Electricity Futures Market

DevelopmentA Report to the Energy Market Authority

of Singapore fromCybele Capital Limited

Cybele Capital Limited

Cybele Capital Limited works with an exclusive range of entities from government agencies to corporates, to investors and financial market entities across Asia, Australia, the Americas and at home in New Zealand.

We have a strong energy and environmental markets practice which services a diverse range of clients across the Pacific Rim. We service some markets directly, and in Australasia our environmental work is managed by a relationship with CO2 New Zealand

Our energy capability (specifically electricity and natural gas) spans scheduling / dispatch markets through to derivatives trading and pricing and the management of energy portfolios. As with most other elements of our business we bring a practical and practitioner’s perspective to our engagements as we drive for effective implementation.

Carbon markets demand considerable patience for those involved, something we have learnt both participating in and observing their development over the past decade. Our focus has always been on compliance rather than voluntary markets, and as a result of this Cybele has extensive knowledge and connections into the global markets for carbon. We also have an extensive understanding of the changing rules that govern these markets.

The strong symmetries between our renewable energy and carbon business lines makes us the obvious partner in either business line.

Cybele Capital Limited is a registered Financial Services Provider (FSP194246) for wholesale products and counter parts.

We do not engage with members of the public for either our investment or advisory businesses.

James Moulder is a Principal of Cybele Capital Limited

James has worked in the Australasian Power market since 2000, initially as a consultant with Andersen in Melbourne and then in several general management positions within Mighty River Power Limited, the countries second largest operator and developer of renewable energy projects. James’ last role at Mighty River Power Limited was as General Manager Generation, prior to him founding Cybele Capital in late 2008.

Prior to entering the power industry James worked in senior roles at ANZ Investment Bank in its financial markets business holding various front office roles in both New Zealand and in Australia.

James has a rare combination of extensive power and commercial experience and has been responsible for negotiating both asset investments and divestments within the New Zealand electricity market. James is currently the Chairman of the New Zealand Electricity Authorities Wholesale Advisory Group, and is a graduate of both Victoria University and the Harvard Business School.

For more information about this paper, please contact us.

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Important Information and Disclaimer

Cybele Capital Limited (Cybele) wishes to draw the following important provisions to your attention prior to your receipt of or access to the Electricity Futures Market Development Paper (the Paper) including any accompanying presentation and commentary (the Cybele Capital Commentary).

The Paper and any Cybele Commentary have been prepared for the Energy Market Authority (the Client) in accordance with a specified scope of work described in a letter of engagement with the Client (the Engagement Letter).

Any person or entity which accepts receipt of or access to the Paper and any Cybele Commentary (the Recipient) agrees to be bound by the terms and conditions set out below;

• the information contained in the Paper and any Cybele Commentary has been compiled from information and material supplied by the Client and other third party sources and publicly available information which may (in part) be inaccurate or incomplete;

• Cybele makes no representation, warranty or guarantee, whether express or implied, as to the quality, accuracy, reliability, currency or completeness of the information provided in the Paper and any Cybele Commentary or that reasonable care has been taken in compiling or preparing them;

• no part of the Paper or Cybele Commentary may be circulated, quoted or reproduced for distribution outside the Client’s organisation without the prior written approval of a Director of Cybele.

• no part of the Paper or Cybele Commentary may be circulated, quoted or reproduced for distribution outside of an entity listed in Annex 2 without the prior written approval of a Director of Cybele.

• the analysis contained in the Paper and any Cybele Commentary is subject to the key assumptions, further qualifications and limitations included in the Engagement Letter and the Paper and Cybele Commentary, and is subject to significant uncertainties and contingencies, some of which, if not all, are outside the control of Cybele; and

• any Cybele Commentary accompanying the Paper is an integral part of interpreting the Paper. Consideration of the Paper will be incomplete if it is reviewed in the absence of the Cybele Commentary and Cybele conclusions may be misinterpreted if the Paper is reviewed in absence of the Cybele Commentary. The Recipient releases Cybele from any claims or liabilities arising from such an incomplete review;

Cybele is not responsible or liable in any way for any loss or damage incurred by any person or entity relying on the information in, and the Recipient unconditionally and irrevocably releases Cybele from liability for loss or damage of any kind whatsoever arising from, the Paper or Cybele Commentary including without limitation judgements, opinions, hypotheses, views, forecasts or any other outputs therein and any interpretation, opinion or conclusion that the Recipient may form as a result of examining the Paper or Cybele Commentary. The Paper and any Cybele Commentary may not be relied upon by the Recipient, and any use of, or reliance on that material is entirely at their own risk. Cybele shall have no liability for any loss or damage arising out of any such use.

The Paper and Cybele Commentary are strictly confidential and for the sole benefit of the Client. No person other than the Client (and the employees, directors, and officers of, and professional advisers to, the Client) or a Recipient (who has agreed to be bound the terms herein) may access the Paper or Cybele Commentary or any part thereof. The Recipient undertakes to keep the Paper and Cybele Commentary confidential and shall not disclose either the Paper or Cybele Commentary or any part thereof to any other person without the prior written permission of a Director of Cybele.

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Contents

1.0 Executive Summary 5

2.0 Background 10

3.0 Challenges, Issues and Factors 14

4.0 Issues of Market Inefficiency 22

5.0 Market Based Solutions 25

6.0 International Experience 34

7.0 Preferred Solution 38

8.0 Cost Benefit Analysis 43

9.0 Market Infrastructure 49

10.0 Endnotes 52

A.1 Glossary 55

A.2 Parties Interviewed During Analysis 58

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1. Executive Summary

1.1. Regulatory Objective and Outcomes

The EMA has publicly stated that it seeks the development of a fair, efficient and effective forward market for electricity in Singapore so that existing, emerging and prospective participants can both have transparency in wholesale pricing while also being able to access (for transactions) that same market.

The further development of new electricity retailers, the emergence of consumer product innovation and the greater use of traded risk management instruments are the primary regulatory outcomes sought by the Authority.

1.2. Market Based Arrangements

The issues that are manifested in the retail market are primarily that there is a barrier to entry for potential new participants as they are potentially unable to access competitively priced risk mitigation contracts. A liquid market for derivatives, is clearly lacking and furthermore, the lack of anonymity in the existing market creates a situation whereby it could be argued that it would be irrational for a generator to offer a competitively priced hedge to a new entrant retailer.

This apparent lack of effective risk transfer also creates a constraint on the growth of the retail portfolios of existing participants resulting in an outcome where the retail market share is dependent more on generation market share than on competence in retailing. The retail market is therefore suffering from a lack of both price and non-price competition.

In order to address these issues, the proposed solution must create an environment whereby risk mitigation contracts can be transacted cost effectively, and with anonymity between retailer (and financial institution) and generator. In order to transact at low cost, there must be reliable liquidity in the market. Liquidity reduces search and transaction costs. In order to provide anonymity between retailers and generators, an intermediary must be active in the market. This intermediary could take a number of potential forms; exchanges, brokers, or financial institutions could all potentially serve this function.

1.2.1. Derivative Markets

There are two broad options for the trading of vanilla derivative products; Over-the-Counter (OTC) or exchange traded. Currently, most participants appear to be active traders of OTC fuel contracts and somewhat little transactions occur in the electricity market are done OTC, although without standardised (e.g. ISDA) documentation.

The following table highlights the key differences between exchange traded futures and OTC forwards.

Whilst it is apparent that OTC forwards have some favourable qualities, the anonymity, transparency and low barriers to entry in terms of documentation requirements of exchange traded futures give the greatest potential for initial development of an actively traded Singaporean electricity derivative. It is important to note that we see the further development of the OTC market as complementary to any exchange traded product in that it allows counterparties to develop more customised solutions to their risk management needs, but that this development requires the underlying liquidity and price transparency of an exchange traded market.

1.3. Potential DevelopmentOptions

The various choices in the development of a traded futures market in Singapore are detailed below. In this section; the following graphic illustrates the range of options considered.

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SerialForward (Contracts for Differences (CFD)) Over The Counter Contracts

Futures Contracts

1Non-standardised contract (tailored to

clients' needs)Standardised contracts (expiry, quantity, grade)

2 Counterparty risk Centrally cleared by Clearing House

3 Bi-lateral contract only Contract novation

4 Non transparent nor regulated market Regulated transparent market

5 No cash flow before contract maturityInitial and variation

margins during life of contract

6 Price only available to counterpartyPrice available to the market via data vendors,

exchange web-site

7Price negotiable. Bigger companies tend to get better prices than smaller companies.

Market prices available to all users – subject to exchange requirements.

8Either no anonymity or, if brokered

may be anonymous pre-trade.Full anonymity

Figure 1.1: Forward vs. Futures (Source: ASX and Cybele.

The options include the status quo (the counterfactual) against which any consideration of new arrangements will be considered, together with four options that have the potential to achieve the regulatory objectives described earlier. The status quo option is self evident in terms of features and elements.

1.3.1 Organic Forwards

The extension of the Status Quo arrangements into a more active over-the-counter CfD market is often presented as a viable compromise in the development of a liquid hedge market. The organic forward market uses the Contracts for Differences (CfD) instrument as its core transactional instrument. Usually based upon international standard documentation, these CfD’s have many similarities and a few key differences with the core transactional instrument in a traded futures market.

Some of the issues with forward markets like transparency can be addressed with other regulatory tools including the mandatory release of key transaction details for all material hedge contracts1. The use of trading bulletin boards (like www.energyhedge.co.nz), standard market documentation and formalised price surveys2 have been attempted in either or both New Zealand and Australia to address many of the negative features of a forward (CfD) market. These developments move the Organic Forward option towards the Power Exchange. In the New Zealand case, these attempts ultimately failed due to a lack trust in the mechanisms particularly with end use consumers and new entrant market participants as they had no access to market prices.

Given its general inability to deliver upon the regulatory objectives of reform (i.e. benefits) and the strong likelihood that costs will be higher than the costs associated with the other options the Organic Forward is not recommended.

1.3.2 Power Exchange

The Power Exchange approach essentially takes the features of the Organic Forward and delivers them in a framework that largely replicates a Futures Exchange. The development of Power Exchanges in Europe has largely negated the need for a futures market as the features of these Power Exchanges replicate many of the functions of a Futures Market.

A model where forward contract settlements are processed through a centralized clearing house is a model that could have application in the Singaporean context if a suitable party is able to fulfill the clearing-house role. Notwithstanding this, in our view, the differences between the use of standard Forward Contracts arrangements on a Power Exchange and an Exchange Traded Futures contract are generally superficial with the critical caveat that credit needs to be operated on a full access model by the clearing function. We have concluded that the development of Power Exchanges is appropriate where (or when) no futures infrastructure is available at establishment.

Our view is that the Power Exchange option should not be used an attempt to create an Energy Hedge type trading portal with restricted access if the regulatory objectives are to be achieved.

1.3.3 Glide Path Futures

The Glide Path futures scenario seeks to establish a traded futures market for Singapore base-load electricity over the next two to three years through a progressively more onerous set of market making and trading obligations. The use of incentives to encourage participation in the provision of futures market liquidity is also a feature of this Glide Path approach.

The Glide Path approach recognises the considerable, in some parts of the markets, skill gaps that will need to be closed before trading can sustainably develop in an open entry environment. This approach also has a minimal level of market marker obligations and will be supported by considerable education and training support from the Exchange and external providers as required.

The Glide Path approach is time graduated, with increasing obligations with time. Figure 1.3 describes the features of the Glide Path.

A commercial arrangement, named a Forward Sales Contract (FSC), could be used as incentives to encourage gencos to be voluntary liquidity providers. Based upon standard financial markets documentation; specifically the use of the financial industry ISDA standard, these contracts will also have the benefit of preparing the market infrastructure for greater OTC trading activity between generator/retailers.

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Figure 1.2: Development Options Considered

Figure 1.3: Common Specifications for Futures Contract Price Making Obligations

Condition Phase 1 Phase 2 Phase 3

Two Way Price Making Spread

$20/MWh $15/MWh $10/MWh

Period of Market Making

4.30pm to 5.00pm Singapore Business Days4.30pm to 5.00pm Singapore Business Days4.30pm to 5.00pm Singapore Business Days

Refresh No Yes, onceYes, once and followed by

best endeavours

Portfolio Stress Clause

Yes Yes Yes

Cumulative Contract Duration

1 year(4 contracts)

2 years(8 contracts)

3 years(12 contracts)

The offering of this voluntary arrangement would have a set deadline for participant to opt in on or prior to a preset deadline set by EMA, where the parties will state the quantity commitment to two way price making on fixed spreads as detailed in our preferred design. A minimum requirement of 13.5 MW per side is required for the FSC to become operative at Phase 3. The volume of Forward Sales Contracts will be allocated on a balance of effort basis so long as the minimum requirement has been meet.

The allocation method for FSC should provide a degree of certainty for generators such that those who meet pre-determined minimums will be given a share of FSC volume and at the same time be rewarded for relative efforts.

1.3.4 Quick Start Futures

The development of a futures market that is fit for purpose on day one, designed to deliver maximum levels of liquidity and very high levels of trading volumes (on a par with markets that do not have vertical integration features) is provided as a final and aggressive model.

This approach would see a futures product with 1 MW on the bid and offer, a small (1 – 2% spread) on a three year (12 contract) duration curve. The reload obligations would be immediate with no phase in period.

Given the large volumes, a three-year market would have over $600m of bids and offers at any one time. This is around five times of the Phase Three volume proposed in the glide path model. This level of liquidity, especially given the quick start nature of the implementation, is not a preferred option.

1.4 Preferred Option

The preferred option is the glide path futures option where generators enter into voluntary market making agreements with the exchange(s) to be voluntary liquidity providers in the electricity futures market. Notwithstanding the above, should there be insufficient interest from the generators to start this process organically, the design of some form of incentive mechanism is recommended.

The ability to incentivize generators into entering into voluntary but binding market making arrangements could be done through the introduction of a forward sales contract (FSC), but with the expectation that a failure to establish a viable market will see the introduction of a mandatory obligation.

1.4.1 Cost Benefit Analysis

We have completed two assessments of costs and benefits to provide a robust analysis of the likely benefits and also the required levels of implied improvement for these improvements to be considered net benefits. These approaches are specifically the Sensitivity Based Approach – looking at small changes (based on changes in other market environments) in identified improvements in the NEMS context. The other approach, the Barrier Based Approach, is to identify the positive change required to provide a single dollar of net benefit, with this change being assessed for reasonableness.

Sensitivity Based CBA

The following quantitative assessment of net benefits has been assessed primarily through a sensitivity based approach with results provided in the following matrix. These results are conservative (i.e. costs estimated to be on the high side, while benefits estimated to be conservative) and provide an option based assessment of minimum levels of expected benefits rather than an expected case. The net benefits are certainly significant enough to justify the associated costs.

Barrier Based CBA

The following quantitative assessment of net benefits has been assessed primarily through a barrier based approach with results provided in the following matrix. The high cost scenario (i.e. conservative approach) is used and benefits are progressively scaled across each of the elements to provide a ten year net benefit (based on a 10% discount rate) in the range of $0.25m and $0.50m.

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Figure 1.4: Specifications for Voluntary / FSC Based Futures Price Making Obligations

Condition Phase 1 Phase 2 Phase 3

Voluntary Market Making Trading Volumes (each side)

33% of Successful Bid Volume as per FSC Allocation

66% of Successful Bid Volume as per FSC Allocation

100% of Successful Bid Volume as per FSC Allocation

Figure 1.5: CBA Net Benefit Matrix – Sensitivity Approach without FSC Costs

Net Benefit (NPV S$)

Low Cost Med Cost High Cost

Low Benefit $70.5m $69.5m $65.9m

Med Benefit $127.6m $126.4m $122.9m

High Benefit $194.0m $192.8m $189.3m

The Barrier Based Analysis shows that the required changes for all elements are well within the estimated changes under the Sensitivity Based Analysis. This further illustrates the low barrier (costs), relative to the benefits of developing a futures market in Singapore.

1.5 Implementation

Whilst market information will not replace the proprietary market analysis that trading firms, both physical and financial, must undertake, it is critical that there is no information asymmetry between the current physical players and potential new entrants.

It is our view that given the capability of the generators with regard to fuel trading, the addition of electricity trading/market making function should not be overly cumbersome.

1.6 Selection of an Exchange

We have proposed a futures contract via the Glide Path approach as our preferred solution in part due to the fact that the product will be centrally cleared and traded through an exchange. In the interests of concentrating liquidity, at least in the early stages of trading, it would be sensible to have all market makers operating on one exchange. Whilst any exchange could list a futures contract that settles against the Uniform Singapore Energy Price (USEP), in order to facilitate a market environment that will encourage participation of new entrants the exchange through which market making takes place must meet certain criteria. We would expect that any exchange that the industry or EMA was to gazette for market making must obviously be of reputable standing. For market makers to reap the benefits of the proposed FSC, market making arrangements should be conducted on an appropriate exchange(s) that is collectively selected by the generators or is endorsed by EMA. Furthermore, the clearing participants of this exchange would need to be reputable in order to instill confidence in the creditworthiness of exchange traded products.

We recommend EMA to allow the generators to work with the exchange to develop a futures market on a commercial basis. However, in the event that an industry-preferred exchange is not selected organically, EMA could opt for an endorsement of an appropriate exchange according to preset selection criteria.

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Figure 1.6: CBA Net Benefit Matrix – Barrier Approach without FSC Costs

Net Benefit (NPV S$) Combined Change

Lower search and transaction costs during scheduled maintenance outages

$2.50/MWh for 0.25% of plant out for 14 days per annum. (Previously 25% of plant)

Reduction in average retail price as new retailers compete for contestable business

$0.5/MWh reduction for 0.30% of contestable consumers. (Previously 30% of contestable consumers)

Lower search and transaction costs for fuel procurement

$0.1/MWh for 0.25% of plant per annum. (Previously 25% of plant)

Stronger incentives on generators to invest in fit for purpose generation plant

A reduction to 20% of the previous low case benefits

Product innovation to consumers due to increased Retail competition and access to hedge markets

Reduction in delivered cost of energy by $1/MWh for 0.50% of contestable consumers. (Previously 10% of contestable consumers)

Improved market price signaling and long run responses by non participating electricity purchasers

during tight market conditions.Efficiency benefits reduced to 25% (Reduction from $0.4m to $0.1m)

2. Background

This section details some of the important background and introductory material drawn on in the paper. A glossary of terms is provided in Annex A of this paper.

2.1 Regulatory Objective and Outcomes

EMA has publicly stated that it seeks to develop, in partnership with all stakeholders, an energy landscape that is forward-looking, innovative and vibrant. The aim is to create an energy sector that contributes to sustained growth, for the benefit of all Singaporeans.

The objectives of EMA as it relates to this work-stream can be found in Section 6 of the Energy Market Authority Act (Chapter 92B) which in part states:

to create a market framework in respect of the supply of —

(i) electricity or gas; or

(ii) other goods or services regulated by the Authority under any written law,

which promotes and maintains fair and efficient market conduct and effective competition or, in the absence of a competitive market, which prevents the misuse of monopoly or market power;

Specifically, EMA seeks the development of a fair, efficient and effective forward market for electricity in Singapore so that existing, emerging and prospective participants can both have transparency in wholesale pricing (not to be confused with the spot or dispatch market) while also being able to access (for transactions) that same market.

The further development of new electricity retailers, the emergence of consumer product innovation and the greater use of traded risk management instruments are the primary regulatory outcomes sought by the Authority.

2.2 Market Volatility

The underlying driver of spot electricity market volatility is a key element in the design of appropriate risk management instruments.

2.2.1 Different Types of Volatility in Power Markets

The following sub sections and graphics provide insights into the differing types of price volatility seen in power markets:

Energy Constrained: this type of electricity price volatility is usually caused by a fuel constraint - e.g. a lack or deficit of gas due to a gas pipeline constraint in a PNG dominated market. Volatility can manifest itself in multi month periods of high but not Value of Lost Load (VoLL) level prices. These markets generally have excess capacity but on occasion become fuel constrained. A good example of this type of market is New Zealand.

Capacity Constrained: this cause of electricity price volatility is usually caused by generation or transmission constraints - e.g. a lack or deficit of available plant or transmission capacity. Volatility generally manifests itself in very short periods (a few hours) of very high (e.g. VoLL) prices. A good example of this type of market is Australia and Singapore, with New Zealand also displaying this type of volatility on occasion.

Figure 2.1: Volatility Charts - Singapore, New Zealand and Australia

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2.2.2 The Singaporean Context

We have conducted a brief analysis of price history, focusing on the nature of the volatility of price, and the degree to which these prices move in tandem with traded fuel prices. Internationally, all electricity markets have their nuances when it comes to volatility as a result of differing generation fleets, fuel mixes, climates, and demand profiles.

As a result of having very low seasonal weather fluctuations, in conjunction with an entirely thermal fueled generation fleet, USEP displays a reasonably close correlation with HSFO prices over the long term. We do however expect this correlation to decline in future as more varied fuel contracts are available to the market following the commissioning of a local LNG terminal in 2013, as we believe it will change the marginal price setting stations.

Another effect of an entirely thermally fueled generation fleet is that the volatility of spot price on a short term basis can often be extremely high, primarily driven by very short periods of very high prices, as is also common in the Australian market.

2.3 The Spot Market

2.3.1 Infrastructure

The spot or pool market in Singapore is operated by the EMC. This is achieved through a linear optimisation which uses as inputs, expected demand, generator offers, as well as transmission network information including losses and constraints in order to solve the least cost provision of electricity to meet demand in each half hour (Interval) of each day. The solution of this optimisation will yield the clearing price and dispatch quantity for each generator that is called upon in the relevant interval.

Generators are able to submit offers for energy and reserve up to 65 minutes prior to the start of the relevant interval. When making such offers, generators must consider their plant capability, fuel costs, contracted positions, as well as their view on the expected market price, which encompasses all the external factors that will influence that price.

Registered retailers or market participants must pay the USEP price for the electricity that they consume in any half hour interval. Given the volatility in this price, their effective short position is generally hedged to some extent through either contracting or through physical generation assets. Given the physical nature of the thermal generation fleet, each individual unit forms a relatively large proportion of total capacity. Thus, in order to ensure adequate availability of generation at all times, an outage co-ordination process is run by the PSO. This information is then available to participants.

It is noteworthy that there is currently a price cap in the pool market and the USEP in any interval cannot exceed $4,500/MWh. This price cap essentially ensures that all available plant is offered at a price which is lower than $4,500/MWh.

2.3.2 Spot Market Behaviour

Whilst we describe in greater detail the behaviour of participants in section 4, our analysis and prior international experience have given us some insight into the behaviour of spot market participants. It is however difficult to get a clear picture without publication of generator offers and a much more in-depth analysis of behaviour over the long run.

Given the diverse generation fleet, (there at least 48 individual generating units in the market) and the portfolio approach that most of the participants are able to take toward their fleet, it is sensible to assume that the least cost generation would be subject to the least ramping, instead running closer to the base load profiles. Given this assumption 3 we would expect to see more expensive plant ramping in order to meet the fluctuations in demand.

Counter intuitively, what we seem to observe is that both HSFO and PNG fuelled plant is ramped, with a substantial amount of HSFO plant run during low demand periods, while PNG plant output is reduced.

There are a number of possible explanations for this, HSFO plant ramp constraints being the first to come to hand, however we are not sure that this would explain the extent to which this practice occurs, especially given that some HSFO plant is clearly being shut down overnight on a daily basis.

Our hypothesis is that the main driver of this behaviour is that the approach of all of the generator retailers, in all intervals, tend to generate to a level that ensures that they are at least generating to the level of their contract obligations, rather than being a net buyer from the pool. We refer to this strategy as ‘contract covering’.

2.4 The Retail Market

2.4.1 Retail Infrastructure

Consumers of electricity in Singapore are divided into two broad groups; Contestable and Non Contestable. The threshold for a consumer to become a contestable customer is if their monthly electricity consumption is over 10 MWh. Those consumers that do not cross this threshold and all residential consumers are deemed to be non-contestable and are supplied by SPS. Any contestable customer that does not elect an alternative retailer is also supplied by SPS at wholesale prices..

SPS therefore has a purchase obligation from the spot market, which is fully hedged in the case of non-contestable customers, and partially in the case of the remaining contestable customers.

This hedge is through the regulated vesting contracts on which we elaborate on in the section below.

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2.4.2 Vesting Contracts

The vesting contracts provide a means by which EMA aims to alleviate market power arising through concentration of ownership of the generation fleet. Essentially the vesting contracts work like a CFD, with base parameters to the price formula set against the long run marginal cost (LRMC) of the most efficient power stations every two years. The volume of vesting hedges is currently set at 55% of generation.

The vesting contracts provide a hedge to SPS for the purchase of all non-contestable volume, and also a portion of the contestable volume (in line with other retailers).

We elaborate on some extension and parallel development of vesting-like contracts for market participants seeking to commit to a voluntary market marker arrangement (see Section 7.2).

2.4.3 Retail Market Behaviour

The retail market in Singapore is dominated by the five major generator/retailers. As we show in section 3, these firms have market shares that are largely governed by their installed generation capacity. All of the major retailers appear to treat their installed capacity as a hard constraint on the expansion of their retail portfolios.

There have been very few new entrants if any into the retail space since the market began. All new entrant(s) to the market seem to have had some kind of physical asset in order to hedge their retail position.

The products that are available from the existing generator retailers are all very similar. There are four products (plus spot) that seem to be more prevalent:

• Vanilla Fixed Price Variable Volume contracts, whereby consumers pay a fixed price per unit of consumption.

• Discount From Tariff, where consumers pay at a fixed discount to the regulated tariff that is charged by SPS to non-contestable customers (which is reviewed on a quarterly basis).

• Fixed payment where consumers pay a fixed price per month that is independent of their consumption (within certain tolerances).

• Fuel Index linked contracts, where consumers pay a rate per unit of consumption that is linked to HSFO prices. Essentially this gives the consumer a fixed spark spread whilst giving them the underlying fuel price risk.

• Spot price contract where consumers pay a rate per unit of consumption that is tied to spot price in the wholesale market.

It is very rare in the retail space for customers to take spot market price exposure and hedge through a CFD or similar derivative product.

2.5 The Forward Market

2.5.1 Infrastructure

Currently there appears to be very little activity in the market for forward electricity contracts. Between the major participants there does not seem to be any standardised forms of documentation (e.g. ISDA agreements) for the trading of electricity derivatives.

There appear to be no intermediaries in the form of brokers or financial institutions that are able to create some anonymity between hedge counterparties. The lack of brokers or any other mechanism for price discovery means that the market through which the small amount of forward trading occurs is currently very opaque. Thus it is virtually impossible for participants to get a gauge on where the market price of forward contracts is at any point in time.

Due to the small volume of spot exposed retail customers, there are very few consumers that have a need to request hedge contracts from their retailer.

2.5.2 Forward Market Behaviour

Whilst generators do trade CFD type products between each other, these transactions appear to be for the sole purpose of covering outages of generation assets. As noted, participants have no anonymity when seeking prices for such contracts. Anecdotally, this leads to significantly higher prices than would otherwise be the case, particularly for small generators.

Currently there does not appear to be any participation from spot exposed consumers seeking hedge cover through CFDs or other derivative products.

2.6 The Fuel Market

The markets through which generators procure or hedge fuel appear to be both highly liquid and transparent. Generally fuel purchases can be hedged through physical or derivatives of HSFO. This also applies to PNG plant given the nature of the current fuel supply contracts.

In order to trade these products, the generators all seem to have access to a number of brokers and financial institutions that can facilitate trades with a broad range of counterparties, as well as providing near real time information on market pricing and activity.

Furthermore generators also have documentation in place with numerous potential counterparties as is necessary to facilitate OTC trading. The existing markets to ‘back off’ fuel risk is a real advantage for the development of a forward market.

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2.6.1 Fuel Market Behaviour

In making their fuel hedging decisions, we understand that generators will effectively hedge a retail contract as it is signed by purchasing the forward fuel, or at least a derivative thereof. Thus we understand that the generator/retailers are usually completely hedged in terms of energy, and their only risk is the spark spread which can be managed physically provided they have generation capacity available.

We also understand that it is rare for a generator to sell surplus fuel. This suggests that generators have a reluctance to purchase electricity to meet their contractual obligations either through the pool or by using derivatives thereof. Obviously this behaviour is somewhat due to the lack of a forward market.

Some, if not all generators will have some take or pay component to their fuel supply agreements which will result in a need for either on site storage or minimum running of plant.

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3. Challenges, Issues and Factors

3.1 Current Market Structure

The NEMS, with five major generators, is a market that is highly concentrated. Through vertical integration these firms are also the dominant retailers. Currently the five generators appear to engage in very little trading with each other. This apparent lack of trading is a function of the vertical integration of the firms and their consequent ability to internally manage risks. This market dynamic tends to be self-perpetuating in that any change needs to occur collectively among all parties at the same time. Such a situation can be described as having reciprocal externalities. Essentially, the behaviour of all parties depends on that of all other parties and thus there are multiple achievable states of equilibrium in terms of trading activity. Currently in a steady state of low activity, the collective activity needs some form of shock to move to a state of high activity, where a new equilibrium will be found.

A consequence of the lack of active trading within the generators is a corresponding lack of sophistication among consumers. It is apparent that there are very few derivative products available to large users of electricity; instead most are Fixed Price Variable Volume (FPVV) supply arrangements. Whilst there have been some innovations around the types of variable volume contracts that are available, for a consumer to take spot exposure and manage this risk solely through the use of derivatives is currently very unusual. For sophisticated organisations with large loads, we would argue that this should be the norm rather than the exception. This aspect of the retail market has further ramifications in that consumers have little, if any, incentive to reduce load in times of high prices.

3.2 Effect of Market Concentration

The market concentration observable due to the dominance of the vertically integrated firms has consequence for the market for derivatives. Having such a small number of firms in the market allows some degree of transparency as to other parties’ positions and strategies. There are no active brokers for electricity derivatives in the Singaporean market, which leaves participants with no anonymity when attempting to transact hedges. These factors will tend to drive participants to internalise, rather than externalise risk.

Given an apparent lack of sophisticated buyers, and the aforementioned lack of anonymity, any party requesting a hedge price from another is more likely to be seen as a competitor rather than a customer. In this sort of market environment, it is unlikely that liquidity will ever organically develop in the OTC market for derivatives.

The current lack of any significant trading activity provides no incentive for participants to develop and maintain any significant trading capability creating a self-perpetuating loop of inactivity. For a market to develop and grow, this capability needs to include not only systems and processes, but also knowledge, experience, and innovative thinking. Until such time as numerous participants build this capability, market growth will be constrained.

3.3 Role of the EMA

Given the market concentration issues above, we do not envisage that the market is currently capable of organic growth. If this were likely, we believe it would have already occurred. Having said that, if the right conditions are provided for trading to begin, we believe the market will be self-perpetuating to the point that it will evolve of its own accord as the general trading culture of the market improves.

If it is deemed that there are net benefits to be secured from creating a liquid hedge market of some form, it will be necessary to initially create artificially incentives on the current participants to build capability and engage in trading. We elaborate further on exactly how this could be done in section 5, but given the Authority’s statutory objectives, we envisage that the Authority would take the necessary steps to create these incentives.

Given the current market concentration and small number of potential traders, the EMA is in a position to create the right initial market conditions through regulation of the electricity market, or threat thereof. Over time these conditions will lead to additional participants joining the market (FIs, new entrant retailers, speculators etc) but as the core nucleus of participants will be electricity market participants, we recommend that the EMA to work closely with MAS in order to monitor and regulate where necessary any market for electricity derivatives.

3.4 Expected Volume and Activity

Given the current state of the market, with almost no trading and low sophistication of participants, we do not envisage initial activity to be particularly high, regardless of the conditions that are created by the EMA. We show in section 7 (preferred solution), that this is not necessarily a problem, and may have positive benefit on a long-term basis. Section 7 also details the level of initial primary liquidity that should be achievable by the introduction of the preferred solution.

Once initial conditions have been created, we expect a gradual development of trading capability and culture within the participant organisations. This learning curve will be steep initially but should lead to not only more open, exchange traded vanilla transactions, but also significantly more OTC structured activity. As the market collectively becomes more active in trading, it will be easier and thus more likely that participants will transact non-standard products (for example short-term outage hedges, time swaps and options etc).

When assessing the change in activity that occurs in the derivative markets as a result of any change, it will be important to understand any changes in activity occurring in both the transparent exchange traded volume, as well as the more opaque OTC markets.

As the markets develop liquidity (both OTC and exchange traded), new entrants are more likely to see potential opportunity in joining the market (wholesale or retail). By having a means to transact risk mitigation contracts at competitive prices, a significant barrier to entry will have been removed from both of these markets. We envisage that this will take at least 12 months from market inception given the need for new players to familiarise themselves with the market dynamic, as well as developing trading capabilities. New players being willing to enter the market is a significant milestone in the development of sustainable liquidity.14

3.4.1 Measures and Levels of Liquidity

While there are many academic articles4 devoted to the measurement and description of liquidity, for our purposes the following generalisations and associated definitions can be made.

‘liquidity’ in the sense of “trading liquidity” reflects the ability to transact quickly without exerting a material effect on prices. Liquidity is optimally achieved when myriad buyers and sellers are ready and willing to trade. The trading is enhanced by market-makers and speculators alike. Underlying this concept is that while buyers and sellers have different views on the most likely outcomes - that is, after all what generates trading - they largely can agree on the distributions of possible outcomes for which they demand risk-based compensation.5

Therefore liquidity can be defined as the volume of transactions that can be absorbed within a market at a given time without materially changing the price. This is related to the concepts of market depth (which can be described as the units of liquidity for a given cost) and breadth or spread (cost per unit of liquidity). The depth of the market is generally a function of the number of market participants - the greater the number of market participants the greater the depth and therefore the greater the market liquidity.

To facilitate trading it is important to make the trading instrument as ‘vanilla’ as possible, on a popular market platform, and with low barriers to market entry to attract the greatest number of trading participants. Increased participation will result in greater market depth and liquidity. It should be noted that the provision of liquidity has a real cost for those market makers obligated to constantly provide volumes at fixed prices into the market, the cost being an opportunity cost of the inability to sell the same volume to another available market segment.

Liquidity has also been expressed as a measure of market confidence, again from Warsh (2007).

Liquidity is confidence. That is, powerful liquidity in the U.S. capital markets is evidenced when the economic outcomes are believed to be benign. When the “tail” outcomes are either highly improbable or, at the very least, subject to reasonably precise measurement, the conditions are ripe for liquidity to be plentiful. ... If unmoored from fundamentals, confidence can give way to complacency, complacency can undermine market discipline and liquidity can falter unexpectedly. If, to the contrary, confidence is justified by real economic determinants, liquidity can flourish.

The use of open interest, including unmatched open interest, as a measure of liquidity within futures markets is commonly applied around the world. Strictly speaking it is not a measure of liquidity itself, but a second order measure of trading occurring presumably as a result (or not) of market liquidity. Given the emerging nature of an exchange traded future based electricity hedge market in Singapore (as it was in New Zealand) it seems, at least in the initial couple of years, that a more direct measure of market liquidity would be more appropriate6. Especially as the entry of important secondary (i.e. non-market maker) traders like the banks will be potentially subject to some delay as product approvals are sought.

Therefore the development of independent rule based mechanisms for the trading of electricity hedge contracts will also improve liquidity. Balancing the risk management needs of both end use consumers and the requirements of market participants (incumbent and emerging), there seems to be a need to provide at least in the vicinity of 12.5 - 15 MW within the mandated spread by the end of any soft start development period.

3.5 Stakeholder Interests

3.5.1 Generators

Whilst it is clear that an initial infrastructure cost must be borne by generators in regards to the development of trading capability, we expect that this capability alone will be of net benefit to the generators in time. The development of an environment that more actively assesses and manages financial risk in order to achieve commercial outcomes will likely be a valuable addition to participant firms.

Furthermore, the benefits that can be gained through having a liquid hedge market are recognised by all generators. Whether they are achieved through more efficient hedging of generation outages, or through relieving constraints on retail growth, there are clearly benefits to be reaped through a more liquid market. Naturally, generators will question whether these benefits outweigh the costs in achieving them, and we have carefully considered this perspective in developing our preferred solution.

3.5.2 Retailers

Currently, among vertically integrated retailers, it appears that most see their installed capacity as an upper bound on their retail portfolio. If hedges were able to be procured at competitive prices, this constraint would be relieved such that the most efficient retailers could purchase forward contracts to cover their risks and continue to grow retail market share.

Also, the current inability of new entrant retailers to procure hedges anonymously is a significant barrier to entry. We see that a liquid, competitive market for risk mitigation is necessary for any new entrant retailer. New retailers can then provide further competition in the market both through price and innovation in their retail offerings.

3.5.3 Loads / Consumers

Our initial and subsequent investigations have indicated that there appears to be a current lack of sophistication among large users of electricity. It seems that it is very rare for a consumer to take any spot price risk and thus the need for risk mitigation contracts is minimal. Having said that, by educating these consumers in the types of products that would be available for them to manage their spot risk once the market is active, we see that there is the potential to create buy side demand for both vanilla and structured hedge products.

The strong connections that investment and commercial banks already trading energy commodities (either Singaporean fuel oil and/or Australasian power) have with large consumers should provide the natural path way for innovative new products to be introduced to Singapore. This expected competition is a strong positive benefit of the futures market development approach.15

3.5.4 SP Services

Whilst all non-contestable load is currently hedged through the vesting contract arrangements, SPS (MSSL) is a provider to approximately 21007 contestable customers. Although these customers are partially hedged through the remaining vesting allocation, the tariff that they are subject to fluctuates with the spot price. Although it is beyond the scope of this paper, there are likely to be means by which at least a portion of this volume could be further hedged if an efficient hedge market were to develop (subject to appropriate regulatory development).

3.5.5 Financial Institutions

Whilst there are a number of potential opportunities for Financial Institutions (FIs) in the current market, the lack of liquidity in the hedge market is a barrier to entry for all of these potential participants. Once this barrier is removed there will be the potential to introduce products that include cash flow smoothing of retail tariffs, intermediation into derivative markets, exotic product structuring and cash-flow/credit swap types of transactions.

FIs have rigorous internal risk and product approval policies and will not be willing to enter the market until sufficient liquidity is reached that they can confidently clear risk positions as and when they need to. Once this liquidity threshold is met, the addition of FIs to the market helps to create further liquidity, which in turn should encourage even greater participation. The introduction of speculative capital from the FIs may also increase market volatility, particularly during periods of market stress. Undoubtedly during periods of market stress the role of speculative interests in the market will be questioned, as although this group brings additional liquidity and volatility, they are unfortunately not always in equal measure. Initially this may expose poor electricity risk management practice in both buy side (end user and retailer) and sell side (generator) camps, but this should increase the quality of risk management practice within the industry over time.

The transition from a risk management environment where assets are priced to an environment where financial risk, independent of asset ownership, are priced will take some time to occur. Improvements in market discipline and risk management practice will also increase market confidence.

3.5.6 Exchanges

The sustainable design of a well-functioning electricity hedge market is an objective that should be at the heart of future reforms to the market, especially from any potential exchange. Care should be taken when designing market features to reduce the risk of eroding market confidence, and therefore liquidity. In our view this is most notably presented as a risk in the expectations of traded volumes in any futures market – particularly given the market participants limited experience in this type of trading, low levels of natural liquidity (due to vertical integration) and little initial support from financial institutions.

3.5.7 EMC

As both a potential key information provider and the pool market clearer, EMC will necessarily need to dovetail their activities with any exchange that is to list an electricity derivative. EMC have expressed a willingness to do this as a market service provider.

The release of information to all potential market participants will be an important requirement of the futures market regulator, the Monetary Authority of Singapore (MAS).

A key consideration when integrating derivative and spot markets is the efficient use of prudential security. As EMC is the spot market clearer, we envisage a work-stream in conjunction with any exchange in order to develop an efficient prudential regime that ideally incorporates offsetting risks across both markets.

3.5.8 EMA

As noted, we expect that the EMA will help to provide the initial conditions from which liquidity can develop in the electricity futures market. This will likely involve regulatory intervention or incentives, and will certainly involve regulatory oversight to ensure that key milestones along the development path are being met.

3.5.9 MAS

As the financial markets regulator, MAS will be responsible for approval of any derivatives listed on an exchange, as well as ongoing market monitoring of trading activities of both current and future financial or derivatives market participants.

3.5.10 Specific Comments Provided to Draft Version

A number of comments where made to the draft version of this paper, which to the greatest extent possible have been paraphrased into common issues, and are hereafter detailed with associated paper references and commentary.

Serial Stakeholder Observation Paper

ReferenceCommentary

1Development of new Retailers is not an end to itself

1.1This is not a sole objective, but one of a few indicators (others listed in 1.1) that provide evidence of the maturing of the retail market.

2Consumers prefer to not concern themselves with price risk management.

Various

This has been a common theme in other developing financial and commodity markets (e.g. interest rate risk management). But with education and explanation of the benefits of more active risk management, significant improvements to overall system performance can be achieved.

Figure 3.1: Stakeholder Comments from Draft Paper

16

Serial Stakeholder Observation Paper

ReferenceCommentary

3Singapore’s largely homogenous generation and fuel supply are such that risks can effectively be internalised.

2.3, 2.3, 2.5 and 2.6

Changes in generator opportunity costs caused by outages, changes in electricity demand and other portfolio effects should be constantly and consistently priced against the market. A futures market will assist this greatly.

4FSC adds another layer of complexity to the market and the existing vesting contract regime.

Various

The introduction of the FSC arrangements will naturally introduce a degree of further complexity. This needs to be considered against the benefit of the volume certainty provided by the FSC arrangements. Furthermore, the FSC is proposed to be introduced as a separate scheme (from the existing vesting contract regime) to avoid conflation of the objectives of both schemes.

5Can a different fuel basis be used for Generators under the FSC contract like PNG.

Footnote26

The use of a Balance Vesting Price could be offered as a one off opt in (at the start of the FSC contract) as an alternative to LNG vesting.

6

Can a single fixed price (for the full term or a fixed fuel price) be used instead of the quarterly LRMC based resets that are currently proposed.

7.4

The use of quarterly prices is designed to neatly interface the prevailing market prices into the futures market product. The futures market then provides participants the opportunity to gain their required level of price security based on market prices.

7The market maker obligation should be voluntary.

5.3

Parties do not have to opt into the FSC/Market Maker regime if they don’t wish to. For those parties that wish to receive FSC volumes, the Market Maker obligation is mandatory. A key feature of the futures market is confidence – essentially confidence that you can transact when required. This confidence comes with having parties make a commitment to pricing market risk.

8There should be a maximum single mandatory reload.

7.3.1This is our proposed position from Phase 2 onwards. The extension of the single reload in Phase 3  of the design is for the provision of sufficient liquidity in the futures market.

9There should be limits to the number of trades that a party can do in a single quarter.

n/a

Subject to the rules of the exchange, the use of ‘sub portfolio’ stress limits is not recommended as it negates the need for the market maker to manage risk through price (rather than quantities). The portfolio stress conditions are for material exposures against the generators wider portfolio rather than a single quarter.

10A reduction in average prices is not a benefit.

8.3It depends as to whether the reduction has been achieved through a efficiency gain (as we have assumed in the CBA) or as a wealth transfer (which we have not included in the CBA).

11

The allocation methodology in Section 7.4 of the paper makes a distinction between large and small generators – this burden should be equally shared.

7.4

It is appreciated that small and large generators will have different views on what is an equitable obligation for market making. Taking into consideration feedback from stakeholders , the allocation methodology has been revised to take into account generators commercial preference, e.g. risk appetite, instead of the physical capacity of generators.

12

The allocation methodology in Section 7.4 of the paper makes a distinction between large and small generators – this proportional sharing is a useful approach.

7.4 See comment 11.

13

The potential for SP Services to utilise hedging instruments to compete for contestable consumers would be an unwelcome market development.

3.5.4The comments in the draft report were not a recommendation, merely an observation. The reference in the paper was for SPS to hedge on behalf of the non contestable consumers.

14

The development of a futures market will take some time and require an up-skilling in some quarters – the EMA should take a patient approach to market development.

5.4.4

The proposed ‘Glide Path’ development has been developed to lower the barriers to participation to address these risks, while also learning from the New Zealand regulator’s experience that development must be bounded by strong objectives and targets for market development.

15

The trading of electricity on a futures exchange has clear implications for existing disclosure rules. The introduction of a market information disclosure regime is required.

9.2The EMA is, we understand, preparing an information disclosure section in the EMA’s Consultation Paper to address these concerns. Refer to Section 9.2

Figure 3.1: Stakeholder Comments from Draft Paper (continued)

17

Serial Stakeholder Observation Paper

ReferenceCommentary

16The EMA is making significant changes in a number of areas of the market – a view on how this all fits together would be useful.

n/a

The futures market development is integrated into the wider development plans of the EMA to promote more effective competition in the energy market.

We see the development of a futures market and a demand response market as highly co-dependent.

We have recommended to the EMA that both programmes are introduced together to ensure the inter-relationships between the two programmes are able to be identified. We see the DR programme creating demand for products that are derived from the futures market.

In our view this type of implementation is always best done concurrently to ensure parties are aware of relationships and interdependences between programmes and avoid any suggestion of a hidden regulatory agenda.

17 The use of monthly contracts is preferred. 7.3.3

We have proposed that a monthly contract be traded in the prompt (i.e. first three month period) as well as the quarterly contracts after Phase 3 to enable the better risk management of physical assets. Notwithstanding this, the establishment of a forward curve should make it easier to price over-the-counter instruments for specific events.

18With SGX’s investment in EMC, participants’ margin calls should be netted.

9.3.1

No exchange has yet been selected as the market exchange for Singapore based electricity futures. But this will be further reviewed as there may be potential to net off the corresponding positions in the futures and wholesale market.

19If we take plant out of service (especially for a ‘non portfolio generator’) we should be relieved of any market maker obligations.

n/a

No, the introduction of a futures market would expand a gencos portfolio of assets and liabilities to include traded futures. Risk can be, and should be, managed directly through the futures market if physical assets (either owned or contracted) cannot be utilised.

20 Options and caps should be developed. 7.4Agree, but the development of a base load futures product is a vital first step.

21Cash flow requirements for margining will be onerous

n/a

The cash-flow requirements from futures can be simply backed off to credit intermediaries (i.e. banks) to avoid the cash-flow requirements of futures. This is standard practice for most electricity futures products traded in the wider region.

22Traded volumes are insufficient to hedge outage risks.

n/a

Even in the less liquid (than the Australian market) New Zealand futures market, we have observed very large volumes trading in the futures market (for example the first 3 weeks of September has seen over 1.5 TWh of contracts traded in New Zealand). This is more than sufficient to hedge plants if futures are progressively acquired over time to avoid significant movements in price.

23Post Implementation Review of Futures Market from New Zealand

n/a

A Review was published on the New Zealand Electricity Authority website entitled “Hedge Market Performance Update” and dated 26 June 2012. It noted the success of the market in meeting its expectations and will monitor performance over time. No further formal review is currently scheduled.

24

Industry standard documents (based on ISDA) should be prepared to reduce transaction costs and promote efficiency of trades.

7.4.8The FSC mechanism will be documented under an ISDA framework documented with a Singapore addendum for future use as an industry standard.

25

Can the contracts have a face value of 1 MW (rather than 0.5MW) and can the minimum price fluctuation be reduced to $0.05 (rather than $0.10)

5.3

The face value limit of 0.5MW presents in our view a good balance (some stakeholders want a 0.25MW contract) and avoids the face value being one of the largest contracts in the world. The move to a $0.05minimum price fluctuation seems reasonable but is not a material issue and should be considered by the relevant exchange.

Figure 3.1: Stakeholder Comments from Draft Paper (continued)

18

Serial Stakeholder Observation Paper

ReferenceCommentary

26Could the trading time be aligned with the Platts Fuel Oil market-trading window?

5.3The move to a Platts window fluctuation seems reasonable but is not a material issue and should be considered by the relevant exchange.

27The Cost Benefit Analysis is very high level can more detail be provided.

8.0

The Cost Benefit Analysis is necessarily high level and is based off our experience in other markets. With greater access to generator trading and sales data, we could considerably improve the resolution of the cost benefit analysis.

28Will FSC Volumes be provided every quarter in advance?

n/a They will be set for the entire (3 year) term of the FSC contract up front.

29What is the half hourly allocation methodology under the FSC contract?

7.4The volumes are base-load and therefore uniform across all time periods and day types over the three-year period of the FSC contract.

30 Is there any force majeure provisions 7.4 Only for whole system type failure as established in ISDA

31Is the FSC contract a financial only contract?

7.4 Yes, and settled against USEP

32Why is there a need for an electricity futures market in Singapore since most gas contracts are long-term and can be hedged.

3Refer to the objectives and benefits of an electricity futures market in this paper and EMA’s Consultation Paper.

33

There might be concerns over potential price distortion with spot or futures prices different from the prevailing retail prices when the electricity futures market is introduced.

n/a

The introduction of the electricity futures market will provide a three year forward curve for better price discovery process. This helps to prevent any potential price distortions as market arbitrage will align the spot and futures prices, and wholesale market prices will then have an ultimate impact on retail prices.

34Can there be a fixed non-fuel margin for the FSC scheme to provide greater certainty?

n/a See comment to item 6.

35Prefer to have the FSC as a separate item in the Market Rules rather than subsuming them in the existing Vesting Contract.

7Agree that the FSC should be separated from the Vesting Contract for the purpose of wholesale market settlement.

36Communication to consumers on the FSC need to be done.

n/a Agree that communication to consumers on FSC is important.

37Any mandatory market making requirements should be shared equally amongst all gencos.

n/a

The proposed approach is for the gencos to sign up market making on a voluntary basis, in exchange for the FSC incentives.  It is appreciated that small and large generators will have different views on what is equitable sharing of the mandatory market making. This will be further reviewed before any obligations are imposed.

38Further risk assessment of a market maker should be done.

n/a

We note that different stakeholders have different views on the market, e.g. on the projections of pool prices, and different commercial preferences and risk management practices. Therefore, it is recommended that such risk assessment be performed internally for meaningful use by each company.

39Is there any relief for the FSC during planned maintenance?

n/aRelief for the FSC is not recommended. Rather, a liquid futures market should enable gencos to hedge their risks more effectively for events such as planned maintenance.

Figure 3.1: Stakeholder Comments from Draft Paper (continued)

19

3.6 Financial Regulations

3.6.1 Product Approvals

As noted in the previous section, the regulation of any exchange traded derivative would be conducted by MAS if the market exchange is domiciled in Singapore. Part of this regulatory oversight includes an approval process for all exchange traded products prior to their listing. Whilst we do not foresee any issue with the approval of a vanilla electricity derivative, allowance must be made for the time that this requires.

3.6.2 Participant Qualification Requirements

It is a requirement of many exchange traded markets that dealers, especially market makers, hold recognised qualifications issued by the relevant regulatory authority. These qualifications may be specific to individuals, or be in the form of licences held by a company that are applicable to employees. Such qualifications ensure that trading is orderly and conducted by those with adequate skill and experience to manage the risks involved.

Our understanding is that generator participants in a futures market of the type discussed in this document, if the market is domicled in Singapore, will not be required to hold a Capital Market Services Licence (CMSL) due to the intangible definition of electricity under the Securities and Futures Act (SFA). It is likely that a registration maybe required under other national jurisdictions .

Relevant education and applicable qualification ensures that traders have sound understanding of the relevant rules and regulations for trading of exchange traded products and other financial products, including insider trading, customer suitability etc.20

Serial Stakeholder Observation Paper

ReferenceCommentary

40Provision of written response to feedback provided by industry stakeholders.

3.5.10

We value the feedback from industry stakeholders and have provided our response accordingly in this paper. If there are other comments that are not addressed in the draft or final reports, Cybele would be happy to address them separately.

41How will an electricity futures market help increase capacity factor of CCGT plant to displace more expensive generation?

4.2 and 5.2

Generators currently internalise their risks by running the more expensive steam plants during outages for their CCGTs when there are potential available CCGT capacity available from competitors. The futures market will facilitate the trades between generators and improve the efficiency of generation as the more cost-effective plants can be utilised during such times.  

42

Disagree with the observation that the wholesale market is inefficient, i.e. the CCGTs are not fully loaded during peak periods.

4.2 and 5.2 See comment to item 41.

43Due to market power concerns, the schedule of planned outages should not be released.

9.2The Annual Generation Outage Plan is already available to all generators.

44Sufficient lead time should be provided from a formal policy decision to actual start of the futures market.

n/a

While we note that sufficient time should be provided for the necessary implementation changes, we understand that the EMA has already started preparing the industry for the implementation by organising industry workshops as part of the education process. Subsequent operational and implementation changes should be taken internally by respective companies.  

45

While there are no major issues on the proposed implementation approach, the main challenge is to drive market adoption and participation. This may require various market education and promotion efforts collaboratively amongst the exchange, industry and the regulator.

VariousThis is consistent with our assessment and in line with the proposed approach the EMA is taking.

46

Physical offers of generators is a key in market information disclosure and should be made available to all futures market participants, whether physical or non-physical players.

9.2 See comment to item 15.

47Is the proposed FSC incentive scheme open to non-generators?

7Based on our current assessment, the FSC incentive scheme is only open to generation licensees under the EMA.

Figure 3.1: Stakeholder Comments from Draft Paper (continued)

3.7 Singapore as a Trading Hub

Given Singapore’s existing and future prevalence as a global commodities trading hub, we see the market as complementary to some of the current and planned trading initiatives. As fuel is used by generators to hedge electricity exposure, we see that increased liquidity and transparency in the electricity forward curve will bring about an increase in depth of the forward fuel markets. Clearly on a global scale this will be minimal, but the fact that the electricity market can so effectively link into the global energy markets will essentially combine the liquidity of each.

Although still in early stages of development, with liquefied natural gas (LNG) coming online from 2013 new trading opportunities will begin to emerge. Given the switch to LNG as the fuel for a number of participants, this emerging gas market will undoubtedly link closely with any electricity derivative market. Again, this linkage will help to combine the liquidity of both markets, and strengthen the linkage of LNG to other traded energy markets as it is a substitute for both piped natural gas (PNG) and High Sulphur Fuel Oil (HSFO). Synergies in the use of capital across all of these fuel markets can be created if all three products can be traded locally, with a liquid electricity market linking them. These synergies will likely bring more deal flow through Singapore as an energy-trading hub in the long term.

We recognise the benefits of having an integrated solution for Singapore based traders but have been appraised of the need to identify the best party to undertake an exchange development against an objective list of requirements.

21

4. Issues of Market Inefficiency

4.1 Introduction to Issues of Market Inefficiency

This section of the paper places the identified issues and challenges identified in the previous section in both a regulatory and economic context. The identification of market inefficiencies below are followed by an introduction to our approach to Cost Benefit Analysis.

Energy Market Authority’s Statutory Objective & Code Amendment Principles

4.1.1 Energy Market Authority’s Statutory Objective & Code Amendment Principles

The Authority’s statutory objective is to create a market framework in respect of the supply of electricity which promotes and maintains fair and efficient market conduct and effective competition or, in the absence of a competitive market, which prevents the misuse of monopoly or market power.8

Good regulatory practice is to intervene by altering regulatory arrangements only in instances where market failure or inefficiency is identified and only in the last resort. It will be important to determine whether the current absence of an effective and efficient traded hedge market creates inefficiency or a market failure either directly or indirectly in the retail and/or wholesale markets.

4.2 Wholesale Markets

4.2.1 Inter Generator Risk Transfer

We have noted in Section 2 that inter-generator derivative trading appears to be very small. In fact, the lack of availability of electricity derivatives has probably resulted in participants hedging all sales through fuel contracts. It is likely that this practice then resulted in the need for participants to generate to their sales positions in the spot market (the fuel has been purchased), which in turn makes it more likely that plant will be run out of merit order simply as a means to cover both short sales and long fuel positions.

Generally in electricity markets, there are regular occasions when a participant will not have generation capacity available to them, meaning price exposures cannot be hedged through taking a fuel position. Typical examples of this situation are when a generator has a significant portion of their portfolio on a maintenance outage, when a new-entrant retailer is acquiring customers, or when an existing portfolio generator attempts to sell volume in excess of their installed capacity.

Under current arrangements, parties facing these situations would be forced to trade OTC hedges with their competitors. If priced efficiently, this is of course an effective way to manage this exposure. However, due to the infrequency of quote requests, the seller can deduce the position of the buyer simply by the fact that a quote has been requested. Because the market is infrequent and participants have no anonymity, it is unlikely that pricing will be anything other than opportunistic. This situation is not conducive to the efficient transfer of risk between participants.

4.2.2 Generators Internalise Risk

The lack of easily tradable electricity derivatives has resulted in the situation whereby participants have little option but to internalise risk, or manage portions of it through fuel contracts. Whilst it is not possible to know exactly the contract positions of all parties in the market, the apparent lack of derivative trading, and availability of spot purchase information makes it possible to make an educated guess at what this might be for each participant.

Given the significant un-hedged spot purchases of SPS, we would expect to see all generators long on average. We would also expect each generator to be fluctuating between long and short spot positions as market conditions changed in relation to their view on price, fuel costs, and risk appetites. As this behaviour is not observed, we assume that generators simply generate to cover their purchase obligations, regardless of the pool price.

This assumption is corroborated by the fact that, net of outages, efficient CCGT plants have capacity factor of about 70%. Whilst we do not have full information in regards to fuel supply contracts as well as ramp rate and minimum running constraints of HSFO plant, we would expect that this capacity factor should be a lot closer to 100% than is currently the case.

By internalising price exposures, generators are almost certainly not reaching an optimal outcome with regard to efficient mitigation of risk. With a liquid hedge market, participants are able to transfer risk as their needs and tolerances change. Furthermore, transparent pricing and ease of access creates a more competitive market for this risk transfer. For any generator or retailer, risk can be associated as a cost of doing business. This risk can either be taken or transferred at some cost to a party that is more willing to take it or better placed to manage it. In any electricity market, a hedge market plays a vital role in lowering the cost to serve consumers, through facilitating the efficient transfer of risk to the lowest cost providers.

4.3 Retail Market

4.3.1 Wholesale Price Risk Management a Barrier to Entry

Although consumers with monthly consumption of above 10 MWh per month have been contestable there has been only one retailer has attempted to enter the market since that time. We believe this is due largely to the significant barriers to entry that exist for any new player. The key barrier is the lack of availability products to mitigate electricity price risk.compete not only on price, but through differentiation. There has clearly been some product development undertaken by the current retailers.

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We have noted that even amongst those retailers with installed generation capacity there is a reluctance to sell beyond installed capacity. This is not of grave consequence given the excess generation capacity available, but is a symptom of a wider issue, which is that retailers appear to be pricing the cost to generate electricity through their plant, rather than the cost to procure this electricity from the marginal generator via either the spot market or the forward market.

This behaviour is largely due to the fact that there is currently no efficient means of transferring price risk between participants. Thus, participants have little choice in the way in which they manage their risk.

4.3.2 Retail Innovation

Under efficient retail competition, retail prices would be subject to competitive downward pressure to the point where retail margin (the difference between risk adjusted spot or forward prices and retail prices) is equivalent to the efficient cost to serve a customer.

Furthermore, as retail competition increases, we would expect to see a more diverse range of product offerings, as retailers attempt to compete not only on price, but through differentiation. There has clearly been some product development undertaken by the current retailers. We believe that this development could still be advanced significantly although this process is probably being stifled by a lack of understanding of electricity risk management options among consumers.

For instance, very few retail contracts appear to put the electricity price risk on the consumer to be managed through separate procurement of hedge products. For large, flat profiled users, we would conclude that they are paying for the embedded optionality that is inherent in FPVV contracts, without any material gain from doing so (other than the fact that it is simple). Again, a lack of alternatives for retailers and customers is leading to inefficient allocation of risk.

Other innovations such as constant cost supply agreements are available, although it would seem that it would be difficult and expensive for these contracts to be transferred around the market until they found their least cost provider, again due to a lack of availability of any kind of hedge market.

4.4 Problem Definition

The lack of inter generator trading forces risks to be internalised by matching sales to generation capability. This physical internalising of risk can only be efficient if the generation fleet and associated fuel contracts across the generation fleet are homogenous – which we conclude they are not.

This inefficiency in the wholesale market leads to downstream impacts in the retail market. An inability to hedge wholesale spot price risk introduces a barrier to retail entry, which in turn reduces competition and product innovation and is likely to result in higher prices for end use consumers.

4.5 Introduction to the Cost Benefit Analysis (CBA)

This analysis is not a market competition study, simply a cost benefit of the introduction of a futures market. We have taken a straightforward market design for consideration of the costs and benefits. Our CBA process typically comprises six steps, we have identified these steps in the table below with associated document references.

4.5.1 Overview of Approach to Analysis

This analysis proceeds in the following steps:

a) Estimate the benefits that would be expected to arise in moving from previous arrangements (i.e. internalised risk management for net position management) to a position where material generators are obligated to act as market makers with a maximum bid/ask spread in a futures market.

This provides a reference point for considering the effect of the introduction of a futures market and variations in the type of market design.23

Figure 4.1: CBA Steps and Document References

Number Step Reference

1 Define the problem 4.2, 4.3, 4.4 and 4.5

2 Select the proposal or options for assessment 5.4

3 Specify the baseline scenario 5.4.1

4Identify the impacts of the proposal or options – negative (costs) and positive (benefits).

85Where possible, quantify the impacts;where possible, value the impacts; andadjust for differences in the timing of the impacts

8

6 Analyse the sensitivity of the results

8

This analysis proceeds in the following steps:

b) Consider how the costs and benefits are likely to alter if changes are made in the type of market design (i.e. organic OTC forward market), the use of voluntary market maker obligations, and the number of market makers and associated fixed spreads.

c) Combine the information from (a) and (b) to identify the circumstances in which the introduction of an electricity futures market is likely to yield net economic benefits.

CBA inevitably vary widely in their complexity, depth and precision, according to what is feasible within the time and data constraints, and its usefulness to inform policy development and decisions. We have undertaken a detailed analysis of the high level elements of market performance and have generated a high-level and pragmatic approach to identify the likely costs and benefits of introducing a traded futures market.

In the analysis of government policy, CBA is normally undertaken from a national economy perspective, weighing up the relative costs and benefits to Singapore as a whole. Wealth transfers between parties, although affecting the distribution of costs and benefits, cancel each other out in the aggregation of total costs and benefits to Singapore (i.e. where a cost to one party is an equivalent benefit to another party).

4.5.2 Economic Analysis

The development of a liquid hedge market is designed to impact on both the short-run operational and long-run investment behaviour of current (and prospective) market participants. It is this behaviour that the projects are intended to alter, to improve the performance of the electricity market, through more efficient signals and responses, providing benefits through:

• increased use of price instead of non-price rationing;

• increased availability and use of ways to manage price risk; and

• increased competition.

In the following sections of this paper, we identify the main types of costs and benefits for the development of a traded futures market in Singapore and describe how we quantify and value these costs and benefits. This modeling inevitably involves some simplification of market features and elements and as a result the size of any benefits will be scaled back to more than compensate for any simplifications in input data. This inherent conservatism is a benefit of this approach, as it does not seek to infer a level of precision that cannot be realistically achieved.

Although, in the first instance, the lower average price paid by participating electricity users represents simply a transfer from generators who receive the lower average price paid by these users, it would ultimately provide real efficiency benefits to the economy through reducing the costs of producing the goods and services supplied by participating electricity users.

The three components of economic efficiency are:

a) allocative efficiency – the price and quantity of electricity or other goods and services supplied;

b) productive efficiency – the cost of supplying electricity or other goods and services; and

c) dynamic efficiency – investment and innovation to pursue reduction over time in the cost of supplying electricity or other goods and services.

Reducing the costs of producing the goods and services supplied by participating electricity users would provide productive efficiency benefits. Depending upon the price elasticity of demand for these goods and services, the reduction in production costs would be shared to a greater or lesser degree with the consumers of these goods and services.

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5. Market Based Solutions

Our proposed problem definition is that there is currently a lack of inter-generator trading and that is because, generators are currently internalising risk through aligning sales and generation volumes. This practice is leading to issues in the retail, wholesale (pool), and forward markets for electricity in Singapore. Any proposed solution must aim to solve the overall problem in order to address the issues in each area of the market.

5.1 Retail Market

The issues that are manifest in the retail market are primarily that there is a significant barrier to entry for potential new participants as they are not able to access competitively priced risk mitigation contracts. A liquid market for derivatives is clearly lacking and furthermore, the lack of anonymity in the existing market creates a situation whereby it would be irrational for a generator to offer a competitively priced hedge to a new entrant retailer.

This lack of risk transfer also creates a constraint on the growth of the retail portfolios of existing participants resulting in an outcome where the retail market share is dependent more on generation market share than on competence in retailing. Due to the constraint on retailer’s positions, retail competition is being stifled. The retail market is therefore suffering from a lack of both price and non-price competition.

In order to address these issues, the proposed solution must create an environment whereby risk mitigation contracts can be transacted cost effectively, and with anonymity between retailer (and financial institution) and generator. In order to transact at low cost, there must be reliable liquidity in the market. Liquidity reduces search and transaction costs as we will show in Section 5.3. In order to provide anonymity between retailers and generators, an intermediary must be active in the market. This intermediary could take a number of potential forms; exchanges, brokers, or financial institutions could all potentially serve this function.

5.2 Wholesale Market

Of primary concern in the pool market is the fact that due to the internalisation of risk by the generators, it is almost certain that some plant is being dispatched out of merit order. This is an inefficient practice; however generators currently have little option if they wish to manage their spot exposure to levels that are within their risk tolerance.

Another issue that we have identified is the probable inefficiencies in outage scheduling. Whilst central co-ordination of outages alleviates this concern to some degree, the lack of forward price signals is likely to lead to the scheduling of outages at sub-optimal times. Again, given the lack of any forward market and subsequent price signals, generators have no choice but to schedule based on a central co-ordination process without any co-optimisation with market prices.

We note that to date there has been very little organic growth in the forward / derivatives market and as previously stated we are of the view that this is largely due to the lack of anonymity in the market, as well as the self-perpetuating lack of an active trading environment. The lack of transparency is then a symptom of these two issues. There can be no transparency of forward prices if there is no forward trading.

As with the retail market, we believe any proposed solution to the issues apparent in the wholesale market must address the current lack of generator to generator/ new entrant anonymity. Again, this can be achieved through a number of means, all of which involve the introduction of an intermediary to the market. A more difficult issue to resolve is the lack of a derivatives trading capability within the generator firms. This will be a gradual process and any proposed solution must recognise that the requisite systems and skills cannot be acquired overnight. We are of the view though, that with the right initial conditions, an environment whereby active trading is incentivized and therefore sustainable can be created. In an environment with active trading, provided there is some mechanism for price disclosure or publication (a normal feature of virtually all markets), price transparency is created. Provided the market is liquid, these prices create reliable signals for wholesale market participants in regards to outage and fuel procurement decisions.

5.3 Key Elements of Derivative Markets

In this section we explore the elements of a derivative market that are required in order to resolve the issues in the retail and wholesale markets. Primarily, these elements are anonymity and liquidity although there are a number of other elements to consider when developing a solution including cost, barriers to entry, transparency, and complexity.

5.3.1 Broad Options

There are two broad options for the trading of vanilla derivative products; OTC or exchange traded. Currently, most participants appear to be active traders of OTC fuel contracts and relatively few transactions occur in the electricity market are done OTC, although without standardised (eg ISDA) documentation.

The following table highlights the key differences between exchange traded futures and OTC forwards.

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Whilst it is apparent that OTC forwards have some favourable qualities, the anonymity, transparency and low barriers to entry in terms of documentation requirements of exchange traded futures give the greatest potential for initial development of an actively traded Singaporean electricity derivative. It is important to note that we see further development of the OTC market as complementary to any exchange traded product in that it allows counterparties to develop more customised solutions to their risk management needs, but that this development requires the underlying liquidity and price transparency of an exchange traded market.

5.3.2 Liquidity in Futures Markets

Extending the discussion in Section 3.4.1, liquidity is often likened to a fire in that initially, all the components can be there, but without an initial spark nothing happens. However once the fire takes hold, it rapidly spreads as it finds more fuel and becomes self-perpetuating. Whilst the initial participants are likely to only be the current NEMS participants, as potential participants gauge that there is enough reliable liquidity to enter the market, this liquidity will grow further. Unfortunately, as can be shown by the current state of the market, reliable liquidity is not something that is likely to occur as a natural market development. In order to ensure that there is liquidity in the market, and daily prices with which to calculate margins, an exchange listed derivative will require market makers.

In any market, the role of the market maker is to post quotes such that if another participant is willing to transact, they are able to do so with the market maker in the event that there is no other participant simultaneously looking to take the other side of the trade. The market maker therefore takes some price risk in that they will be acquiring positions as they are transacted with.

Figure 5.2 illustrates a trading screen (in the currency markets) where a market trading system has aggregated market prices from multiple participants across multiple currency pairs.

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Figure 5.1: Forward vs. Futures (Source: ASX and Cybele)

SerialForward (Contracts for Differences (CFD)) Over The Counter Contracts

Futures Contracts

1Non-standardised contract (tailored to

clients' needs)Standardised contracts (expiry, quantity, grade)

2 Counterparty risk Centrally cleared by Clearing House

3 Bi-lateral contract only Contract novation

4 Non transparent nor regulated market Regulated transparent market

5 No cash flow before contract maturity Initial and variation margins during life of contract

6 Price only available to counterpartyPrice available to the market via data vendors,

exchange web-site

7Price negotiable. Bigger companies tend to get better prices than smaller companies.

Market prices available to all users – subject to exchange requirements.

8Either no anonymity or, if brokered

may be anonymous pre-trade.Full anonymity

Figure 5.2: Market Making Screen in the Foreign Exchange Market9

For market making to assist in the provision of liquidity, prices must be reasonably close to the fair value of the products. A market maker that posts with 100% spread between bid and offer is unlikely to generate any transactions and is therefore not providing liquidity. As each market maker’s spread gets tighter, and as the number of market makers increases (all with slightly different views and positions), the spread of the overall market reduces.

Consider the case of three market makers pricing.

In the example illustrated, in Figure 5.2a, two market makers combine to provide a narrower spread than the the price making obligation would imply. The resulting, or apparent, spread is much narrower as illustrated in Figure 5.2b.

This reduction in spread is a key to increasing volume and liquidity in a market. As the spread reduces, it is more likely that the price at which a participant is willing to transact can be matched or bettered in the market, and thus more likely a transaction will occur. Furthermore, when transactions do occur, by paying a smaller spread, participants can alter their risk positions at lower cost. As this cost reduces, a larger number of participants will see the market as a viable method by which to hedge, leading to greater participation, volume, and still tighter spreads.

5.3.3 Two Way Price Making

To ensure that a market maker is providing a quote that is reasonably likely to be able to be transacted, a system of two-way quoting is enforced. This system ensures that there is a maximum difference between a market maker’s bid and offer price. By having to hold these two prices within a limited range, the market maker cannot price above or below what they perceive as a fair price without risking somebody transacting with them and therefore selling too low, or buying too high. See Figures 5.2a and 5.2b above for examples of two way pricing conventions.

5.3.4 Expectations for Liquidity

With the existence of an exchange traded derivative and market makers, we would expect to see liquidity develop over time. In order to assess the performance of the market, both potential new entrants, EMA will be using liquidity as a measure. Hence, it is important to define what is liquidity to set the expectations for the market from the outset.

We propose that the most important measurement of liquidity is not a measure of the volume that has transacted (whilst this may be a symptom of liquidity), but rather a measure of the volume that could be transacted at a price reasonably close to current market prices. Given that the development of the OTC market is complementary to any exchange traded market, our view is that it is important to consider the trading potential of both the OTC and exchange traded markets when assessing liquidity.

In terms of expectations, whilst we feel that the proposed solution will promote liquidity in the medium term, it is important to be realistic about the volume that could reasonably trade through the market without significantly impacting price. For a participant to be able to hedge 10-20MW in a trading day and only move the price 1-2% would be a tremendous improvement over the current situation. In time, this should be achievable under the proposed solution, however we do not expect that say due to an outage, a participant that is seeking to hedge 200-300MW of volume should be able to transact that in the market without adversely impacting price. This price movement is a feature of any market (referred to as “slippage”) and needs to be managed when transacting large volumes. There are various methods for doing this, generally involving breaking the order into smaller chunks to be transacted over time or through different channels (eg exchange and multiple OTC counterparties).

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Figure 5.2a: Market Making Screen in the Foreign Exchange Market

Figure 5.2b: Market Making Screen in the Foreign Exchange Market

5.3.5 Liquidity Model

We have developed a simple liquidity model using Monte Carlo simulator to estimate the apparent spreads that should be generated by a market assuming that parties are neither colluding to trade or not trade and that they are not avoiding trading even if not colluding. The model assumed a $10/MWh price spread and was run 5,000 times to produce the graph in Figure 5.3.

Figure 5.3 shows that useful levels of market liquidity (i.e. available volume within a 5% spread) can be achieved by having a handful of market makers on a fixed spread.

5.3.6 Development Potential

When deriving to a preferred solution, we have given due consideration to some of the potential product developments that could occur if liquidity in vanilla derivative contracts is achieved. Below we attempt to predict what some of these positive developments might be.

Retail Products

We feel that with the addition of a liquid and transparent forward market, retail innovation will flourish. The ability of new retailers to effectively and efficiently manage their risks will allow them to create better products for their customers. Currently, the lack of new entrant retailers, and the constraints faced by existing retailers are not conducive to an innovative retail environment. Through relaxing these constraints, competition and therefore innovation will increase.

There may be some scope for SPS to utilise the forward market to some extent in order to reduce the volatility in tariff for non-contestable consumers. Whilst we do not provide a methodology by which this could occur, it may be a market development worthy of further investigation.

Demand Response

As larger users will potentially have direct access to the hedge market, it is likely that in time there will be more consumers with an exposure to the spot price (albeit hedged through a derivative). As they move away from FPVV products, these consumers will have greater incentive to respond to short term pool price signals. By reducing consumption, a hedged load effectively becomes long the pool price. This exposure creates significant value for those loads that are able to respond to periods of short term market stress and requires no regulatory developments.

Fuel and Spread Products

Given the thermal nature of the Singaporean generation fleet, there are tight linkages with the traded fuel markets. Currently, due to the nature of PNG contracts, this link is strongest with the HSFO market. As LNG comes online, and as gas contract price indexing becomes more varied, there will likely be further development of traded fuel products that will have synergies with the electricity derivatives market. It is likely that electricity products will form another linkage between various fuel markets which should add to the liquidity of all of them.

Sophisticated inter-generator hedges

As the transparency and liquidity of an underlying vanilla product increases, so to will the potential for structured derivatives of a more exotic nature. We expect that as the derivative trading capability of the generators builds, we will see more sophisticated hedging arrangements between them on an OTC basis. These hedges will likely be used to cover outages, and may include options, time or fuel swaps, swaptions and the like. With a liquid futures market, these products can also be traded by those without physical assets including financial institutions.

5.4 Development Options/Road Map

The various choices in the development of a traded futures market in Singapore are detailed below. In this section, the following graphic illustrates the range of options considered.

The options include the status quo (the counterfactual) against which any consideration of new arrangements will be considered, together with four options that have the potential to achieve the regulatory objectives described in Sections 2.1 of this document.

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Figure 5.3: Market Liquidity from Multiple Market Makers

Figure 5.4: Development Options Considered

To assist in the interpretation of the development options and associated road map we have presented in the table below the design elements of the products and the various options. These will be used in the futures sub sections of this section 5.4.

5.4.1 Status Quo

The description of the status quo and its associated issues is contained within sections 2,3 and 4 of this report so will not be described in detail in this section of the paper.

The current market environment is characterized by a small number of relatively large vertically integrated firms. There is little evidence10 of active trading between market participants outside of the need to cover plant outages and therefore risk is internalised by the generator retailers with a consequence being that retail products are often structured to manage the risk of the generator’s11.

5.4.2 Organic Forwards

The extension of the Status Quo arrangements into a more active over-the-counter Contracts for Differences )CfD) market is often presented as a viable compromise in the development of a liquid hedge market.

The organic forward market uses the CfD instrument as its core transactional instrument. Usually based upon international standard documentation these CfD’s have many similarities and a few key differences with the core transactional instrument in a traded futures market. The following table provides a useful comparator between CfD’s and futures contracts.

Some of the issues with forward markets like transparency can be addressed with other regulatory tools including the mandatory release of key transaction details for all material hedge contracts12. The use of trading bulletin boards (like www.energyhedge.co.nz), standard market documentation and formalized price surveys13 has been attempted in either or both New Zealand and Australia to address many of the negative features of a forward (CfD) market. These developments move the Organic Forward option towards the Power Exchange category (discussed in 5.4.3).

In the New Zealand case these attempts ultimately failed due to a lack trust in the mechanisms particularly with end use consumers and new entrant market participants as they ultimately had no access to market prices.

The development path for the Organic Forward would need be to implement a range of pro-competitive reforms, see Figure 5.6, which would have the purpose of removing some of the hard edges from the Organic Forward.

Figure 5.5: Futures Market Design Elements

Serial Element Description

1 Market Marker Quantities The minimum quality requirements (in MW per contract) required

to be posted as both bid and offer volumes.

2 SpreadThe maximum fixed spread (in $/MWh) to between posted bid and

offer prices.

3 Market Making TimeThe time and length (in hours and/or minutes) of any market

maker obligation.

4 ReloadThe requirement to immediately reload prices after a trade is

conducted on the exchange.

5 Pressure ReleaseThe use of daily market limits (to restrict trading when the market

is volatile), individual position limits (to curtail over trading) and other limits as required by either the MAS or the EMA.

6 Curve Duration The number of years that the forward curve is provided.

Figure 5.6: Pro Competitive Organic Forward Reforms

Serial Initiative Description

1Price, Volume and Terms

Disclosure RegimeA requirement that the terms (duration, pricing basis, exclusions etc), price and volume are disclosed without the counterparty names within a week of a transaction being executed.

2Standard Industry ISDA

DocumentationEstablishment of a standard ISDA with Singaporean Electricity Annex to cover standard transactions anticipated to be traded in Singapore.

3 Forward Price SurveyIn the absence of a traded market the requirement that all generators provide a mid price for where they see current market prices on a monthly basis for two years.

4 Hedge Market Training Require generators to fund training programmes for end users on the use of forward contracting alternatives.

5 Mark to Market ObligationThe development of a transparent forward curve provides the ability for all assets and liabilities to be fair valued against an industry generated forward curve (at the mid price) – thereby providing further incentive to have the curve accurately priced.

Not withstanding the initiatives above, the features of an Organic Forward Market that are generally incompatible with the regulatory objective are:

• Pricing: Bigger companies tend to get better prices than smaller companies when accessing the market.

• Anonymity: A lack of anonymity may put new entrant (or smaller) participants at a competitive disadvantage when accessing the market.

• Counterparty Risk: The mere fact that a credit decision as to whether a counterparty (potentially a new entrant retailer) is acceptable to an incumbent presents a barrier, which is not easily overcome without credit intermediation (i.e. a futures market or a independently cleared Power Exchange).

Given its general inability to deliver upon the regulatory objectives of reform (i.e. benefits) and the strong likelihood that costs will be higher than the costs associated with the other options, the Organic Forward is not recommended.

5.4.3 Power Exchange

The Power Exchange approach essentially takes the features of the Organic Forward and delivers them in a framework that largely replicates a Futures Exchange.

The development of Power Exchanges in Europe has largely negated the need for a futures market (see Section 5.6 on both the United Kingdom and Nordpool), as the features of these Power Exchanges replicate many of the functions of a Futures Market. Figure 5.1 has been amended to provide a comparison of the futures and a Nordpool type Power Exchange and is presented as Figure 5.7.

The Nordpool example where forward contract settlements are processed through Nord Pool Clearing ASA is a model that could have application in the Singaporean context if a suitable party was able to fulfill the clearing-house role. Notwithstanding this, in our view the differences between the use of standard Forward Contracts arrangements on a Power Exchange and an Exchange Traded Futures contract are generally superficial (as detailed in Figure 5.7); with the critical caveat that credit needs to be operated on a full access model by the clearing function.

The sustainability of non-exchange based providers of clearing services has been highlighted by a number of developments in recent years including:

• The purchase of Nord Pool Clearing ASA by OMX/NASDAQ a United States based exchange company.

• The purchase of a majority stake of European Energy Exchange (EEX) by Deutsche Boerse a German based exchange company.

• In New Zealand with the rejection of Energy Hedge over an ASX futures contract due in part to risks and costs associated with establishing a clearing house.

These developments support our view that the development of Power Exchanges is appropriate where (or when) no futures infrastructure was available at establishment.

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Figure 5.7: Power Exchange Forward vs. Futures

SerialForward (Contracts for Differences (CFD)) Over

The Counter ContractsFutures Contracts

1 Standardised contracts (expiry, quantity, grade) Standardised contracts (expiry, quantity, grade)

2 Centrally cleared by Clearing House Centrally cleared by Clearing House

3 Bi-lateral contract with Novation Contract Novation

4 Semi Regulated transparent market Regulated transparent market

5 Subject to Clearing House credit rules Initial and variation margins during life of contract

6Price available to the market via data vendors,

exchange web-sitePrice available to the market via data vendors, exchange

web-site

7 Market prices available to all users. Market prices available to all users.

8 No Anonymity Full Anonymity

A limited scope exchange which provides for trading between counterparties with strong credit standing only is essentially the New Zealand Energy Hedge model (see Section 5.4.2), which while satisfying the secondary objectives of price transparency does not provide market access for emerging market participants (both generators and retailers).

The Power Exchange option should not be used an attempt to create an Energy Hedge type trading portal with restricted access if the objectives detailed in Section 2.1 are to be achieved.

5.4.4 Glide Path Futures

The Glide Path futures scenario seeks to establish a traded futures market for Singapore base-load electricity over the next two to three years through a progressively more onerous set of market making and trading obligations.

The Glide Path approach recognises the considerable, in some parts of the markets, skill gaps that will need to be closed before trading can sustainably develop in an open entry environment. This approach also has a minimal level of market marker obligations (especially under the proposed voluntary step up approach) and will be supported by considerable education and training support from the Exchange and external providers as required.

The Glide Path approach is time graduated, with increasing obligations as time progresses. Figure 5.8 provides a table of the Glide Path approach. The graphic makes the distinction between core design elements and ‘tuning parameters’, with the former being central to design and the latter being somewhat more flexible within the range presented in the graphic.

The glide path approach utilises a differential development path subject to whether the parties voluntarily opt into market maker arrangements prior to the preset deadline set by EMA, and also subject to the size of the installed capacity of the generation assets. The elements used to explain the various parts of the Glide Path are described in Figure 5.5.

Voluntary Establishment Approach

The introduction of a voluntary acceptance model provides the opportunity for parties to both reduce their overall risk exposures and also take some degree of ownership over the development of the market.

Incentives to be considered under the voluntary approach will be required to achieve success, this incentive mechanism, named the Forward Sales Contract (FSC), are detailed in section 5.5 of this paper.

The first stage of the Voluntary approach provides a very simple point of entry for all participants with the volumes illustrated above the minimum volumes of market making obligation anticipated from any FSC process14.

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Figure 5.8: Glide Path

Phase 1 Phase 2 Phase 3

Duration 6 Months 6 Months from Phase 1 Steady state thereafter

Figure 5.9a: Voluntary Establishment Obligations – Phase 1

Under Scheme A Under Scheme BRound 1 Only

All Generators

The second and then the final stage of the Voluntary approach assist the market to progress to a meaningful level of liquidity within eighteen months. It must be stressed that the market-making obligation is set in these graphics to the minimum level assumed under an FSC allocation.

Mandatory Establishment Approach

In the event that participants do not feel incented to voluntarily commit to a market development (even with the introduction of the FSC) the introduction of a mandatory regime will be required with higher obligations in Phases 2 and 3.

In summary the Glide Path approach provides a transitional environment from which participants can come up the experience curve in relation to markets, financial derivatives and the management of risk in a financial market paradigm without the additional pressure of new market participants increasing the complexity of this new environment.

5.4.5 Quick Start Futures

The development of a futures market that is fit for purpose on day one, designed to deliver maximum levels of liquidity and very high levels of trading volumes (on a par with markets that do not have vertical integration features) is presented in this section as the Quick Start Futures model.

The same graphical illustrations have been used from the previous section to illustrate this more aggressive form of market development.

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Figure 5.9b: Voluntary Establishment Obligations – Phase 2

Figure 5.9c: Voluntary Establishment Obligations – Phase 3

Under Scheme A All GeneratorsUnder Scheme BRound 1 Only

All GeneratorsUnder Scheme BRound 1 Only

Under Scheme A

There is no phasing of implementation for this approach. This model while simple to implement would raise considerable issues of stability and sustainability issues. Inexperienced generator/retailer market makers being exposed to professional, non-electricity market, traders and speculators would considerably increase the risk of total market failure if pursued.

5.5 Summary

The preferred option is the glide path futures approach where generators enter into voluntary market making agreements with the exchange(s) to be voluntary liquidity providers in the electricity futures market. Notwithstanding the above, should there be insufficient interest from the generators to start this process organically, the design of some form of incentive mechanism is recommended. The incentives should be designed to be in line with the recommended Glide Path approach.

The ability to incentivize generators into entering into voluntary but binding market making arrangements could be done through the introduction of a forward sales contract (FSC), but with the expectation that a failure to establish a viable market will see the introduction of a mandatory obligation. An option for the provision of sufficient incentives for generators to opt into a market making arrangement with an exchange is detailed in Section 7.

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Figure 5.10: Quick Start Futures

6. International Experience

The consideration of learning from markets similar to the Singaporean electricity market (like New Zealand) and others that share some degree of similarity are provided in this section of the report. Coverage of the New Zealand, Australian, NordPool, US (PJM) and the UK markets are introduced below. This section should not be considered to be a detailed description of each market, but merely an overview with relevant issues to Singapore from this international experience highlighted.

The following table provides a brief summary of the various markets, their similarities and differences with Singapore. These elements in each of these markets are considered separately in the paragraphs below.

6.1 United States

PJM (Pennsylvania, New Jersey, Maryland)

PJM is based upon two markets, a day-ahead market and a real-time balancing market (PJM is a net settlement market). As the PJM market only provides a day ahead and real time market there is a need to hedge forward price risk, especially given the variability of credit quality between participants and the size and diversity of the market and its participants.

Both futures contracts (traded on CME owned exchanges NYMEX) and forward contracts through traditional brokers are traded in various hubs in PJM. There are currently 52 futures and 9 options contracts listed on NYMEX15 for PJM. These contracts have a range of durations from daily to five-year contract.

The following graphic (Figure 6.2) illustrates the dominance of PJM in the trading of North American electricity contracts. The 1,257 TWh of year to date transactions to 30 September 2011 is large in absolute terms and also in relation to the underlying annual demand of almost 700TWh in PJM market.

A rise in credit risk recognition of the poor relative credit standing of the merchant power sector prompted a movement to exchange traded futures contracts in the early to mid 2000s. Open interest in the PJM monthly contract rolls from 5,073 contracts at the end of June 2003 to over 32,000 contracts a year later (over a 500% increase). In spite of the large volume of exchange-traded futures contracts, OTC hedge contracts are widely viewed to continue to represent the greatest volume of hedge contracts within PJM.

A large proportion of the futures trading activity in PJM is short term to support the balancing nature of their net market design. Complementary hedging instruments like the highly complicated financial transmission right (FTR) provide a wide range of hedging options and instruments for market participants. NYMEX is also settling a growing number of OTC trades because of the credit risk enhancement this provides – there is however no price transparency to these OTC transactions.

6.2 United Kingdom

The wholesale electricity market in the United Kingdom (but not Northern Ireland) has been under reform since 1990 when the UK established Europe’s first organized power market. Additional reforms in March 2001 (introduction of the New Electricity Trading Arrangements – NETA) and then the 2005 (introduction of the British Electricity Trading and Transmission Arrangements, BETTA) have formed the basis of the current UK power market.

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Figure 6.1: International Summary Table

Sing. NZ US (PJM) Nordpool UK Australia

Physical Size 42 TWh 43 TWh 685 TWh 400 TWh 390 TWh 205 TWh

Pool Type Gross Gross Net Net Net Gross

Vertical Integration Yes Yes No No Yes No

Dominant Fuel Thermal Hydro Thermal Hydro Thermal Thermal

Annual Trading Volumes

Nil 2 TWh 1,650 TWh 1,200 TWh 20 TWh 225 TWh

Figure 6.2: YTD Volume of US Based Futures Markets on NYMEX and other CME Exchanges16

Although the UK market is highly vertically integrated, with 6 large generator-retailers holding 99% of the market share, forward market trading has volumes generally in excess of 3 times the underlying physical market.

The market has a balancing mechanism for physical generation, this market has a one hour gate closure but most transactions occur well before this gate closure to achieve balance. The UK forward market has bilateral OTC contracts in its core market design as counterparties seek to manage their physical balancing obligations.

These OTC contracts are traded through dedicated brokers in a very transparent manner. Furthermore, exchange traded forwards (vanilla contracts) and day ahead auctions are all heavily traded by generators, retailers, banks and speculative trading houses.

UK electricity futures products were listed on the APX/ENDEX in 2000 (as the UK Power Exchange), the ICE exchange in mid 2004, and more recently the NASDAQ/OMX in 2011. Volumes are relatively low with 16 TWh being traded on APX/ENDEX in 2011. This is not surprising given that there is already an active exchange traded forward market, there is little use for futures products. The number of active participants in futures markets is only about 20% of that in the exchange traded forward market.

It is noteworthy that despite the high traded volumes as a percentage of physical (relative to say Singapore or New Zealand), and spreads in the order of 1-2%, the UK market regulator is currently looking at the introduction of a mandatory market making obligation on the 6 largest generators in order to improve the poor liquidity in the forward markets.

6.3 Nord Pool

Nord Pool was the first multinational power exchange in the world. Statnett and Svenska Kraftnät (national transmission companies) each own 50 percent of the Nord Pool.

Nord Pool is made up of three inter related markets.

• A day-ahead spot market (Elspot)

• An intra-day balancing market (Elbas)

• A financial derivatives market (Eltermin)

Market rules cover the operations of the market. Nord Pool also provides clearing and settlement for OTC trades, which is a very large feature of the market. The prices and volumes of all trades are published without disclosing the identities of buyers or sellers. Nord Pool is the central counterparty of all trades and guarantees settlement.

The Eltermin market has futures contracts for days (in the current week) and for weeks (rolling 6 weeks). In addition, OTC forward contracts for months (rolling six months), seasons (next season), quarters (up to two years out) and years (up to four years out) are listed on Eltermin and settled on the Nord Pool trading platform to eliminate credit risk between market counterparties. There is considerable price transparency in the Nord Pool markets as activity is concentrated into a central market services company. OTC volumes are about two to three times futures based trading volumes18.

There are hundreds of participants on both the buy side and the sell side in Nord Pool’s Elspot and Eltermin markets and the OTC market. The participants are diversified in terms of size, ownership and activities. There is very little vertical integration. There is considerable need to re-contract from time to time amongst participants.

6.4 Australia

The Australian National Electricity Market (NEM) spans the eastern states of Queensland, New South Wales, Victoria and South Australia, Tasmania and the Australian Capital Territory. The western and northern states and territories of Australia have their own arrangements.

The hedging of market risk for Australian market participants has become an increasingly important activity for retail and generation businesses. The lack of vertical integration between generators and retailers creates a natural demand for hedging, which has been increasing as both merchant generators and retailers are increasingly concerned about counter party credit risk. Figure 6.4 provides an illustration of the growth in futures demand over the first ten years of the market.

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Figure 6.3: UK Forward Market Volume17

Trading volumes in the ASX are now many times that of physical volume with a significant volume cap, baseload and peak load contracts being traded.

The nature of volatility (from capacity rather than energy scarcity) drives demand towards option related products – an exchange traded $300 cap contract has been a popular product for participants.

6.5 New Zealand

The New Zealand Electricity Market (NZEM) is very similar to the Singaporean market operating as a nodal gross pool market since 2003 (prior to 2003 it operated as a nodal net pool). The market is also highly vertically integrated with generator retailers accounting for well over 95% of retail load.

The development of a liquid hedge market has been a regulatory objective (for the relevant regulator) since 2003. Initiatives to improve transparency and liquidity initially involved industry working groups and various rounds of consultation to facilitate the development of a market. The risk practice of generator-retailers in trading simple derivative contracts was at best variable – with many participants seeking to ration quantity through non-price mechanisms (including onerous force majeure clauses and simple deprival).

The establishment of a simple forward contracting deal matching service called Energy Hedge in 2003 was the first industry attempt to provide a transparent forward curve. Energy Hedge initially established a 10% mandatory two-way price at a single node (geographically in the middle of the country) for three years but provided no ability to access prices (and therefore liquidity) to non-Energy Hedge participants. One financial institution joined towards the end of the Energy Hedge period. Progressively active and urgent questioning from the Regulator on the development path for Energy Hedge led to some extension of the market in terms of product, location and duration, but was ultimately insufficient to placate the Regulator and a new Minister of Energy from direct intervention.

A Ministerial Review into the development of a hedge market provided the industry with a simple test to avoid direct regulation. This simple test was:

All major generators (with over 500 MW of capacity) to put in place by 1 June 2010 an electricity hedge market with the following characteristics:

– standardised, tradable contracts– a clearing house to act as a counter-party for all trades– low barriers to participation and low transaction costs– market makers (offering buy and sell prices with a maximum spread) to provide liquidity.

An assessment to be made by 1 June 2011 of satisfactory market liquidity, defined as 3,000 GWh of ‘unmatched open interest’ (contracts without matching offsetting contracts).20

The development of a market occurred in three distinct phases:

1. July 2009: The initiation of an ASX futures contract with limited (and voluntary) market making support by one generator-retailer. (Outcome: 1 participant with a 10% spread)

2. July 2010: All generator-retailers sign up with ASX as price makers (Outcome: 4 participants with a 10% spread).

3. November 2011: generator-retailers agree to reduce market making spreads and increase quantities after pressure exerted from Regulator on failure to meet the 3,000 GWh open market interest target. (Outcome: 4 Participants with a 5% spread).

The following graphic (Figure 6.5) illustrates the development in the New Zealand context through these phases.

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Figure 6.4: YTD Volume of US Based Futures Markets19

Figure 6.5: New Zealand Futures Contracts Open Interest

6.6 Lessons for Singapore

The experiences in the five markets briefly introduced above are all different. The largest negative impact on futures market liquidity is the degree of vertical integration between retailers and generators and/or the concentration of participants in these sectors. The higher the vertical integration and the greater the concentration of participants the lower the degree of futures (or forward) based market trading. Australia, which does not have anywhere near as wide number of participants compared with PJM or Nord Pool, but with limited vertical integration, has managed to develop a vigorous forward and futures markets. However, with the right infrastructure, trading culture, and initial liquidity, the issues caused by vertical integration can be overcome, as has been shown by the UK market, as well as the strong recent growth in the NZ market.

As most of the world’s power markets are net pool market, the role of the balancing market does inflate the volume of transactions being reported in power exchanges, futures markets and the potential as OTC contracts. These low value (NYMEX quotes a PJM contract with a face value of 80 MWh) and short duration contracts produce impressive trading statistics but in our view can be seen as an extension of the spot and balancing markets. While not an arbiter of success or failure in the development of a futures trading market, the differences in reported trading volumes between gross and net markets need to be considered when assessing success.

The zonal and nodal distinction is also not an arbiter of success or failure in the development of a liquid futures market. However, the ability to concentrate liquidity (as is done in the nodal PJM market) to a small number of trading locations is important. This is somewhat of a moot point for the Singaporean market with the use of the USEP.

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7. Preferred Solution

7.1 Introduction

The development of a preferred solution for the development of a futures market has been developed with extensive industry engagement with the buy side (consumers and retailers), sell side (generators), intermediaries (financial institutions), exchanges and regulators / government agencies.

This process has been very much a consumer and industry driven initiative to improve retail competition through a transparent and effective futures market. The preferred solution was recommended in Section 5 as the Glide Path Futures development option. The following sections provide further support for the development of a futures market in Singapore on this Glide Path Futures approach.

7.2 Voluntary Incentives backed with Mandatory Obligations

We recommend that the ability to incentivize generators into entering into voluntary but binding market making arrangements should be done through the introduction of the Forward Sale Contract (FSC) regime, but with an explicit expectation that a failure to establish a viable market will likely see an introduction of a mandatory obligation.

7.2.1 Voluntary Incentives

It is recommended that a voluntary arrangement to be introduced as a voluntary scheme for generators to participate in the futures market as price markers. This scheme will largely be based on the commercial terms of a current LNG21 vesting contract, and be introduced for a minimum three-year period which in turn would be subject to a review and potential extension by the EMA. The introduction of this voluntary arrangement would dovetail into the gradual roll back of the legacy vesting contract scheme. We have worked on the basis that a 5-6% of total forecasted electricity demand (a fixed MWh) as of a specified date would be needed to provide sufficient volume and therefore incentivising market participants to participate. The actual total volume of FSC to be allocated will however be set by EMA. This voluntary arrangement is described in greater detail in section 7.4.

This commercial arrangement, named a Forward Sales Contract (FSC), will be enabled as part of the Vesting Contracts Sections of the Rules, but will be voluntary for any market participants to opt in. Based upon standard financial markets documentation, specifically the use of the financial industry ISDA standard, these contracts will also have the benefit of preparing the market infrastructure for greater OTC trading activities between generator/retailers. The FSC will be distinct from the vesting contract (i.e. above and beyond the prevailing vesting contracts volume).

The offering of this voluntary arrangement will have an opt-in deadline for participant opt in on or prior a preset deadline to be determined by EMA, where the parties will state the quantity committed to two way price making on fixed spreads as detailed in our preferred design. The volume of the FSC will be allocated on a balance of effort basis so long as the minimum requirement has been meet.

7.3 Staged Implementation

The proposed market design is a staged development in both product type and its implementation. The staged implementation of a futures market is designed to reduce the risk for market participants as they climb what will be an initially steep learning / experience curve. The introduction of additional and complementary products is also introduced in this section but would not be subject to the same obligations on participants as the primary futures contract specification.

7.3.1 Contract Specifications

It is proposed that the following recommended features are put in place in the product and market design with the glide path approach recommended. The features also provide the recommended assessment criteria by which the opt-in programme is assessed (and valued) against.

Notwithstanding the recommendation, the following parameters are open for further refinement between the generators and the exchange. This is consistent with our recommended approach for the generators to select and work with their preferred choice of an exchange and the parameters of the futures contract.

Element Detailed Description

Unit0.5 MW of electrical energy per hour for the Uniform Singapore Energy Price (USEP) over the

period of a calendar quarter.

Contract MonthsMarch / June / September / December such that sufficient quarter months are always available

for market participants to trade over 3 calendar years. At any point in time a minimum of 13 quarters will be listed.

Minimum Price FluctuationPrices are quoted in Singapore dollars and cents per MWh. The minimum fluctuation is $0.10.

This however could be reduced to $0.05 if preferred by the exchange.

Figure 7.1: Futures Contract Specifications at the end of development path (i.e. steady state)

7.3.2 Market Making Obligations

The introduction of market making arrangements is a key element of this approach as we believe that a voluntary approach (see section 5) to liquidity building will fail unless adequate incentives, as described in Section 7.2, are in place. The references to Voluntary Market Making trading volumes are intended to provide an indication of what should be provided by the parties under the incentive regime, but recognise this is not prescriptive, with the exception of the overall reserve limit of 13.5 MW.

We can foresee the development of a voluntary market making arrangement the same in all material respects with this Preferred Solution being proposed in this Section with the introduction of the FSC mechanism and with the additional step of legislation as effective regulatory backstop.

7.3.3 Implementation Phasing

The trading of electricity derivatives is not currently an apparent strong competence of the generator participants in the Singapore electricity market. Given that many of the benefits to accrue to the market, from the introduction of a traded futures market, are from the dynamic efficiencies generated by improved price transparency and improved market function by the generators themselves. Therefore there is a real need to transition generators into the market progressively over a short period of time (twelve to eighteen months) in a way which enables them to build confidence and competence in price making and trading in a sustainable manner. The following table details the phase timing for implementation of the Market Maker Obligations detailed in Section 7.3.2. The introduction of a monthly contract after Phase 3 is also recommended.

Element Detailed Description

Tick SizeA 1,080 MWh contract quarter has a tick size of $108.00.A 1,092 MWh contract quarter has a tick size of $109.20.A 1,104 MWh contract quarter has a tick size of $110.40

Last Trading Day Last Business Day (in Singapore) in the Calendar Quarter.

Settlement Day The sixth Business Day (in Singapore) after the expiry of the Contract Quarter.

Trading Hours 9.00am - 5.00pm Singapore time

Market Maker Obligation Times 4.30pm - 5.00pm Singapore time (Last half hour of Singaporean trading)

Settlement Method Cash settled

Exchange Rule These contracts are listed with, and subject to, the rules and regulations of an Exchange.

Figure 7.2: Futures Contract Price Making Obligations – Voluntary with FSC

Condition Phase 1 Phase 2 Phase 3

Mandatory Two Way Price Making Spread

$20/MWh $15/MWh $10/MWh

Period of Mandatory Market Making

4.30pm to 5.00pm Singapore Business Days4.30pm to 5.00pm Singapore Business Days4.30pm to 5.00pm Singapore Business Days

Voluntary Market Making Trading Volumes (each side)

Minimum Levels under FSC

Scheme A1 Unit per Contract22

Scheme A2 Units per Contract

Scheme A3 Units per Contract

Voluntary Market Making Trading Volumes (each side)

Minimum Levels under FSC

Scheme B2 Units per Contract

Scheme B4 Units per Contract

Scheme B6 Units per Contract

Voluntary Market Making Trading Volumes (each side)

Minimum Levels under FSC

33% of Phase 3 Volume

66% of Phase 3 Volume

100% ofPhase 3 Volume

Refresh No Yes, onceYes, once and followed

by best endeavours

Portfolio Stress Clause Yes Yes Yes

Cumulative Contract Duration1 year

(4 contracts)2 years

(8 contracts)3 years

(12 contracts)

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This Glidepath approach has the additional benefit of providing a strong signal of market structure and price making support to non traditional parties (including financial institutions, prospective new retailers and/or generators). This confidence will in our considered view, will increase the attractiveness of the market for their own participation. The ability for the Authority to progressively monitor market performance and increase or decrease product settings (referred to as the tuning parameters in Section 5.4.4.) is also a feature of this preferred solution.

7.4 Forward Sales Contract (FSC)

7.4.1 Introduction

It is recommended that a voluntary arrangement via a Forward Sales Contract (FSC) regime be introduced as an ‘opt-in’ scheme for generators to participate in the futures market as price makers. Given that there might be potential costs to the generators participating as market makers, the FSC allows generators to have fixed price (repriced quarterly) contracts to mitigate the risk of the uncertainty under market making arrangements. The FSC has similarities with the current vesting contract arrangement (i.e. Contract for Differences between generators and SPS at vesting price), but should be viewed as a separate scheme with difference objective for the market. In terms of implementation, we recommend that the FSC dovetails with the gradual roll back of the legacy vesting contract scheme (e.g. FSC to be implemented when vesting level drops from the current 55% level as more capacity enters the market), and be introduced for a minimum three-year period which in turn would be subject to a review and potential extension by the EMA. We have worked on the basis that a 5-6% forecasted electricity demand (a fixed MWh) as of a specified date would be sufficient to provide adequate volume and therefore incentivising market participants to engage in voluntary market making. The actual total volume of FSC to be allocated will however be set by EMA prior the start of the scheme.

We view the introduction of the FSC as a pure incentive for the adoption of the voluntary market maker arrangements. A 20% share of a 5% FSC (i.e. 1% of FSC) equates to a 50 MW baseload hedge contract at the LRMC value of a modern LNG fueled generation asset. We recommend the FSC price to be based on the commercial terms of a current LNG vesting contract as new capacity for existing and new players are on LNG contracts. Given the impending plant commissionings that are scheduled to occur in 2013 we believe these contracts will be highly sought after as they provide greater levels of revenue certainty for the generators.

Assuming a 5% discount from LRMC prices which is very close to average spot pricing and a three year arrangement, the value of this arrangement has a net present value (NPV) of around $10m. This is well above the assumed costs of providing a 3MW two way pricing obligation.

The offering of this voluntary arrangement will have an opt-in deadline for participant to opt in on or prior a preset deadline to be determined by EMA, where the parties will state the quantity committed to two way price making on fixed spreads as detailed in our preferred design. A minimum requirement of 13.5 MW23 per side is required for the FSC arrangements to become operative at Phase 3. The volume of the FSC will be allocated on a balance of effort basis so long as the minimum requirement has been meet. There is no benefit for early action if this reserve level is not met to avoid any perverse incentives.

The core elements of the proposed FSC are detailed in the following sub-sections.

7.4.2 Minimum Structural Features

It is proposed that the minimum features described in Figure 7.1 and 7.2 are put in place in the product and market design at the end of the development path associated with the glide path approach recommended. The features also provide the minimum assessment criteria by which the opt-in programme is assessed (and valued) against.

7.4.3 Volume Allocation

The design of the instrument provides a strong incentive for generators to opt into the FSC mechanism to the extent that their internal risk envelope allows. The volume allocation of the FSC volumes is based upon the pro-rata share of Phase 3 bid/offer volumes that are compliant with the minimum features detailed in Figure 7.1. This approach may well see smaller generators sufficiently comfortable with trading risks which would then led to them taking a disproportionate share of the FSC volume to their installed generation asset fleet. Therefore, even though the installed asset portfolio of any generator is not directly related to FSC volumes, it should have an impact on their relative risk appetite and risk preferences.

In the event that total bid/offer volume from the opt-in process deadline is below 13.5 MW for either bid or offer volumes or the number of participants is below 4 (the de-minimis), then the opt-in process will be deemed to have failed. EMA might wish to have the right to use opt-in volumes as a residual reward to any subsequent market maker arrangements either voluntarily or mandatorily. We would caution EMA in this approach as it may well provide a perverse incentive to offer minimum volumes, with any failure of the opt-in to reach the de-minimis resulting in the initiation of any subsequent mandatory response.

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Figure 7.3: Futures Contract Development Path Timing

Condition Phase 1 Phase 2 Phase 3

Duration of PhaseFirst 6 Months of Market

OperationSecond 6 Months of

Market OperationSteady state thereafter

It is recommended that the FSC prices and volumes are reviewed and revised by the EMA every three years.

a) Allocation Process

Prior to the allocation process, the generators will have to opt in and indicate early interest in participating in the futures market as voluntary market makers. Even though no actual bids are required by the generators in this juncture, the indicative interest (i.e. yes or no) is binding on the generators such that those who do not indicate interest will not be eligible for the allocation of FSC during the actual bidding and allocation process.

Generators which have indicated interest to submit bids for the voluntary market making (VMM) arrangements will then be invited to submit their actual MW bids. There are two schemes for the allocation process, based on the pro-rata share of Phase 3 bid/offer volumes that are compliant with the minimum obligation. The full volume (MW) of VMM has to be bid in at the start (i.e. no subsequent bidding or changing of bid volume). The FSC will be allocated (using preset formulae) based on the volume (MW) generators offer on the futures market as voluntary price makers.

All generators can sign up for either of the schemes:

(i) Scheme A: FSC allocation with a minimum bid of 1.5MW; and

(ii) Scheme B: FSC allocation with a minimum bid of 3MW in Round 1 and optional tranches of 0.5MW in Round 2.

The two schemes provide the opportunity for generators to reflect their commercial risk (and value) preferences in the allocation round. It is recommended that the FSC price and volume are reviewed and revised by EMA every three years.

b) Timing

The timing of the opt-in and bidding period is to be determined by EMA.

c) Contract Suspension

It will be important to include mechanisms that continue to obligate participants to maintain compliant market maker agreements with an approved exchange. See sections 7.4.4 and 7.4.5.

d) New Generators

All companies with a generator license from the EMA will be eligible to participate on the sell side of the FSC scheme.

e) Allocation Process

The calling for a tenders as part of the allocation process by the EMA will require qualifying participants in the Tender to agree to subject themselves, for the duration of the FSC contract, to a requirement to provide, when requested a declaration (for a defined time period) from either, their Chief Executive/Managing Director or from their Board, confirmation that they have met, in all respects, the market making provisions detailed in the FSC Tender document.

The EMA will not have the right to seek a declaration at a greater frequency than quarterly.

7.4.4 Scheme Opt Out Period

Participants will be able to remove themselves from the FSC and Market Maker obligations in Phase One if they have given notice to the EMA, MSSL and relevant exchange. Commitments will terminate at the end of Phase One (after six months of operation).

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Figure 7.4: Proposed FSC Allocation Scheme & Rates

Scheme AScheme AScheme A Scheme BScheme BScheme B

Condition MM Volume

FSC Volume (% of total forecast demand)

Rate MM VolumeFSC Volume

(% of total forecast demand)

Rate

Round 1 1.5 MW 0.3% 0.2% per MW 3 MW 0.75% 0.25% per MW

Round 2 0.5 MW 0.15% 0.4% per MW

7.4.5 Penalties from a Failure to meet Market Maker obligations after Phase One

Participants that choose to end their market maker agreements (as signaled by a declaration and as required by EMA under its FSC allocation) after Phase One will be required to return of any mark-to-market benefits as measured and settled quarterly (from the Gencos perspective). This mark to market payment obligation will span from the start of the FSC scheme until the end of the contracted FSC regime (i.e. three years).

This repayment requirement will not be symmetrical and in the circumstance that a quarterly settlement is out of the money to the Genco no reimbursement will be made. Additionally a further penalty of 10% of any mark to market losses paid by the Genco or the sum of $250,000 per quarter over the entire 3 year FSC regime will also be required which ever is the higher.

7.4.6 Pricing

The cost and benefits of the introduction of the FSC incentives are quantified and incorporated in the cost-benefit analysis detailed in Section 8 of this paper. At this point, without fully understanding the risk preferences of the generators, it is likely that the value of the FSC is actually greater than the P50 mark to market (or mark to model) value of the contract. This is due to the risk adverse nature of the generators as they enter into a period of generation oversupply.

7.4.7 Comparison with the Vesting Contract

The FSC contract is largely modelled, in its economic benefits, around the LNG vesting contracts offered to generators in the last couple of years. LNG vesting and FSC have some similarities but also much differences. The following table details the the key features of both instruments:

7.4.8 Documentation

The FSC will be based upon an Singapore Electricity Addendum to the 2002 ISDA Contract. This arrangement will replicate many of the features of the existing LNG Vesting Contract but within a standard (and EMA endorsed) contracting framework.

The development of a Singaporean ISDA addendum provides another element of important (and currently not developed) market infrastructure for OTC transactions.

7.4.9 Assurance

To ensure compliance with the voluntary market maker arrangements described in this section, each party that opts in, would be required to sign a statutory declaration that it was compliant with the minimum obligations detailed in this section 7, either annually or as requested by the EMA but not more frequent than quarterly.

7.4.10 Further Development

While the development of a baseload three year forward curve will be sufficient to seed the market and move generators up the experience curve, the further development of products should be an explicit expectation of the Authority. The next product with the greatest utility to the market would be the introduction of a $300 cap product.

We do not believe that this instrument should in the first instance be subject to a market making requirement. Unlike the baseload instrument, the hedging of market risk for the cap product back through physical plant is not universally possible in the NEMS. Therefore the subset of generators with diesel peaking capable plant (or new entrants) should themselves promote the development of the $300 cap product.

If after three years of liquid baseload futures trading a $300 cap product has not emerged, the Authority should revisit the need for regulatory measures to stimulate further product development.

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Figure 7.5: Comparison of the FSC and Vesting Contract

FSC Contract Vesting Contract

Quantity/Volume5% of average total forecasted electricity demand

2013-175% of total electricity demand

Pricing LNG26 LRMC PNG & LNG LRMC

Voluntary Yes Mandatory (for Big 3)

Counterparties Generators/SPS Generators/SPS

Documentation ISDA Vesting Contact

Volumes Reviewed 3 year contract term Biennially

Load Shape 1% of Base Load Peak Load Biased with an average of 1%

8. Cost Benefit Analysis

8.1 Introduction

To enable a direct comparison of costs and benefits occurring at different points in time, we adopt a real discount rate of 10%, to convert future prices levels (for both costs and benefits) into their present 2012 values. Sensitivity analysis where conducted will specify the variances to this default case. All values are expressed in real terms in 2012 prices in this paper.

The baseline (or counterfactual) scenario against which this preferred solution is being assessed is the current market design and characteristics detailed in Sections 2 and 3 of this paper.

8.2 Sources of Economic Benefit

The robust pricing of futures contracts is expected to increase hedging activity by market participants. While increased hedging does not, in itself, represent a net benefit (given that hedging constitutes a transfer of cost/risk from one party to another or from one point in time to another27), it is expected to have positive effects on investment and operating decisions (including greater competition in the retail market and providing more certainty for thermal fuel purchasing decisions which would have benefits for system security).

These benefits arise because the presence of robust hedging arrangements and information about the forward curve allow parties to take actions that they would not otherwise undertake. Moreover, parties do not need to actively trade futures contracts to obtain these benefits. A more robust forward price curve would facilitate the use of customised OTC hedge agreements, which quite conceivably be the predominant hedging instrument for many parties.

Improved market-making arrangements are expected to have benefits in the following areas:

a) stronger retail competition, because parties entering or expanding their presence in the retail market are able to better manage their exposure to price risk;

b) improved outage management, because parties managing outage risks will be able to better manage their exposure to price risk;

c) improved fuel management decisions because parties have a more robust indicator of expected future electricity market conditions;

d) improved demand-side operating decisions, such as whether to commit to a production order or buyback contract, because they have a more robust indicator of expected conditions and greater confidence to enter into contracts;

e) improved generation investment decisions leading to stronger generation competition, because parties have a more robust indicator of expected future conditions; and

f) improved demand-side investment decisions, such as whether to expand production facilities or develop demand response capacity, because they have a more robust pricing benchmark for the future.

The key benefits of market making in a traded futures market are discussed in more detail in the following sections of this paper.

8.2.1 Set Up, Implementation and Operating Costs

Direct costs include items such as a requirement for some parties to invest in systems or take on more staff to manage the processes associated with the market-making obligation. As with most commodity markets that are cash and not physically settled, risks can be managed either through physical assets or risk capital (but in both cases with the necessary human capital).

While the nature of pricing is very different to the generators’ current exposure in fuel oil and associated OTC markets, much of the human capital and some of the physical assets (systems and processes as opposed to power stations) and some of the risk capital required to operate as market makers are present in all of the generators (and in some cases prospective generators) today.

Existing generators all have extensive fuel and currency trading capabilities in two of the world’s deepest and richest trading markets. It is acknowledged that parties acting as market makers may take on additional exposure to trading risk. As futures contracts are cash settled, these risks can be managed by access to either physical assets or financial capital, combined with the necessary trading capability. In the latter context (use of risk capital), the key competencies will be in gathering and analysing information that affects the future price of electricity, formulating trading strategies based on this analysis, executing these trading strategies, and the reporting and settlement of exposures as part of a trading function within a price making generator.

Figure 8.1: Linkage between market-making and economic benefits

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Given the existing trading capability in fuel oil the key area of uncertainty therefore appears to focus on the incremental cost that price making generators would incur if there is a need to enhance trading capabilities. One view would be that this cost should be nil or very modest because existing generators have been active participants in global fuel and currency markets for many years. The counter view is that generators may need to make some incremental investment in its trading capacity. It is difficult to assess which of these views is correct without access to detailed company specific and sensitive information.

Given this uncertainty, this analysis considers three different cases:

The costs above have been estimated based on the experience in international jurisdictions. Given the nature of markets, and international standards for best practice in regards to trading in those markets it is unlikely that costs will be radically different from those incurred overseas. In fact, given the fungible nature of people and systems we expect these costs to be very similar to those incurred in NZ, Australia and the UK, which are reflected in the estimates above.

8.2.2 FSC Costs

The cost of the FSC programme have been assessed and estimated to be about $50m28. Assuming a 5% discount from LRMC prices, which is very close to average spot pricing, the value of this arrangement has a NPV of around $10m. The estimation assumes a three year arrangement and a full 5% of total market volume being allocated to all qualified participants.

8.3 Benefits – Sensitivity Based Analysis

In general, six types of benefit are to be reaped from the introduction of a traded futures market with market makers. The benefits have been divided into two broad groupings, specifically first order and second order benefits. The first order benefits are direct impacts on the wholesale market from the introduction of a traded futures market, with second order benefits being realised as a result of first order benefits being realised.

In making estimates and assumptions regarding the magnitude of benefits, we are cognisant of the fact that any estimate that we make will be inaccurate. However, in making our assessments, we have in each case taken what we deem to be very conservative estimates of both the amount of the market affected and the magnitude of the effect. In many ways these estimates are better described as sensitivity studies rather than absolute forecasts. The benefit estimates below represent the lower end of a wide distribution of possibilities.

The first order benefits included in the cost-benefit analysis of the proposal are summarised in Figure 8.3 below:

Type Frequency Low Case Mid Case High Case

Implementation Costs to EMA Initial $100,000 $150,000 $250,000

Implementation Costs to MAS Initial $100,000 $150,000 $250,000

Operating Costs for MAS & EMA Ongoing $20,000 $25,000 $30,000

Setup Costs to Exchange Initial $50,000 $75,000 $100,000

Operating Costs to Exchange Ongoing $15,000 $30,000 $50,000

Setup Costs to Participants (Market Makers)

Initial $100,000 $500,000 $2,000,000

Operating Costs to Participants (Market Makers)

Ongoing $100,000 $200,000 $500,000

Figure 8.2: CBA Cost Matrix

Figure 8.3: CBA First Order Benefits Matrix

Type Frequency Low Case Mid Case High Case

Improved hedging between market makers

OngoingTransfer between market participants and/or consumers -

no net benefits but material wealth transfers expected.Transfer between market participants and/or consumers -

no net benefits but material wealth transfers expected.Transfer between market participants and/or consumers -

no net benefits but material wealth transfers expected.

Lower search and transaction costs during scheduled maintenance outages

Ongoing$2.50/MWh for 25% of plant

out for 14 days per annum.$2m

$2.50/MWh for 33% of plant out for 14 days per annum =

$2.7m

$2.50/MWh for 40% of plant out for 14 days per annum =

$3.3m

Reduction in average retail price as new retailers compete for

contestable business29Ongoing

$0.5/MWh reduction for 30% of contestable consumers.

$1.6m

$1.5/MWh reduction for 30% of contestable consumers.

$4.8m

$3.0/MWh reduction for 30% of contestable consumers.

$9.7m

The second order benefits included in the cost-benefit analysis of the proposal are summarised in Figure 8.4 below:

Improved hedging between market makers

Greater use of hedging does not, in itself, represent a net benefit, given that hedging constitutes simply a transfer of cost from one party to another or from one point in time to another.

Greater use of hedging can, however, provide some benefits within hedge markets by reducing search costs in seeking hedge contracts and reducing transaction costs in negotiating hedge contracts, through greater liquidity aiding price discovery. See other sections below for commentary on reduced search and transaction costs.

Lower search and transaction costs during scheduled maintenance outages

Just as more robust information on future conditions is expected to improve investment as well as operating decisions it should also improve the selection of periods for taking plants out of the market for routine maintenance.

While access to the futures market will enable generators wishing to hedge periods of outages directly and anonymously, it will also deliver dynamic efficiencies as market making generators come up the experience curve. Specifically these benefits are reduced search costs in seeking hedge contracts and reducing transaction costs in negotiating hedge contracts, through greater liquidity aiding price discovery.

Our approach assumes that about 25% to 40% of the current generation fleet is taken out for maintenance for an average of two weeks per annum. A small $2.50/MWh (approximately 1.25% of average electricity spot price) benefit has been prescribed to this volume and duration to reflect the improvement in transparency, reduced search and transaction costs.

Reduction in average retail price as new retailers compete for contestable business

A more robust hedge market is expected to facilitate entry into retailing by new participants and the expansion of market share by existing parties. It would also increase the threat of entry or expansion.

In total, these effects will support greater rivalry among retailers, putting downward pressure on retail costs and prices, and enhancing incentives for retailers to pursue innovations of value to customers. Even very modest gains in these areas can lead to material economic benefits because of the large size of the market.

Our modeling included only 30% of contestable consumers and have (based on feedback from industry) assumed almost complete contract churn (i.e. duration of hedge contract before repricing event) which provides an almost immediate opportunity to demonstrate efficiency gains.

Type Frequency Low Case Mid Case High Case

Lower search and transaction costs for fuel procurement

Ongoing$0.1/MWh for 25% of plant

per annum.$2.2m

$0.1/MWh for 33% of plant per annum.

$2.9m

$0.1/MWh for 40% of plant per annum.

$3.5m

Stronger incentives on generators to invest in fit for purpose

generation plant

Year 1-5Year 6-10

$0.25m$8.5m

$0.4m$12.8m

$0.5m$17m

Figure 8.4: CBA Second Order Benefits Matrix

Type Frequency Low Case Mid Case High Case

Product innovation to consumers due to increased retail competition

and access to hedge marketsOngoing

Reduction in delivered cost of energy by $1/MWh for 10%

of contestable consumers.$1.9m

Reduction in delivered cost of energy by $3/MWh for 10% of contestable consumers.$5.8m

Reduction in delivered cost of energy by $5/MWh for 10% of contestable consumers.$9.7m

Improved demand-side investment decisions

Ongoing Transfer between market participants and/or consumers - no net benefits.Transfer between market participants and/or consumers - no net benefits.Transfer between market participants and/or consumers - no net benefits.

Improved market price signaling and long run responses by non

participating electricity purchasers during tight market conditions.

Ongoing Efficiency benefits of $0.4m Efficiency benefits of $0.6m Efficiency benefits of $0.8m

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Lower search and transaction costs for fuel procurement

The transparency of a forward price curve for electricity provides a new and important tool for the optimisation of fuel procurement. This optimisation process requires decisions by multiple parties and a key indicator guiding their decisions is the forward price curve, since this provides information on the expected value of discretionary fuel resources in different periods. Importantly, the forward contracts cover quarterly periods, meaning that they can reflect seasonal influences which are a source of uncertainty.

Improved information about future conditions should allow better decision making, and reduce the real cost of holding excessive or deficient fuel stocks. Excessive fuel stocks will lead to higher holding costs for thermal fuel. Deficient fuel stocks will lead to higher costs of acquisition and/or costs associated with increased conservation. The benefit of improved decisions is expected to be related to the size of the swing in fuel use.

The transitions from fuel oil, to pipeline natural gas, to liquefied natural gas and beyond are all events that would benefit from forward price transparency and price discovery. The dynamic efficiency gains from better market co-ordination through competitive pricing over these large structural market changes have been assessed as a small single one-off benefit in 2013. This value would have been considerably higher if the futures market was already in operation or if Singapore in the future chooses to go through another step change in fuel types and associated cost.

Stronger incentives on generators to invest in fit for purpose generation plant

More robust information on future conditions is expected to improve investment as well as operating decisions. In the generation context this has been modeled by estimating the value of investment that occurs each year, and then considering the effect of modest improvements in investment efficiency.

Electricity demand is expected to grow on average by around 3-4% per annum. Investment over the next ten years is expected to meet demand growth and maintain existing security margins. Whilst a significant portion of this investment has already been committed, we expect that half of this new investment will occur in the second half of the ten year horizon. In addition, investment will be required to refurbish existing plant, offset plant retirements and maintain a margin of spare capacity relative to demand. These additional components are assumed to equate to 50% of total new investment.

The timing of this investment is very important. Premature investment means that generation resources will tend to be under-utilised, resulting in a loss relative to the alternative uses of capital from a wider economic perspective. Alternatively, delayed investment will result in higher costs in the form of greater use of relatively more expensive ‘reserve’ generation sources or (in the extreme) an increased risk of forced demand curtailment.

Investment decisions are made by multiple parties and the forward price curve is an important influence on these decisions. Narrowing the range of uncertainty about future prices would help to optimise these decisions. A 0.5% to 1% reduction in average investment costs would equate to benefits of $8.5 million to $17 million per year once new, non-committed generation is being invested. Investment gains are likely to crystallise more slowly than benefits in an operational context. These benefits are therefore modeled as being phased in over a ten year time frame. When discounted at 10%, these annual gains equate to $24 million - $48 million in present value terms.

Product Innovation to consumers due to increased retail competition and access to hedge markets

The dynamic efficiency gains from the introduction of a fixed volume hedging based market provides the opportunity for retailers to package products different to the those traditionally provided to contestable customers.

The ability to offer longer term contracts (three years under the Preferred Solution) coupled with the ability to structure fixed price fixed volume hedging arrangements would further stimulate both retail market competition and product innovation.

An example could be extended, with the retailer smoothing out the variances in demand over a year and offering a product which provides customers a regular payment amount each month. We have referenced a number of examples of this simple retail product (and more advanced examples) across New Zealand, Australia and the United Kingdom30. Interestingly, there is a trend towards more tailored products based around smart metering assets.

Improved demand side investment decisions

More robust information on future conditions is also expected to improve investment decisions for demand side participants. As with the operating decisions, the gains are expected to be concentrated in those sectors where electricity is a significant proportion of total costs.

Improved market price signaling and long run responses by non participating electricity purchasers during tight market conditions.

Generators are not the only parties seeking to optimise their operations in light of uncertainty about future conditions. Demand side parties also face uncertainty and need to make plans and commitments that can be costly to change. For example, a large commercial user might need to implement an extended shut down to carry out a plant upgrade or major maintenance. If electricity is a major business input, the timing of the shutdown could have material influence on its costs. Likewise, an electricity user might have an opportunity to fulfil an additional production order, but needs information on future electricity costs to determine whether it should commit to the order.

It is difficult to estimate the demand-side gain that could arise from improved forward price information because there is relatively little data available on the issue in the public domain. Demand side management itself is relatively undeveloped in Singapore and is a complementary work stream by the Authority. Although electricity is a vital input into almost all activities undertaken within the economy, the gains are likely to be concentrated in those sectors where electricity is a major component of total costs.

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8.4 Quantitative Net Benefits

We have completed the following quantitative assessment of net benefits in the following matrix. These results are conservative (i.e. costs estimated to be on the high side, while benefits estimated to be conservative) and provide an option based assessment of minimum levels of expected benefits rather than an expected case. The net benefits are certainly significant enough to justify the associated costs.

The inclusion of FSC costs naturally reduces the net benefit of the introduction of a market maker arrangement. The following table Figure 8.5 provides this detail.

8.5 Benefits – Barrier Based Analysis

As with the Sensitivity Based Analysis, six types of benefit are to be reaped from the introduction of a traded futures market with market makers. The following quantitative assessment of net benefits has been assessed primarily through a barrier based approach with results provided in the following table. The high cost scenario (i,e, conservative approach) is used, and benefits are progressively scaled across each of the elements to provide a ten year net benefit (based on a 10% discount rate) in the range of $0.25m and $0.50m.

The Barrier Based Analysis shows that the required changes for all elements are well within the estimated changes under the Sensitivity Based Analysis. This further illustrates the low barrier (costs), relative to the benefits of developing a futures market in Singapore.

To assess the barrier including the present value of the FSC we have followed the same approach and detailed the result of a ten year net benefit (based on a 10% discount rate) of $0.25m to $0.50m in the following table.

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Figure 8.5: CBA Net Benefit Matrix – Without FSC Costs

Net Benefit (NPV S$)

Low Cost Med Cost High Cost

Low Benefit $70.5m $69.5m $65.9m

Med Benefit $127.6m $126.4m $122.9m

High Benefit $194.0m $192.8m $189.3m

Figure 8.6: CBA Net Benefit Matrix – With FSC Costs

Net Benefit (NPV S$)

Low Cost Med Cost High Cost

Low Benefit $20.5m $19.5m $15.9m

Med Benefit $77.6m $76.4m $72.9m

High Benefit $144.0m $142.8m $139.3m

Figure 8.7: CBA Net Benefit Matrix – Barrier Approach without FSC Costs

Net Benefit (NPV S$) Combined Change

Lower search and transaction costs during scheduled maintenance outages

$2.50/MWh for 0.25% of plant out for 14 days per annum. (Previously 25% of Plant)

Reduction in average retail price as new retailers compete for contestable business

$0.5/MWh reduction for 0.30% of contestable consumers. (Previously 30% of contestable consumers)

Lower search and transaction costs for fuel procurement $0.1/MWh for 0.25% of plant per annum. (Previously 25% of plant)

Stronger incentives on generators to invest in fit for purpose generation plant

A reduction to 20% of the previous low case benefits

Product innovation to consumers due to increased retail competition and access to hedge markets

Reduction in delivered cost of energy by $1/MWh for 0.50% of contestable consumers. (Previously 10% of contestable consumers)

Improved market price signaling and long run responses by non participating electricity purchasers during tight market conditions.

Efficiency benefits reduced to 25% (Reduction from $0.4m to $0.1m)

8.6 Qualitative Benefits

The benefits derived from improved hedging between market participants have been correctly characterised in the above sections as a wealth transfer between generators and consumers and therefore has not been quantitatively included in the cost benefit analysis.

As an example we have calculated the wealth transfer of more efficient plant as there is currently a significant amount of under-utilised CCGT capacity in Singapore. In 2011 the capacity factor of CCGT plant net of outages was about 70%. Through increased contracting among participants, if this capacity factor could be increased by a mere 1% of the available capacity, the cost of this generation (480GWh) would decrease by $12.3m as more expensive plant is displaced.

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Figure 8.8: CBA Net Benefit Matrix – Barrier Approach with FSC Costs

Increased capacity factor of CCGT plant displacing more expensive generation.Increased capacity factor of CCGT plant displacing more expensive generation.Increased capacity factor of CCGT plant displacing more expensive generation.

Capacity factor net of outages increasing by 1% with $3/GJ fuel spread.

Capacity factor net of outages increasing by 2% with $2/GJ fuel spread.

Capacity factor net of outages increasing by 3% with $1/GJ fuel spread.

$7.5m per annum or a 10 year 10% NPV of $53.6m

$24.7m per annum or a 10 year 10% NPV of $176.5m

$51.2m per annum or a 10 year 10% NPV of $365.8m

Net Benefit (NPV S$) Combined Change

Lower search and transaction costs during scheduled maintenance outages

$2.50/MWh for 20% of Plant out for 14 days per annum. (Previously 25% of plant)

Reduction in average retail price as new retailers compete for contestable business

$0.5/MWh reduction for 25% of contestable consumers. (Previously 30% of contestable consumers)

Lower search and transaction costs for fuel procurement $0.1/MWh for 20% of plant per annum. (Previously 25% of plant)

Stronger incentives on generators to invest in fit for purpose generation plant

A reduction to 80% of the previous low case benefits

Product innovation to consumers due to increased retail competition and access to hedge markets

Reduction in delivered cost of energy by $1/MWh for 7% of contestable consumers. (Previously 10% of contestable consumers)

Improved market price signaling and long run responses by non participating electricity purchasers during tight market conditions.

Efficiency benefits reduced by 50% (Reduction from $0.4m to $0.2m)

Figure 8.9: Wealth Transfer Example

9. Market Infrastructure

9.1 Introduction

As the proposed solution calls for an exchange traded futures contract, there will obviously be a need to create the required exchange infrastructure in order to have the contracts listed and traded. Whilst we do not attempt to describe the means by which an exchange will do this, we do propose some criteria that an exchange should meet in order to give a high probability of success of the contract.

Furthermore, there will be a need to further develop the current market infrastructure in order to facilitate orderly trading. These infrastructure developments will cover current market participants as well as service providers. We explore the necessary infrastructure below.

9.2 Physical Market Information Disclosure

Whilst market information will not replace the proprietary market analysis that trading firms, both physical and financial, must undertake, it is critical that there is no information asymmetry between the current physical players and potential new entrants.

In order to allow for new entrants such as financial institutions to actively trade in the forward market, a review of all physical market information disclosure should be undertaken to ensure that this information is available to all participants and potential participants.

• Outage plans – Outages, scheduled and forced, have a significant impact on forward prices, and should be published where possible to all participants.

• Forecast Demand and Prices – The demand and price information that is used by generators in order to trade in the physical market needs to be easily available to potential participants.

• Physical Offers – It is our understanding that the physical market offers submitted by generators are not currently published. We are of the view that publishing this information would have positive benefits for price discovery in both the physical and forward markets. It is beyond the scope of this paper to enter into a discussion on the cost and benefit of publishing spot market offers, however we will note that if they are not published, there is a slight informational advantage to a generator that can alter its own offers and see the impact on forecast prices, gaining some insight as to the shape of the physical market supply curve that is not available to a non-physical player.

• Fuel Disclosure – Information regarding fuel stockpiles and supply disruption is also critical to the efficient pricing of forward electricity. Again, we stress the need for disclosure on a basis such that non-physical players are not materially disadvantaged.

• Formal notice of LNG and PNG (or blended) Vesting Price changes to formally notified on the MSSL website no less than 10 days before the beginning of a new calendar quarter.

9.3 Exchange Infrastructure

We have proposed a futures contract as our preferred solution in part due to the fact that the product will be centrally cleared and traded through an exchange. In the interests of concentrating liquidity, at least in the early stages of trading, it would be sensible to have all market makers operating on one exchange. Whilst any exchange could list a futures contract that settles against the USEP, in order to facilitate a market environment that will encourage new entrant participation the exchange through which market making takes place must meet certain criteria. We would expect that any exchange that the EMA was to gazette for market making must obviously be of reputable standing such that it would be worthy of EMA endorsement. For market makers to receive the benefit of the FSC, market maker arrangements should be required to be conducted on an exchange, or exchanges, that have the endorsement of EMA. Furthermore, the clearing participants of this exchange would need to be reputable in order to instill confidence in the creditworthiness of exchange traded products.

Ideally any exchange will have existing energy products listed or at least planned, which will complement any electricity derivative. We see HSFO products initially providing a lot of synergy with electricity, but over time as fuel price indices vary, we expect products that are more closely linked to gas prices would be an invaluable addition – especially in the event that gas moves to a new (i.e. non oil) based pricing basis.

The exchange must be using industry standard techniques for the calculation of margins and these margins must be netted for individual participants across relevant commodities. This is necessary to minimise additional cost of entry to existing exchange participants, and also to ensure efficient use of capital where participants are taking cross commodity positions. These benefits will then help to encourage the concentration of liquidity.

The exchange and its clearing participants must have a global presence in order to facilitate ease of access to international participants, as well as ensuring that the exchange is able to engage in promotion and education around the new products on a global basis.

Finally, the exchange must be able to display an understanding of the issues and challenges, and methods by which these may be overcome, in the development of electricity derivatives in the Singaporean context.

9.3.1 Options to Select an Exchange

In the interests of concentrating liquidity, at least in the early stages of trading, it would be sensible to have all market makers operating on one exchange. Whilst any exchange could list a futures contract that settles against the USEP, in order to facilitate a market environment that will encourage participation of new entrants, the exchange through which market making takes place must meet certain criteria. We would expect that any exchange that the industry or EMA was to gazette for market making must obviously be of reputable standing. For market makers to reap the benefits of the proposed FSC, market making arrangements should be conducted on an appropriate exchange that is collectively selected by the generators or is endorsed by EMA. Furthermore, the clearing participants of this exchange would need to be reputable in order to instill confidence in the creditworthiness of exchange traded products.

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An appropriate exchange can be selected organically by the industry or explicitly by the regulator – (i) an industry preferred / selected exchange, or (ii) an EMA endorsed exchange. The market based approach is clearly inclined to the first option of an industry selected exchange is preferred.

We recommend EMA to allow the generators to work with the exchange to develop the futures market on a commercial basis. However, in the event that an industry preferred exchange is not selected organically, EMA could opt for an endorsement of an appropriate exchange according to preset qualifying criteria.

9.4 Market Maker Infrastructure

It is our view that given the capability of the generators in regards to fuel trading, the addition of an electricity trading/market making function should not be overly cumbersome. However, we do recognise that there are requirements to build the capabilities outlined below.

• Front Office – All market making firms will need a trading function with direct market access, either through a clearing or executing broker. Traders will need delegated authority to trade, including the ability to take positions where necessary. It is likely that this trading capability will need to be integrated with the current spot, fuel and foreign exchange (FX) trading functions.

• Middle Office – Appropriate position keeping and reporting systems will need to be put in place. Again, we expect that generators currently have these systems and that with minimal adaptation they will be suitable for futures products. Given the cash-flow implications of traded futures products, we expect that generators will give due consideration to developing their risk monitoring and reporting systems.

• Back Office – A benefit of using exchange traded products is the ease of settlement. Although slightly different, we expect that the back office requirements for a futures trading function will be far less than the current requirements for trading OTC fuel and fuel derivatives. This settlement system will need to be developed.

• Governance – Of critical importance to all participants will be the development of appropriate policy and procedures. Such policy will no doubt include mandate to trade, process design which ensures appropriate oversight and separation of duties, risk limits and breach reporting processes. The development of appropriate policy and process may require board input in the case of some participants and recognition should be made of the time frames required for the development of this infrastructure within the various organisations.

• Education and Training – Across all of the areas above there will currently be a lack of knowledge of futures products and market making strategies. This knowledge, as well as that regarding the opportunities for integrating futures products with the wider portfolio will need to be built by participants.

Figure 9.1: Trading Organisational Chart

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9.4.1 Physical Participant Portfolio Integration

Given time to develop liquidity, the futures market will essentially become another channel through which generators can sell and retailers can buy. This is a considerable change from the current situation whereby virtually all retail sales are simply an internal transfer within the physical participants. This change will provide the opportunity for participants to manage their portfolios in new ways. By instilling a more active trading culture across the industry, there will also be greater opportunity for inter-generator hedging at competitive prices. Participants will need to be cognisant of, and develop strategies to capitalise on these changes to the market.

9.4.2 Implementation for the Retail Market

As noted above, the current retailers will soon have another channel through which to buy hedge products. We should see that over time, there will be change to the retail market shares such that they are not so reflective of a retailer’s generation market share. This change will occur through competition as those retailers able to profitably acquire more customers at a given futures price will be able to do so without the constraint of their physical generation capabilities.

Retail organisations will need to be aware of how futures can be used within their portfolio, and develop the necessary infrastructure to manage positions and risk limits with regards to futures. Again, we do not see this as additional infrastructure in that retailers must currently capture and manage their hedge positions

By creating an alternative to the use of physical assets to manage risk, it becomes far more likely that new entrants will enter the retail market. Obviously this will create a change from the current market dynamic where a generator’s market share is the primary driver of its retail market share.

9.5 Implications for the Spot Market

Whilst we do not see any specific need for infrastructure developments within the spot market other than the need for consistent information disclosure as noted above, we do see some long term impacts on the market dynamic. The most likely initial effect on the spot market is a greater incentive for the market to run the generation fleet (and large consumption) in a more strict merit order.

If we see retailers purchasing volume through the futures market, we can draw the conclusion that they are buying this volume off the least cost generators with generation to hedge. If the futures price was greater than the cost of generation, we would expect generators to be willing to sell, rather than take spot price risk. So, whilst the most efficient retailers will be applying upward pressure to the market, this should be offset by downward pressure (and consequently sales) by the most efficient generators. If we take this behavior to the limit, we will see that efficient generation will be contracted ahead of less efficient generation, incentivising efficient generation to run in the spot market, and removing the need for less efficient plant to run (out of merit order) to cover contract.

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10. End Notes

1 www.electricitycontract.co.nz

2 Refer to the Australian Financial Markets Association – electricity Price Curve – available at http://www.afma.com.au/afmawr/_assets/main/lib90011/elec_extract%20new%20format%20for%20afma%20website.pdf

3 Naturally this cannot be fully validated without access to the generators fuel contracts.

4 See Polimenis, V, 2005, A Realistic Model Of Market Liquidity And Depth, Journal of Futures Markets, Vol. 25, No. 5, pp. 443–464.

5 Mark Governor Kevin Warsh, 5 March 2007, At the Institute of International Bankers Annual Washington Conference, Washington, D.C., , http://www.federalreserve.gov/newsevents/speech/warsh20070305a.htm.

6 Mark For example the use of a requirement that a minimum symmetrical volume of bids and offers is delivered within a mandated bid offer spread.

7 Of the 7,542 contestable customers in December 2011, 28% were serviced by SPS under the MSSL. Source: EMA Website, as at May 2012.

8 Energy Market Authority Of Singapore Act (Chapter 92b), Part 3, Section 6(1)a

9 Source: Electronic Broking Services (EBS)

10 There is no industry standard ISDA documentation to govern inter-generator transactions.

11 The prevalence of fuel pass through contracts / indexed fuel contracts and fixed price variable volume contracts being provided to the contestable consumer are examples of this phenomena.

12 Refer to www.electricitycontract.co.nz.

13 Refer to the Australian Financial Markets Association – Electricity Price Curve – available at http://www.afma.com.au/afmawr/_assets/main/lib90011/elec_extract%20new%20format%20for%20afma%20website.pdf

14 See Section 5.5

15 Mark Refer to www.nymex.com.

16 Bradford G. Leach, Director, Energy Research and Product Development CME Group, 24 October 2011, APEx Conference 2011, Rio De Janeiro, pp. 9.

17 OFGEM, GB Wholesale Market Liquidity: 2011 Summer Assessment. June 2011.

18 Dr Juan J Alba , Power Market and Trading, Director, Regulatory Affairs, Endesa, September 2006.

19 Source: ASX

20 www.med.govt.nz

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10. End Notes

21 An alternative of PNG (one-time option) may be considered by EMA.

22 1 unit contract is equivalent to 0.5MW.

23 The 13.5 MW limit is based upon the largest three generators providing on average 3MW per side and the remaining three or four generators providing on average half that amount.

24 0.6% of average total forecasted electricity demand.

25 Mark These numbers have been rounded to the nearest whole percent.

26 An alternative of non LNG Vesting (one-time option) may be considered by EMA.

27 Although more efficient hedging markets can also reduce search and contracting costs, which is a direct resource saving. These effects have not been quantified for this analysis.

28 Assuming a 10% reduction in spot price of $20/MWh and a forecasted electricity demand of 47GWh, the cost of the FSC is estimated to be $47 mil (5%*47,000,000*20).

29 The assumed average contestable customer contract duration is 12 months.

30

The following links relate to the ‘smooth bill’ product or more advanced retail products.http://www.empower.co.nz/files/EMP_Smoothpay.pdfhttp://www.contactenergy.co.nz/web/findoutabout/smoothpayhttp://www.genesisenergy.co.nz/genesis/index.cfm?2336AE81-C09F-4299-6D7A-2ECB901278E7http://www.agl.com.au/Downloads/071228_AGL-Direct-Debit-bill-smoothing-Online-TC_Retail_%20Terms-Conditions_Page-Direct-Debit-%20Bill-Smoothing.pdfhttp://www.scottishpower.co.uk/pdf/201212_CappedPricev1.pdfhttps://meridian.custhelp.com/app/answers/detail/a_id/1/~/how-does-levelpay%E2%AE-work%3F

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A.1 Glossary

Actively Traded: Any commodity for which a buyer and seller can be found in a relatively short time frame.

Arbitrage: The simultaneous entering into offsetting transactions that completely eliminate market price risk and locking in either an immediate riskless profit at no cost today or a return on investment greater than the risk-free rate.

Ask (also known as Offer): The lowest price at which a participant will sell an asset or product.

Basis: The difference between any two prices for a commodity or commodities at different time periods, locations, product forms, or qualities. For example, the differential that exists between the cash or spot price of a given commodity and the price of the nearest futures contract for the same (or related) commodity. The cash price minus the futures price equals the basis.

Basis Risk: The risk that the value of a contract will not move in line with that of the underlying exposure. Basis differentials are generally due to differences in geography (nodes), quality, delivery, time, and options valuations.

Bid: The highest price at which a participant will buy an asset or product.

Bid-Offer Spread: The difference between what buyers are willing to pay and what sellers are asking for in terms of price.

Call Option: An option contract that gives the option purchaser the right, but not the obligation, to purchase an underlying asset at a specified price at/during a specified period of time.

Cap: A supply contract between a buyer and a seller whereby the buyer is assured that he or she will not have to pay more than a given maximum price. This type of contract is analogous to a call option.

Clearing House: An agency or separate corporation of a futures exchange responsible for settling trading accounts, clearing trades, collecting and maintaining margin monies, regulating delivery and reporting trading data. Clearing houses act as third parties to all futures and options contracts - as a buyer to every clearing member seller and a seller to every clearing member buyer.

Contract for Differences (CfD): An arrangement made in a forward contract whereby differences in settlement are made through cash payments, rather than the delivery of physical goods or securities.

Derivative: A financial instrument, traded on or off an exchange, the price of which is directly dependent upon (i.e., derived from) the value of one or more underlying securities, equity indices, debt instruments, commodities, other derivative instruments, or any agreed-on pricing index or arrangement.

Financial Institution (FI): A financial services business including commercial banks, investment banks, brokers and investment managers.

Fixed Price Fixed Volume (FPFV): See CfD.

Fixed Price Variable Volume (FPVV): A financial or physical contract whereby a fixed price is paid for all volume regardless of the amount of volume supplied/consumed.

Floor: A supply contract between a buyer and a seller of a commodity whereby the seller is assured that he/she will receive at least some minimum price. This type of contract is analogous to a put option, which gives the holder the right to sell the underlying commodity at a predetermined price.

Forward Contract: A contract between a buyer and a seller whereby the buyer is obligated to take delivery and the seller is obligated to make delivery of a fixed amount of a commodity at a predetermined price on a specified future date. Payment in full is due at the time of delivery.

Forward Price Curve: Graphical depiction of the future value of one commodity and one location over time. The curve can be based on information from third party and/or exchange settled price quotes for large, liquid markets; models for illiquid markets with little or no external quotes; or interpolated markets where some third party data exists.

Fungibility: The characteristic of interchangeability. Futures contracts for the same commodity and delivery month are fungible because of their standardized specifications for quality, quantity, delivery date, and delivery locations.

Futures Contract: A contract, usually exchange traded, between a buyer and a seller whereby the buyer is obligated to take cash delivery and the seller is obligated to make cash delivery of a fixed amount of a commodity at a predetermined price on a specified future date. All profits and losses are realized immediately and result in a cash credit or debit based on daily changes in the settlement price of the contract.

Historic Volatility: Volatility estimated from historical data.

Holding Period: A time interval or horizon over which the variability in the value of a portfolio or estimated earnings from an economic activity is assessed.

High Sulfur Fuel Oil (HSFO): High sulfur fuel oil is a feedstock for power stations in Singapore.

Implied Volatility: The uncertainty of future price movements as implied by an option price observed in the market.

55

A.1 Glossary

International Swaps and Derivatives Association (ISDA): is a trade organization of participants in the market for over-the-counter derivatives. It is headquartered in New York, and has created a standardized contract (the ISDA Master Agreement) to enter into derivatives transactions.

Liquefied Natural Gas (LNG): Consists mostly of methane and is cooled to approximately -160 degrees Celsius and is a feedstock for power stations in Singapore.

Market Risk: Potential fluctuations in prices, volumes exchanged, and market rules that may affect a company’s buying and selling activities. Usually, this is composed of:

Price Risk: Potential fluctuations in prices of the underlying energy commodity.

Credit Risk: Potential adverse occurrence of a counterparty’s ability to pay its obligations.

Volumetric Risk: The risk that commodity volumes will vary from expected volumes and result in a potential loss due to changing commodity market prices. For example, a generating unit sells projected electric generation production forward and at the time of delivery a unit is forced out and cannot deliver. This results in a loss if the price to purchase electricity to cover the sales is higher than the electricity sale price.

Mark-to-Market (MTM): The value of a financial instrument (or a portfolio of such instruments) at current market rates or prices of the underlying.

Mark-to-Model (MTMO): The value of a financial instrument (or a portfolio of such instruments) using, in addition to available prices of the underlying commodities, approved models for developing both the prices of the underlying commodities where the prices are not readily observable in the marketplace and the valuation and risk metrics of the instruments themselves where the instruments are complex combinations of standard products.

Monetary Authority of Singapore (MAS): The primary government agency responsible for the regulation of the financial services industry including Singaporean financial markets.

Notional: The principal amount used to calculate payments in a derivative instrument. The principal is notional because it is neither paid nor received.

Operational Risk: The risk of direct or indirect loss resulting from inadequate or failed internal processes, people, and systems or from external events.

Option: A contract between two parties that gives the option buyer a right, but not the obligation, to purchase or to sell an underlying asset at a specified price or during a specified period of time.

Over-the-Counter (OTC): A security which is not traded on an exchange, usually due to an inability to meet listing requirements. For such securities, broker/dealers negotiate directly with one another.

Pipe Natural Gas (PNG): Consists mostly of methane piped from neighbouring countries to Singapore and is a feedstock for power stations in Singapore.

Power System Operator (PSO): The Power System Operator is a Division of the EMA and is responsible for the secure supply of electricity to consumers and operation of the transmission system.

Put Option: An option contract that gives the option purchaser the right, but not the obligation, to sell an underlying asset at a specified price or during a specified period of time.

SP Services (SPS): Provides integrated customer services for electricity, water and piped gas supplies in Singapore. It is the Market Support Services Licensee (MSSL) that provides meter reading services, manages meter data, facilitates customer registration and transfer between retailers, serves as a conduit to buy electricity from the wholesale electricity market on behalf of retailers or contestable consumers, provide electricity at published tariffs for residential and small businesses (i.e. non-contestable consumers).

Spark Spread: The difference between the price of electricity sold by a generator and the price (cost) of the fuel used to generate it, adjusted for equivalent units.

Strike: The set price at which a position will be established or cash settlement made if the buyer exercises the option.

Swap (also known as a Contract for Differences): A bilateral contract between two counterparties to exchange cash flows in the future according to a prearranged/contracted formula. A swap can therefore be regarded as a portfolio of forward contracts.

Swaption: An option on Swap.

The Market Operator and/or the Energy Market Company (EMC): The company that operates and administers the wholesale markets.

Tenor: Time to maturity of an asset, liability, trade, transaction, or portfolio.

56

A.1 Glossary

Tolling Arrangement: An agreement between a power buyer and a power generator in which the buyer supplies the fuel and receives an amount of power generated based on an assumed heat rate.

Uniform Singapore Energy Price (USEP): A weighted-average of the nodal prices at all off-take nodes used for retail or off-take contracts and or as a reference price.

Value of Lost Load (VoLL): The estimated amount that customers receiving electricity with firm contracts would be willing to pay to avoid a disruption in their electricity service.

Value at Risk (VaR): Value at risk of a position or a portfolio is defined as the loss or change in value that is not expected to be exceeded with a given degree of confidence over a time period of interest called the holding period. VaR is therefore a statistical measure of variability in the value of a portfolio of positions or earnings from economic activity arising from the changes in the market prices of the commodities or other variables underlying the portfolio or activity.

Volatility: A measure of the degree of the fluctuation in the price of an instrument.

57

A.2 Parties Interviewed During Analysis

We appreciate the generous assistance provided by the following organisations during the course of our study:

58

Party Organisation Type Meeting Type

GMR Energy Generator / Retailer Industry meeting / One-on-one session

Keppel Merlimau Cogen / Keppel Electric Generator / Retailer Industry meeting / One-on-one session

Power Seraya / Seraya Energy Generator / Retailer Industry meeting / One-on-one session

Sembcorp Energy / Sembcorp Energy Supply Generator / Retailer Industry meeting / One-on-one session

Senoko Energy/ Senoko Energy Supply Generator / Retailer Industry meeting / One-on-one session

Tuas Power Generation / Tuas Power Supply Generator / Retailer Industry meeting / One-on-one session

Tuaspring Generator Industry meeting / One-on-one session

Diamond Energy Ltd Retailer Industry meeting / One-on-one session

Energy Market Company Market operator Industry meeting / One-on-one session

Singapore Power Services Market Support Services Licensee Industry meeting / One-on-one session

Shell Eastern Petroleum Ltd Consumer / Embedded Generator One-on-one session

Exxon Mobil Ltd Consumer / Embedded Generator One-on-one session

Singapore Exchange (SGX) Exchange One-on-one session

Singapore Mercantile Exchange (SMX) Exchange One-on-one session

BNP Paribas Financial Institution One-on-one session

Deutsche Bank Financial Institution Teleconference

ANZ Financial Institution Teleconference

Noble Group Ltd Financial Institution Teleconference

Monetary Authority of Singapore (MAS) Government agency / Regulator Inter-agency meeting / One-on-one session

Ministry of Trade and Industry (MTI) Government agency / Regulator Inter-agency meeting / One-on-one session

International Enterprise Singapore (IE Singapore) Government agency / Regulator Inter-agency meeting

Cybele Capital LimitedP O Box 12-8077RemueraAuckland 1541New Zealand

www.cybelecapital.com