPs to react to the charge in a manner consistent with lowering ancillary service costs overall. EMC The light on the hill proposal to shift the emphasis to a usage market would improve further incentives to lower costs overall. Network Control Ancillary Services – Power Transfers Including generic constraints within SPD would improve the efficiency of allocation relative to the current environment. The light on the hill concept of a nodal active/reactive pricing model should in theory incorporate relevant NCAS into prices appropriately. Continuing to allocate residual costs narrowly (to market customers only) is not supported by the economic efficiency tests developed in the NEMMCO report. EMC Network Control Ancillary Services – Access Support The structure for allocating NCAS (assess support) charges does not appear to result from a careful and coherent framework that has as its objective the creation of incentives to minimise costs overall. NEMMCO’s review appears not to have reached a clear view as to how charges for NCAS could be structured to create incentives to minimise costs, nor identified the regulatory changes required to achieve this outcome. System Restart Ancillary Services NEMMCO’s recommendation to allocate costs of system restart services over as broad as base as possible (generators and consumers) is consistent with efficiency objectives. This universal service is purchased on behalf of all market participants. Allocating the costs of any supplementary service to the entities that request and are prepared to pay for the service should ensure the transaction is welfare enhancing EMC Introduction and scope Introduction On 15 October 1999, NEMMCO published the results of its review of ancillary services.15 One outcome of this review is a series of recommendations regarding how the costs of ancillary services should be allocated. The NECA Code Change Panel commissioned Kieran Murray of LECG and John Mather of EMC, to carry out an independent appraisal of the recommended cost allocations. This appraisal is limited to the recommendations relating to who should pay for the various ancillary services, and does not address other aspects of the recommendations. In particular, the appraisal does not comment on the practicality of the proposed arrangements for ancillary services. Background The recommendations regarding who should pay presented in NEMMCO’s report are based on a decision hierarchy proposed by Intelligent Energy Systems Pty Ltd (IES).16 In summary form, the decision hierarchy is as follows: Implement two way markets where possible. Where two way markets are not practical, allocate costs according to a principle of ‘causer pays’ or to those who benefit from the service. Where there is no obvious causer or beneficiary, allocate costs equally between market participants. Because some of the recommendations arising from the review may require changes or specific outcomes in other areas of industry reform or time required to implement, the recommendations were grouped into three distinct phases. These phases are as follows: First transitional phase (1 July 2000). Second transitional phase (from July 2001). Light on the Hill (3 to 5 years). Recommendations relating to the first transitional phase would result in the following allocation of ancillary service costs: 15 NEMMCO ‘Ancillary Service Review – Recommendations’ 15 October 1999 16 Intelligent Energy Systems Pty Limited, ‘Who Should Pay for Ancillary Services? A Project Commissioned by NEMMCO Ancillary Services Reference Group’, Final Report, July 1999. EMC Recommended Cost Allocation Service Cost Allocation Generators Customers Small deviation FCAS Causers as Residue after measured causers measured Large deviation FCAS (raise requirement) 100% 0% Large deviation FCAS (lower requirement) 0% 100% NCAS (TNSP provided – via TUOS regime) 0% 100% NCAS (mandatory) 100% 0% NCAS (NEMCO dispatched) 0% 100% SRAS 50% 50% Approach and Structure of Report The appraisal focuses upon whether the recommendations with regard to who should pay contribute to the efficiency objective set for the NEMMCO review. These objectives included achieving efficient outcomes for the marketplace in both the provision and procurement of ancillary services, while preserving price signals for efficient future investment so that ancillary services match needs over time. The appraisal emphasises the dynamic effects of the recommendations, and in particular, whether the proposed allocations provide participants with incentives to undertake an alternative action when that alternative would lower overall costs in the marketplace. The appraisal: Evaluates whether the decision hierarchy adopted for the NEMMCO review is robust in terms of producing outcomes that are consistent with least cost outcomes, while preserving price signals for future investment. Reviews whether the decision hierarchy has been applied consistently and appropriately in determining the recommendations in each stage, and whether the recommendations contained in the transitional phases are consistent with progress toward the ‘Light on the Hill’ recommendations. Frequency Control Ancillary Services (FCAS), Network Control Ancillary Services (NCAS) and System Restart Ancillary Services (SRAS) are considered in turn. Meetings with industry representatives EMC Views and comments of industry participants formed a critical input into the appraisal. In addition to reading the written comments provided to NEMMCO during its consultation period, meetings were held with a broad cross section of the industry, including representatives from: End-use customers Retailers Generators Network service providers Regulators and state officials NEMMCO The authors are very grateful for those who took time out of their busy schedules to talk with us and who have allowed this appraisal to be more informed. Though many participant and customers reiterated established views (which can be broadly summed up as “someone else must pay”), they also provided insights to resolving complex quality of supply issues. Some remarked that the significant delays in addressing this issue appropriately has ameliorated ingrained views and allowed them to understand different or opposing views. Market customers, in particular, commented upon how their understanding of ancillary service issues and trade-offs had increased. Several customers have also become more aware that they can manage their ancillary services consumption and potentially provide some of these services back to NSPs, retailers and the NEM on a commercial basis. These entities strongly supported measures that would allow customers to actively participate in the emerging market. With the advent of full retail competition, retailers expressed concern regarding how any ancillary service charges would be structured. Retailers anticipate significant difficulties trying to recoup costs from customers who have changed retailers, if charges are variable or back-dated. NSPs were generally comfortable with the recommendations, although some had hoped for more progress on determining responsibility for access and capacity. Most took the view that changes to ancillary service obligations affecting NSPs should be addressed as part of regulatory re-set negotiations. A number of market participants, end user advocacy groups and customers raised issues outside our terms of reference. These included issues relating to NEMMCO governance and its monopsony role in some of these markets, the ancillary service standards (in particular, whether they should be universal) and the complex and undefined boundary between regulated and unregulated services, standards and participants. Where we have been able to address these issues within our terms of reference, we have tried to do so EMC appropriately. We understand that NECA, NEMMCO and the ACCC are addressing many of the issues elsewhere. EMC Review of Decision Hierarchy The hierarchy The decision hierarchy upon which the recommendations presented in NEMMCO’s report are based was described by IES as follows: “ Where two-way markets in AS can be established, the costs of AS provision would be internalised into the market trading arrangements and the requirement for the service would be determined by competitive supply and demand rather than centrally. No external funding would be required. In other cases there may be no prospect of establishing two-way markets. In these cases the costs should be allocated according to those who caused the need or who are assessed as the beneficiaries of the service. Where security and reliability standards would be breached or threatened despite the above arrangements, some additional AS costs could be incurred by NEMMCO. These would be allocated according to those who caused the need for them or who are the beneficiaries of their provision, or, for any remainder where such causers or beneficiaries cannot be determined, according to metered energy on both sides of the energy market, as system security is a matter of importance to all market participants.” 17 Each of these three steps is assessed in turn below. Two way markets There can be little argument about the merits, from a perspective of economic efficiency, of ‘two way markets’, where such markets can be established. If participants could choose whether or not to buy or sell ancillary services, there could be no debate regarding whom to allocate the costs of the service. Participants would choose to purchase or provide services if the benefits to them outweigh the costs. In competitive markets, this balancing of cost and benefit should ensure transactions are welfare enhancing. The first step in the decision hierarchy, therefore, is unambiguously in accord with economic efficiency objectives. 17 IES Who Pays Report, section 2.5.1. EMC One way market and causer pays Where ‘two way markets’ are not practical, the decision hierarchy prefers ‘one way markets’, with the service procured by NEMMCO. In these cases, cost allocation would accord with the principles of either ‘causer pays’, or those who benefit from the service should pay. One way markets Opening the supply of various ancillary services to contestable supply through establishing ‘one way markets’, accords generally with economic efficiency objectives. This is because such processes establish a mechanism for finding the least cost provider in the long term. Indeed, removing barriers to entry (actual or perceived) in the provision of ancillary services and placing greater commercial incentives around ancillary service purchase functions has been credited elsewhere with substantial falls in the cost of ancillary services. Where barriers to entry have been removed, initial concerns about the potential for market power have usually not materialised as market participants find innovative means of competing. Existing regulatory processes and oversight are generally sufficient to monitor concerns over oligopolistic or monopolistic provider behaviour. Appendix I provides a frequency control example of the gains which can be achieved through opening ancillary services to contestable supply. Cost allocation Apart from careful attention to barriers to entry, ‘one way markets’ also require decisions on how costs should be allocated. The decision hierarchy proposes that costs should be allocated to ‘causers’, or to beneficiaries of the service. As IES observes,18 the concept of ‘causer pays’ is often associated with the idea of a Pigouvian tax. The core idea is that a charge should be levied on an entity whose activity creates costs for others. Pollution is the common example. Faced with the ‘true cost’ of its activity, the polluting firm may either take action which reduces the cost on others or, if that is not possible, pay a tax equivalent to the cost it imposes which can be used to compensate the other party. Such a tax may improve efficiency if the charge is calculated correctly and the entity can avoid or reduce the charge by eliminating or reducing the harmful activity. That is, a Pigouvian tax (or in this case, a cost allocation regime) enhances efficiency when it provides participants with incentives to adopt alternative actions which lower overall costs in the marketplace. One difficulty in reducing these concepts to a convenient phrase such as “causer pays” or “beneficiary pays” is that efficiency concepts may become blurred with notions of equity 18 IES, Who should pay, page 23. EMC or fairness. What matters for efficiency is how the charge may affect current and future (especially investment) decisions. If the entity deemed to cause or benefit from the service cannot reduce the charge by an appropriate, offsetting action, justification for the charge reduces to a notion of equity. A different concept of equity or fairness, would produce a different allocation of costs, and hence a charging structure based on an equity concept is essentially arbitrary. Conversely, an entity that is neither the ultimate causer nor beneficiary may be placed best to take actions that lower overall the cost of the service, such as customer/NSP co-operation. Appendix II provides an example of such a situation in relation to a NCAS. Because the terms ‘causer’ and ‘beneficiary’ can encapsulate both efficiency and equity concepts they do not provide a sufficiently sharp tool for allocating ancillary service costs. The test may fail to identify a clear path forward in complex areas of network interconnection such as NCAS. A better approach would be to adopt cost allocations which provide participants with incentives to undertake actions that lower costs overall in the marketplace. That is, to allocate costs to those entities that can act to reduce the cost of ancillary services. In a capital intensive industry and for capital intensive services like ancillary services, the incentives influencing future investment decisions are especially important. As discussed in detail below, NEMMCO’s recommendations for FCAS largely achieve this objective, but considerably less progress is made in relation to NCAS. Remaining costs allocated equally between participants The problem of common costs The decision hierarchy suggests allocating equally between participants any costs remaining after the first two stages. Costs falling into this category are viewed as arising from common services. That is, participants cannot choose whether to purchase the relevant service, nor is it practical to allocate the costs in a manner that would provide participants with incentives to take actions that lower overall costs. Charges resulting from an allocation of common costs are not a price signal to guide production and consumption decisions. As the ancillary service charge is a condition of participating in the market, the only relevant decision for a participant is whether to remain in the market. (Under the compulsory pool regime, a decision to leave the market is effectively a decision to cease business). A participant might derive a positive, zero, or significantly negative marginal benefit from the contribution of the relevant ancillary service, but might still remain in the market. While allocating costs incurred in providing a common service does not convey useful information for decision-making, such charges create an obvious risk to economic EMC efficiency through causing entities to alter their decisions in response to the charge. As the charge will reflect marginal cost or benefit only by coincidence, any change in behaviour due to an allocation of common costs would risk reducing economic welfare. From an efficiency perspective, the primary challenge is to allocate common costs in a manner that minimises these distortions. Minimising efficiency losses from common costs A body of economics, called the optimal tax literature,19 is concerned with developing rules for raising a given revenue requirement in a way that minimises the loss to economic efficiency. A key conclusion from this literature is that the total loss to economic welfare caused by charges to fund common costs is minimised when the charges are spread as broadly as possible. The reason why a broad base minimises efficiency losses is intuitive. Narrowing the base over which common costs are recovered means the amount levied on the remaining entities has to increase to meet a given revenue requirement. Recovering the same amount of common costs from twice as many entities roughly halves the charge on any one participant. If demand elasticities are similar, halving the price reduces the total inefficiency or dead-weight loss to approximately one quarter of its previous value – a fuller explanation of this point is set out in Appendix III. A dead-weight loss arises when an activity discouraged by the charge was worth more to participants than would have cost to provide. Measured against this simple but powerful result, the proposal to allocate equally between participants (i.e., the broadest base possible) any common costs remaining after the first two stages is consistent with an objective of achieving economic efficiency. Optimal tax literature also shows that having spread a charge over as many users as possible these charges can, at least in theory, be fine-tuned. One well-known theoretical rule for fine-tuning is the ‘inverse elasticity rule’ (or Ramsey pricing).20 This rule is based on the insight that if participants differ in their sensitivity to price changes, then an equal charge to all participants would make some participants choose to reduce their consumption too much, while others will reduce their consumption just a little. In these circumstances, increasing the charge for participants who are less sensitive to price changes, and reducing it for others, would reduce dead-weight losses. The optimal mark-up is inversely related to the demand elasticity of each participant. Some version of this inverse-elasticity result is the basis for all optimal utility pricing rules. In practice, the rule is very difficult to implement because the elasticity of each participant is not known and can be estimated only imprecisely. Nor can any estimate of elasticity (typically derived from historical responses) predict accurately how participants will respond to changes in the future. In the absence of empirical data to the contrary, allocating common costs over a broad base as suggested by the decision hierarchy is a sound 19 See for example, Samuelson, Paul, “Theory of Optimal Taxation,” Journal of Public Economics, vol. 30 Jul 1986, or Auerbach, Alan, ‘The Theory of Excess Burden and Optimal Taxation’, Handbook of Public Economics, vol. 1. 20 Ramsey, Frank, ‘A Contribution to the Theory of Taxation’, 37 Econ J 47 (1927). EMC approach to cost allocation. A process to test through time whether such costs are truly common would enhance the allocation method. Mandatory standards not addressed in decision hierarchy In addition to the above allocation methods, the costs of some ancillary services are allocated to the provider of the service through the use of mandatory requirements. The decision hierarchy does not address this issue explicitly, although mandatory provision is discussed in the IES report.21 As the industry seeks more efficient ways of providing ancillary services, mandatory provision will become increasingly subject to dispute. This is because mandatory standards will achieve economically efficient outcomes only in special circumstances. Mandatory standards are not typically conducive to economic efficiency because a mandatory standard does not provide a mechanism to identify the least cost provider. As a result, the total production cost of the relevant ancillary service is likely to be higher than the case where there is a market for the service. Mandatory standards also give rise to other costs. These include the cost of setting, monitoring, enforcing and reviewing the standard. There may also be costs associated with poor specification or rigidity of the standard over time. However, there may be instances where purchase contracts cannot be relied upon to ensure supply and the external affects of a failure to supply are particularly large, or where it is difficult to measure performance but easy to measure technical compliance. In these circumstances, the service may not be marketable in a practical sense, and a mandatory standard may be necessary to ensure system security. As discussed in section IV below, NEMMCO makes several recommendations to maintain mandatory standards. The decision hierarchy could usefully be expanded to provide guidance in assessing when it is efficient for services to be mandatory. Decision hierarchy may founder on hard issues In reviewing the decision hierarchy, this section concludes that where two-way markets can be established effectively, the decision hierarchy is unambiguously in accord with economic efficiency objectives. However, where one-way markets are established and costs must be allocated, the ‘causer’ or ‘beneficiary’ tests may fail to identify a clear path forward, especially in complex areas such as NCAS. This is because the ‘causer’ or ‘beneficiary’ tests can encapsulate both efficiency and equity concepts. A better approach would be to provide participants with incentives to undertake actions which reduce the cost of ancillary services. 21 IES, bid, page 26. EMC Where a charge must be levied to fund common costs, the total loss to economic welfare will be minimised when the charges are spread as broadly as possible. The approach set out in the decision hierarchy of allocating equally between participants (i.e. the broadest base possible) any common costs remaining after the first two stages is consistent with economic efficiency objectives. Finally, the decision hierarchy could usefully be expanded to provide a basis for making decisions as to whether a specific service should be mandatory. EMC Recommendations on Frequency Control Ancillary Services Applying the decision hierarchy This part of the paper reviews whether the decision hierarchy has been applied consistently and appropriately in determining the recommendations relating to Frequency Control Ancillary Services (FCAS). These are ancillary services concerned with balancing power supply and demand over short time intervals throughout the power system. Services within this category have been grouped by NEMMCO into small frequency deviation capability and large frequency deviation capability. Recommendations concerning each type of capability are discussed below. Small frequency deviation capability Summary of recommendations The purpose of the small deviation service is to keep system frequency stable at or around 50Hz under normal operating conditions. NEMMCO’s recommendations with regard to who pays for small frequency deviation capability can be summarised as follows: Transition Phase Who Pays First phase Causer identified using simplified measurement system. Generators assessed individually. Costs not allocated to generators, spread over market customers. Second phase Enablement market where those who contribute to frequency deviations pay and those that correct deviations receive payment. Light on the hill As above. Assessment of recommendations The recommendations accord broadly with the criteria established in section II of this appraisal for efficient recovery of ancillary service costs. Although NEMMCO adopts the term ‘causer pays’ it is clear from the context and detail of the recommendations that it intends these costs to be borne by those entities that can act to reduce the cost of ancillary services. EMC For the first transition phase, the allocation method will distinguish between generators and customers because of transaction costs. The relative performance of generators in causing and correcting small frequency deviations would be measured, and generators charged on the basis of aggregated deviations over the billing period. Individual generators can adjust behaviour to optimise their exposure to the charge, creating incentives for generators to act in ways that improve market efficiency. Because of measurement difficulties, costs of correcting small deviations that do not arise from the actions of generators will be allocated to market customers. If the costs of measuring small deviations by market customers are prohibitive, then spreading the cost of FCAS attributable to those deviations over all market customers should minimise distortions to decisions during the transition. This is consistent with the view that common cost only arise where transaction costs are high. A ‘two way market’ as envisaged in the second transition period and for the light on the hill would remove any debate over who pays for FCAS for small deviations. The concepts developed for the ‘two-way market’ are in accord with, but leading, international trends. The proposed changes offer considerable scope for achieving efficiency gains, and would lay to rest the contentious issue of who pays.22 Possible enhancement It may be possible to fine-tune the regime applying to customers in phase one. Some consumers of electricity can cause sharp load variations (e.g., arc furnaces and draglines), while others are extremely stable and contribute little to the need for FCAS. One option would be to allow market customers to ‘self-select’. Where market customers install acceptable mechanisms for measuring deviations, they should have an opportunity to participate in the same cost allocation regime as will apply to generators. Such an arrangement would create incentives for market customers with low measurement costs and/or potentially 22 As noted in the introduction, this appraisal does not investigate the practicality of the proposed arrangements. EMC large savings from more accurate measurement, to elect to measure and pay on actual deviations. Any remaining costs would be spread evenly over those market customers for whom the cost of measurement outweighs the gains from greater specification. There would not appear to be any significant practical difficulties preventing this option being extended to market customers. Self-selection regimes such as this exist in other areas of the electricity industry where costs of measurement are high. For example, where retail competition has been introduced, entities with time-of-use meters are typically allowed to elect to pay on time of use rather than deemed profiles. EMC Large deviation capability Summary of the recommendations The purpose of the large deviation service is to recover the system frequency following large disturbances typically caused by the loss of significant load, loss of transmission equipment, or loss of a generation unit. NEMMCO’s recommendations with regard to who pays for large frequency deviation capability can be summarised as follows: Transition Phase Who Pays First phase Generators (raise service) Customers (lower service) Second phase Enablement market costs paid by causer as identified through dispatch process. Causers would be defined as largest contingency dispatched. Light on the hill As above, but emphasis shifts from the enabling market to a usage market. Assessment of recommendations The recommendations concerning who should pay for large deviations accord broadly with the criteria established in section II of this appraisal for efficient recovery of ancillary service costs. In the first transition phase, costs are allocated over as broad as base as is possible to minimise distortions to decisions while more sophisticated mechanisms are implemented. In the second phase substantial progress is proposed towards a structure where costs are borne by those entities that can act to reduce the cost of ancillary services. The light on the hill phase builds on the second phase by shifting the emphasis to a usage market where the service can be bought and sold much like any other commodity. However, as discussed below under possible enhancements, the detail of allocation method would appear to contain significant difficulties and may need to be revisited if economic efficiency objectives are to be achieved. A criticism of the recommendations raised by a number of entities is that the proposed cost allocation (especially in phase two) takes no account of the probability of an item of generation or transmission equipment contributing to an event. This approach to allocation is aligned with current NEM security criteria, where it is the size of the potential contingency, not the probability of the event, which is relevant for scheduling. The light on the hill proposals would address this concern by moving to emphasise a usage market. EMC Possible enhancements Detail of allocation method may be counterproductive Appendix C of the ‘Who Should Pay for Ancillary Services?’,23 sets out an example of how costs would be allocated amongst generators in the second phase. Based on this example, the proposed method for allocating large deviation FCAS amongst generators and NSPs would appear to contain a number of difficulties, including: Creating an incentive for generators to try and second-guess the clearing price for energy. A generator that offers just under the clearing price will minimise its FCAS charge relative to a generator with identical capacity that offers at marginal costs (assuming the marginal cost of both generators is below the clearing price). This outcome would be undesirable from a perspective of enhancing efficiency in both the ancillary services and energy markets. Biasing future generation and grid investment decisions by allocating all of the FCAS costs to the largest contingency, rather than ensuring the largest contingency faces the full incremental cost of FCAS needed to cover the increased risk. Appendix IV provides a fuller explanation of the differences in the two approaches, and why the proposed method may bias investment. The concerns raised above relate to the detail of the intra-generator allocation and should be addressed before moving to the second transition phase. Regulatory barriers to enhancing efficiency One possible complication relating to the second transitional phase is that the regulatory structure may not allow all entities to respond in a manner that enhances efficiency. For example, the second phase envisages transmission network service providers (TNSPs) being allocated costs where the potential contingency is a network. However, the regulatory environment places constraints on the ability of TNSPs to react to the charge in a manner consistent with economic efficiency. Some of the factors influencing reliability, such as thermal limits and stability factors are controlled by NEMMCO not the TNSPs. Regulatory constraints may also prevent TNSPs from managing their exposure to ancillary service payments efficiently. For instance, unlike a generator, a TNSP is prevented from contracting to purchase FCAS through the market in order to offset any exposure. In these circumstances, the TNSP may be forced to manage its exposure through capital 23 Intelligent Energy Systems Pty Limited, ‘Who Should Pay for Ancillary Services? Ibid. , Appendix C, page 46. EMC investment, even when that is not the lowest cost option. These issues may need to be considered if the efficiency gains from cost allocation are to be maximised. FCAS recommendations advance efficiency, but need fine-tuning in phase two This section concluded that NEMMCO’s recommendations relating to small deviation capability should enhance the efficient recovery of ancillary services costs. In the first transition phase, incentives will be created for generators to act in ways that lower the overall cost of maintaining frequency. Because of measurement difficulties, the costs of correcting small deviations that do not arise from the actions of generators will be allocated across all market customers. It may be possible to fine-tune this regime by allowing market customers to ‘self select’. Where market customers install acceptable mechanisms for measuring deviations, they should have an opportunity to participate in the same cost allocation regime as generators. Spreading the cost of large deviations over as broad as base as possible until more sophisticated mechanisms are implemented should minimise distortions to decision- making. In the second phase, substantial progress is envisaged toward a structure where costs are borne by entities that can act to reduce the costs of ancillary services. However, the detail of the allocations method may need to be revisited before phase two is implemented. The intra-generator allocation appears to create incentives for generators to try and second guess the energy spot price and may bias new investment. Expected gains from allocating network contingency costs to TNSPs may be muted because the regulatory regime constrains the ability of TNSPs to react to the charge in a manner consistent with least cost outcomes. EMC Network control ancillary services Applying the decision hierarchy This part of the paper reviews whether the decision hierarchy has been applied consistently and appropriately in determining the recommendations relating to Network Control Ancillary Services (NCAS). These are ancillary services used for maintaining and extending the operational efficiency and capability of the network within secure operating limits. Services within this category have been grouped into services that support access by generators and supply to connection points, and services that have a measurable effect on network power transfers. There is no bright line boundary between these two categories, with reactive power included in both. NCAS that effect power transfers Summary of the recommendations NEMMCO conclude that recommendations in relation to NCAS may depend upon assumptions about the outcome of various reviews in the area of transmission pricing, regulation, and Code responsibilities. To minimise the risk of having to reconsider its recommendations for ancillary services, NEMMCO proposes no immediate action with regard to who should pay. However, NEMMCO does describe its light on the hill proposals for NCAS that effect power transfers and specifies some steps toward that goal. This combination of recommendations can be summarised as follows: Transition Phase Who Pays First phase Generators meet the costs of mandatory requirements Market customers meet the costs of TNSP services through TUOS charges. Market customers meet any residual costs Second phase Introduction of generic constraints in SPD would alter energy prices. Market customers meet the costs of TNSP services through TUOS charges. Market customers meet any residual costs EMC Light on the hill AC nodal pricing model establishes prices inclusive of reactive requirements. Market customers meet the costs of NSP services through TUOS charges. Market customers meet any residual costs Assessment of recommendations A full nodal active/reactive power dispatch and pricing model is intended to establish prices for spot energy reflecting reactive and real power demand and supply conditions. A ‘two way market’ of this nature, if achievable, should ensure the relevant NCAS costs are incorporated into prices appropriately. As a step toward the light on the hill recommendations, generic constraints would be included within SPD to express the relationship between the capability of the network and NCAS. Introducing such a constraint is expected to allow a broadening of the potential sources of reactive power and the prospect of reducing or eliminating the mandatory requirements currently placed on generators. These phase two changes should improve the efficiency of the market, relative to the current environment. The recommendations to continue allocating residual costs to market customers, however, are not supported by the economic efficiency tests developed in the decision hierarchy (either as developed by IES or as proposed in this appraisal). This aspect is considered further below. NCAS that support access Summary of the recommendations As with NCAS that support power transfers, NEMMCO proposes no immediate action with regard to who should pay for NCAS that support access. Combined with its light on the hill proposals, NEMMCO’s recommendations can be summarised as follows: Transition Phase Who Pays First phase Generators meet the costs of mandatory requirements EMC Market customers meet the costs of TNSP services through TUOS charges. Market customers meet any residual costs Second phase Market customers meet the costs of TNSP services through TUOS charges. Generators meet the costs of any residual mandatory requirements Market customers meet any residual costs Light on the hill Reactive power requirements specified and traded at network boundaries. Market customers meet the costs of TNSPs through TUOS charges. Market customers meet any residual costs Assessment of recommendations Under the light on the hill proposals, responsibility for purchasing the necessary services to maintain access would remain divided between NEMMCO and NSPs. Costs associated with these services would, for the most part, be charged to market customers, either by NEMMCO or via use-of-system charges. This structure of charges does not appear to result from a careful and coherent framework that has as its objective the creation of incentives to minimise costs overall. For instance, it is not obvious why charges by NEMMCO to market customers for the cost of services necessary to maintain network stability would give rise to actions which reduce the cost of NCAS. If the charge is intended simply to recover costs (and is not intended to provide incentives for decisions), the economic efficiency considerations are the same as those for recovering common costs or levying a tax. In the absence of empirical data to the contrary, allocating the ‘residual’ costs over as broad as base as possible, as suggested by the decision hierarchy (and explained in appendix III) would be a less distortionary approach to cost allocation. The preferred approach would be to try and identify entities whose actions, when faced with the charge, would lead to lower costs overall. NEMMCO’s reluctance to make recommendations to change existing arrangements, where those recommendations depend upon assumptions as to the outcome of yet incomplete reviews, is understandable. As noted earlier, the decision hierarchy developed for the review would not have assisted in identifying a clear path forward, as it EMC is impossible to identify the ‘causer’ or ‘beneficiary’ for most NCAS in an interconnected network. However, as the example in Appendix II illustrates, it is possible to identify entities that can act to minimise the overall costs of NCAS, and to structure charges to create incentives for actions that lower overall costs. The ancillary services review may have made a more constructive input into the various regulatory reviews if it had reached a clear view as to the parties that can act to lower overall costs, and how charges might be structured so as to align incentives with least cost outcomes. Those responsible for reviewing the current regulatory framework could then come to a view as to whether the regulatory restraints, if any, which prevent such an allocation give rise to public benefits that exceed the loss of incentives to minimise the costs of NCAS. Progress on NCAS disappointing Compared with the innovative solutions proposed for FCAS, NEMMCO’s recommendations for NCAS are disappointing. Introducing generic constraints within SPD to express the relationship between network capability and NCAS should improve incentives to minimise NCAS costs. Beyond these changes, very little if any progress is envisaged. . NEMMCO’s reluctance to propose changes which would depend on the outcome of other reviews is understandable. The structure recommended by NEMMCO for allocating charges does not appear to result from a careful and coherent framework that has as its objective the creation of incentives to minimise costs overall EMC System restart ancillary services Description of services System restart services, as the name suggests, are services contracted in advance to ensure the system can be re-started. Summary of the recommendations The review concluded that SRAS is not a prospect for a dynamically traded market, and recommended that the services be purchased through a competitive acquisition process. NEMMCO’s recommendations with regard to who pays for SRAS are as follows Transition Phase Who Pays First phase Shared equally by market participants Second phase Basic service costs shared equally by market participants. Supplementary services costs met by Light on the hill As above. Assessment of recommendations In general, allocating costs of system restart services over as broad as base as possible (generators and consumers) is consistent with efficiency objectives. The service is purchased on behalf of all market participants. Allocating the costs of any supplementary service to the entities that request and are prepared to pay for the service should ensure the transaction is welfare enhancing.24 24 The service may be difficult to define contractually under the current regulatory structure, as some jurisdictions are likely to intervene in the even of catastrophic system failure. EMC Appendix I: Gains from Opening FCAS to Contestable Supply – An Example NEMMCO recommends that spot markets be established for large deviation FCAS. These markets will be optimised with the energy spot market and discover clearing prices for providing frequency raise and lower services. NEMMCO will be the sole buyer of the service. Very similar market arrangements were implemented in New Zealand for large deviation services with the start-up of the wholesale market in October 1996. Prior to the start-up of NZEM, large deviation services (or instantaneous reserve as it is called in New Zealand) was purchased by the national transmission company, Transpower, under long term supply contracts. Generation was scheduled largely independently of reserve – at least, there was no dynamic interaction modeled between energy and reserve markets. The advent of NZEM provided generators and purchasers (interruptible load) with a mechanism to offer reserve into the spot market. Offers to supply instantaneous reserve (either spinning reserve or interruptible load) are in the form of price and quantity tranches for each trading period. For generators, the reserve offer is made conditional upon the level of output – that is, generators can make offers to supply reserve contingent on scheduled levels of generation. The model solves to find the least cost combination of reserve and energy offers. Providers of instantaneous reserves are paid an availability payment determined by the half-hour clearing price for reserve. Introducing a market clearing price for reserve and allowing interruptible load to compete on even terms with generation has had a dramatic impact on market share, the clearing price and associated payments for instantaneous reserve. The volume of interruptible load offered into the New Zealand market has increased from approximately 150 MW in 1996 to about 570 MW in 1999. A substantial proportion of the increase has come through the aggregation of large numbers of small users (e.g., water heating). Interruptible load now accounts for about 70% of scheduled reserve, where it is capped because of system security reasons. As shown in the graph below reserve prices have fallen substantially. Total payments for instantaneous reserves have fallen correspondingly from around NZ$12 million per annum in 1996 to about NZ$5.5 million per annum in 1999. EMC Reserve ($/MWh) Average Reserve Prices (outliers removed) $18.00 $16.00 $14.00 $12.00 $10.00 $8.00 $6.00 $4.00 $2.00 $0.00 7 8 6 7 7 7 8 8 6 7 8 8 9 6 7 7 8 8 8 9 7 7 7 8 8 9 7 8 9 7 8 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 ------l l t t t r r r r r r v y v y v c g c g c b p b p b n n n n n a u a u a c c c p p p a a e e e e e e e e a a a o u o u o u u J J J J J J J O F A S O F A S O F A D M A D M A D M N N N M M Date Average 6s Reserve Price Average 60s Reserve Price EMC Appendix II: Creating Incentives for Cost Reduction in NCAS The ‘causer’ or ‘beneficiary’ of ancillary services necessary to maintain the operational efficiency and capability of an electricity network are often not easily identified. For example, maintaining voltage levels within specified limits is important for maintaining transmission capacity, protecting equipment, and minimising transmission losses. Voltage levels within the transmission and distribution networks are maintained within specified limits by injecting or absorbing reactive power at certain nodes. Reactive power requirements are location sensitive. The amount of reactive power varies with changes in voltage and current flow, with the variation depending upon circuit components. Consequently, transmission and distribution networks and generator and load connected to them affect the derived measure of reactive power and, in this sense, each appears to either consume or generate quantities of reactive power. In reality, reactive power is an abstract in that it is the currents and voltages that have changed. Who benefits or causes the need for reactive power at any particular point is a matter of contention within an interconnected network. However, entities whose actions can reduce the overall cost of maintaining voltage levels are readily identifiable. For instance, it is feasible to specify and measure a power factor requirement at the boundary between a local distribution network and a transmission grid. A power factor requirement of 0.95, for instance, would mean that for every 10MW of real power drawn into a local network, 3.2Mvar of reactive power might also be drawn (consumed). Specification of such a requirement would allow distribution network companies to be charged for exceeding the power factor requirement. The light on the hill recommendations envisage trading of reactive power at boundaries between networks. Under such an arrangement, networks with high reactive power consumption could manage load, invest in capacitor banks or other equipment to maintain the power factor target, or alternatively ‘purchase’ reactive power from the transmission grid by exceeding the power factor requirement. Similar arrangements could be established for transmission network service providers. EMC As a first step toward pricing reactive power in this manner, distribution companies around Auckland in New Zealand last year agreed with Transpower to pay an annual rate of $4.42 per unit of nominated kVAR demand (as nominated by the distribution company). A monthly penalty rate of $1 per unit of peak kVAR above the nominated amount was imposed to reflect the expected higher costs Transpower would incur in meeting unanticipated kVAR requirements (e.g., by constraining on generation). Distribution companies responded by seeking out lower cost sources of reactive power, such as installing capacitor banks, and apart from the first few months no distribution company incurs the penalty charge. Appendix III: Minimising Efficiency Losses when Allocating Common Costs Where services are common to all market participants, it is not possible to identify and price the incremental service provided to any particular participant. Any allocation of the costs of providing such a service will not reflect (except by coincidence) the marginal cost of the service. Consequently such a charge does not provide useful information in decision- making in relation to the purchase and provision of the service. However, common costs have to be recovered by some means otherwise the providers of the services would suffer a loss and the provision of the services would not be sustainable. Since in reality the charges cannot be “truly fixed” in the sense that the charges are completely unrelated to the consumption or production quantities of the entities that are charged, any change in behaviour due to an allocation of common costs risks reducing economic welfare. From an efficiency perspective, the primary challenge is to allocate common costs in a manner that minimises these distortions. A body of economics, called the optimal tax literature, is concerned with developing rules for raising a given revenue requirement in a way that minimises the loss to economic efficiency. A key conclusion from this literature is that the total loss to economic welfare caused by charges to fund common costs is minimised by spreading the charges as broadly as possible. The reason why a broad base minimises efficiency losses can be illustrated in the following graph. Common cost allocation $/MWh D AC p1 p* B SRMC q1 q* MWh EMC In the graph, the average cost curve (AC) represents the cost per unit of transacting energy through the market, including the costs of common ancillary services. The short-run marginal cost curve (SRMC) shows the marginal cost of each additional unit transacted SRMC is below average cost since it does not include common costs. 25 An economically efficient price is p*, where the demand curve crosses the SRMC curve. Recovering common costs through a levy on MWh transacted through the market raises the price of transactions from the efficient level p* to p1. At price p1, the quantity of services demanded is reduced to q1. This level of usage is inefficient, because the usage that has been discouraged would be worth more to the users than it would cost the system. The loss in economic welfare is shown by the shaded triangle (B). Economists call this loss to welfare the ‘dead-weight loss. The reason why a broad base minimises efficiency losses is readily apparent. If prices are increased above p*, the area of the dead-weight loss triangle increases by the square of the increase in price. Doubling the price increase will increase the dead-weight loss by a factor of four. Halving the price increase will reduce the dead-weight loss to a quarter of its previous value. For a given level of common costs, a broader base of cost allocation means that a smaller price increase above the efficient level p* would be required, and consequently a smaller amount of dead-weight loss would be incurred. Optimal tax literature also shows that having spread a charge over as many users as possible these charges can, at least in theory, be fine-tuned. One well-known theoretical rule for fine-tuning is the ‘inverse elasticity rule’ (or Ramsey pricing). According to this rule, the (common cost) charge should be set higher for those who are less responsive to price changes (i.e., low price elasticity) and lower for those who are more responsive a price changes (i.e., high price elasticity). This approach would reduce the total dead-weigh loss by reducing the divergence between the actual quantity demanded from the optimal level. This rule can be illustrated using the graph above. Users who are more responsive to prices would have a flatter demand curve (D). For a given level of common cost charge (p1 – p*), users with a flatter demand curve would reduce their quantity by more (i.e., q1 is further away to the left from q*), thus the dead weight loss (area B) would be larger. If users’ sensitivity to prices varies significantly, reducing the charge for participants who are more sensitive to price changes, and increasing it for others, would reduce total dead-weight losses. A more sophisticated version of the inverse elasticity rule recognises the impact of the charge on the consumption of all goods and services, not just the service that is levied. That is, the rule takes into account the ‘wealth’ effects of the charge. For instance, to comply with this rule it is not sufficient to consider the impact of a price change on demand for ancillary services. The change in demand for other services as a result of higher common cost charges must also be taken into consideration. In practice, even the simplest version of the inverse elasticity rule is very difficult to implement because the elasticity of each participant is not known and can be estimated only imprecisely. Nor can any estimate of elasticity (typically derived from historical responses) predict accurately how participants will respond to changes in the future. 25 These curves have been drawn to emphasise the point, and are not intended to reflect the shape of actual costs. EMC Appendix iv: Payment for Large Deviation FCAS – What Proportion Should the Largest Contingency Bear? The NEMMCO report recommends that the largest contingency or group of contingencies incur the full costs of large deviation FCAS costs. An alternative approach is to ensure that the largest contingencies incur at least the full incremental cost of the increased risk. This approach is often referred to as the Runway method. The Runway method of cost allocation is best described using the example of an airport runway. Suppose the runway is 1000 meters in length and costs $100,000 per year. Suppose daily usage of the runway is by three types of aircraft and is as follows: 2 jumbo jets that use the entire 1000 metres of the runway to land safely 3 737’s that use 500 metres to land safely 5 Cessna’s that use only 100 metres to land safely. Since the total cost of the runway is $100,000, the cost per 100 metres is $10,000. A total of 10 aircraft “use” 100 metres, implying a cost allocation of $1,000 per aircraft. The three 737’s use an additional 400 metres of runway, as do the two jumbo jets. Thus, $40,000 is spread across five aircraft, implying an allocation of $8,000 each. Finally, the remaining two jumbo jets use the final 500 metres of the runway. The cost allocation per jet is $25,000. Total costs for each type of aircraft are: Cessna’s $1,000 737’s $9,000 Jumbo’s $34,000 The same principles may be applied to allocation of instantaneous reserves. The total required level of reserve may be defined, for example, by a 600 MW generating station. But there may also be several smaller stations operating. By charging these stations a proportion of the costs (with the proportion determined as above), incentives for future investment are less distorted. If the largest contingency incurs all of the FCAS cost, new investors face incentives to reduce the size of any new plant. Under the Runway method, new investors will face, appropriately, the incremental cost of FCAS necessary to manage the increased contingency risk. Both methods suffer from not assessing the probability of a failure. Hence, the real EMC resource cost of covering contingencies are likely to be higher and/or security lower for the same cost under these mechanistic approaches, when compared with more sophisticated risk analysis. Randell Consulting Randell Consulting Pty Ltd Telephone: (02) 9130 1877 ACN 090 778 555 Facsimile: (02) 9300 8985 Email: [email protected] ______ Hedging ancillary services This paper is prepared for NECA and reflects discussions with market participants regarding NEMMCO's final report "Ancillary Service Review - Recommendations". It focusses on concerns about the ability to manage ancillary services risk. For clarity I have used the term retailer to mean a buyer of ancillary services and hedges. Similarly generator means a seller of ancillary services and hedges. Concern that generators won't offer hedges in ancillary services because of volume risk If a generator offers hedges over the same load in both ancillary services and energy markets it is exposed to the risk that it will be constrained in the energy markets to provide the ancillary services. In this case energy market compensation is paid to the generator as part of the ancillary service clearing price. The hedge in the ancillary services market has worked adequately. However the generator remains overcontracted in the energy market and is exposed to high energy prices. To put this in stark terms a 500 MW generator who sells 500 MW of contracts in the energy market and 500 MW in the ancillary services market may find itself overcontracted by 500 MW in the energy market. Generators can avoid this risk by not providing hedges over the same load. If a generator is currently 80% hedged in the energy market it may decide in future to be 70% energy hedged and 10% ancillary services hedged. As a consequence this volume risk may not be a barrier to the development of ancillary services risk management. It is also worth noting that a retailer's market share will be a input into their ancillary service costs (In contrast to energy markets where a retailer need forecast their load but not market share). This is not seen as a barrier to the development of a hedge market. Concern that the generators earn a state price whilst retailers earn a national price Since interconnectors only break infrequently the risk of divergence is not likely to impede the development of a hedging market. I note that there may be a move towards loading interconnectors to higher than current normal maximums. This may impede the free flow of ancillary services. This could lead to significantly more divergence since interconnectors get constrained far more than they totally breakdown. This could leave retailers with a significantly reduced ability to manage ancillary service risk. Concern about transition arrangements I note that some generators have said that they would look favourably at the prospect of offering ancillary service hedges at commencement of the market. However in the short term generators may be reticent to provide ancillary service hedges for two reasons. Firstly, there is no pressing need for generators to hedge since they are not exposed to huge risks as a supplier of ancillary services. They are giving up "windfall gains" by selling hedges. In the absence of sufficient high quality historical data they may decide to wait and see. The second reason is the provision of hedges will require investment in infrastructure by generators. In my opinion they may not make this investment if there is any uncertainty as to whether and when the final report will be adopted and its exact form. Accordingly hedges may be unavailable for some months after the final step in the approval process (which I understand is ACCC approval). To assist the development of hedges the market should commence at some fixed time after this final step. Some have pointed out that high ancillary service prices will correlate well with high energy prices This is due to generators rebidding if this is not the case. Accordingly retailers may choose to hedge their ancillary service risk using energy hedges. For example, a retailer could purchase energy caps as a defacto ancillary service hedge. In the case of FCAS lower markets the ancillary service price could vastly exceed the energy price. In this case energy caps are unlikely to provide the cover retailers need. The retailer is effectively undercontracted. In the case of constraint on the interconnector, energy prices will diverge but ancillary services may remain low since they are sourced from the cheapest national source. Retailers may find they receive payouts on their energy caps even though the ancillary service price is still low. Accordingly there is an element of possible overcovering in the case of constrained interconnectors. Nevertheless energy caps could still be valuable in the transition period and may even be used to manage ancillary services on an ongoing basis. If this aspect of the transition becomes critical, then the risks implicit in buying energy caps should be more carefully considered. ASIC Approval Generators and retailers are currently authorised to transact in the electricity contract market. It is unclear that this would apply to ancillary service hedges. It is important to check that there are no legal barriers to hedges being consummated. Need for a facilitator to be provided The availability of hedges is not materially improved by the provision of a facilitator to operate a market. A facilitator will also damage the development of future initiatives. Liquidity Given the eight spot markets for FCAS and the small size of the market it is unlikely to receive additional liquidity/risk capital from market participants, traders, speculators etc. However this does not detract from its ability to operate as a very basic "risk transfer" market in the way some parts of the electricity contract market do. Complexity The arrangements regarding ancillary services and the link to the current energy market arrangements are without doubt complex. Excessive complexity can damage the ability of participants to assess and manage risks. To counteract this concern the arrangements should be reexamined to determine if they can be simplified or Nemmco should be required to provide education to participants. Conclusion There seems nothing in the proposal to prevent the development of a market to hedge ancillary services provided the operation of the interconnectors does not "crowd out" the provision of ancillary services. To minimise transition risk the system should commence a fixed number of months after the final approvals are obtained. Otherwise the transition will depend on the use of energy hedges which only provide an approximate hedge. Finally the arrangements should be simplified or arrangements made to provide education to participants.