Will the contents of a new framework for developing market reforms in Brazil lead the hydro-dominated electricity supply industry to successfully create a commodities market, or turn it into a 'dead man walking'?
In the late 1990’s Brazil took steps to reform, liberalise and privatise its Electricity Supply Industry (BESI) achieving some success so far. Experience has shown countries that have embraced those market reforms shared a common necessity – a need for capital to invest or make the industry more competitive with impacts on prices. The challenges faced by those countries for over 12-15 years should not be underestimated: rebuilding sustainable commercial and legal frameworks are laborious tasks requiring negotiations-improvements for a considerable length of time. The BESI electricity market reform and privatisation happened at different time, scope and pace. Its structure is fractioned in terms of degree of integration and ownership which is split into Federal, State and Investor Owned Utilities (IOU). Privatisation of some Distribution Utilities occurred prior to the 97 market reforms completion and enactment – this per se created additional tensions among state owned companies, however.
The 97 structure comprises a regulator (ANEEL), a market “Pool” (MAE), an Independent System Operator (ONS), several bilateral contracts, transitional arrangements and externalised the Energy Reallocation Mechanism (MRE). Contracts negotiated into the MAE comprise Initial Contracts, Itaipu, Electricity Imports, MRE for secured-energy and plants with special rights defined by ANEEL. Further details about these entities and procedures can be found in websites supported by ANEEL, MAE and ONS.
The ultimate goal of those market reforms was the creation of “New Market” rules, the engine if well designed and implemented, would be able to attract investors and provide long term sustainability for the industry. In addition it was an attempt to sustain electricity price at attractive levels, price observability, liquid contracts trading, hedging and stability of market principles. Currently electricity prices are “formed” and contracts settled as follows (see Fig. 1):
• Prices are determined on a weekly, monthly and year-ahead for four regional markets (North, Northeast, South, Southeast-Mid-West “submarkets”). ONS calculate and inform System Marginal Operating Costs (CMO) from Central Despatch daily perspective. “Power shortage” cost is used to expand/dispatch plant and provide signals about market tightness. This procedure has clear implication on forward prices.
• Contracts are settled at the end of each period with positions closed out based on final prices. MAE recalculates ONS’ procedures with ex-post data using the same tools – NEWAVE (Month/Year ahead) and DECOMP (week ahead).
• Additional levies (ESS) are added to the final price aimed at maintaining system reliability and is shared by market participants in the interconnected system. It comprises operating restrictions (amount of energy available to a participant cannot be dispatched) and penalty charges for lack of metering.
For monthly dispatch scheduling, NEWAVE considers the amount of water stored in system at the beginning of each period (month) and future rivers flow simulations (2000 series), operating restrictions and transmissions capacity availability to determine the month-ahead price (quasi-forward). This procedure has been developed and improved for over 20 years and is regarded a world-class approach. For weekly dispatch, DECOMP optimises the scheduling for calculating weekly prices (see in Fig 2).
The MAE acts as a quasi-exchange and quasi-clearing house. Settlement prices are not derived from traded contracts – it results from short-term auctions and known tariffs for long term contracts. Prices are determined for three load curve levels: peak, intermediate and off-peak. The MAE cannot novate contracts as an exchange.
Contracts clearing has a detailed routine for settling the MRE between generators based on the ‘secured-energy’ principle. Hydro power generators are entitled to trade electricity at pre-determined amount of energy (MW-YEAR) defined during the Planning Studies, confirmed by ANEEL and key component of a hydro power asset tender. If during the dispatch, a generator position is different from the secured-energy threshold, then the MRE applies. Those generators whose dispatched electricity was below the available capacity (secured-energy) will receive the equivalent energy up to the secured-energy threshold and on a pro-rata basis. This procedure is an incomplete balancing mechanism with bias towards the physical book – out of balance positions are minimised by the electricity dispatcher.
Market participants (generators) are entitled to buy and sell water at R$4/MWH as defined by ANEEL – no spread is allowed in this trade. All available energy above the secured-level (e.g. secondary energy, common in the event of above-expectations rain season) is sold at the same price. Generators are entitled to freely sell secondary energy subject to regulatory approval. No generator can sell above the secured-energy threshold without being authorised by ANEEL. Additional revenues from electricity generated/transferred surplus between regional markets and importers are shared on a pro-rata basis. Contractual prices have been capped at R$72.35/MWH and spot at R$49.26/MWH during the 2001/02 power shortage.
To date there are circa 147 market participants, an acceptable measure of its success. Although Brazil has world-class skills and capabilities in building and operating a hydro-based industry, its current electricity market required further improvements to rival its operating skills. A new attempt was disclosed in December 2003.
Market reform proposals
The government has singled out lack of investments, electricity price volatility and incomplete market liberalisation as causes for the Electricity Industry malfunctioning and under-achievements. The December 2003 proposal unveiled some major intentions to tackle these issues:
• Efficient electricity contracting: improve the tender process for new power projects and auctioning aggregated demand contracts via a new quasi-exchange – CCEE (former MAE).
• Security of supply: ensure that 100% of demand is contracted at all times, benefiting from a combined increased reliability of hydro and thermal plants without increased cold reserve costs.
• Low cost electricity for all market segments: the MME expects lower prices will result from effective combination of efficient contracting and security of supply policy guided by least cost criteria to achieve low cost electricity (tariff).
Those guidelines uncovered a two-fold initiative as effective means to further develop the industry: vesting an obligation to sell into the pool and clarity in planning/tendering/monitoring construction of power plants. Four new features are introduced in the proposed market reform:
• Creation of two electricity markets – regulated and free-market: the regulated market comprises captive customers (below 3MW) supplied by former state Distribution companies. The free market is primarily dominated by large industrials and traders;
• Creation of demand aggregator: the new power exchange entity will aggregate demand from regulated market and will buy electricity on behalf of those agents. It intends to exercise buying power to achieve lower price as well as single price in the exchange;
• Quasi-compulsory sale to the regulated market: generators are entitled to sell electricity into the free-market on the condition that a portion of electricity generated is sold to the regulated market and payment of compensation fee;
• Regulated market compensation fee: generators should pay a fee for sales made outside the regulated market if the price negotiated in the free-market is below the achieved in the former.
No mention is made for improving the balancing mechanism. Existing contracts settlement procedures will remain in force. Free-market customers can switch back to the regulated market depending on its demand requirement (min 3MW) – a notice should be given one to thee years in advance prior to first delivery. Regulated agents could shorten this time at will. Vertical integration (generation, distribution and supply) and self-dealing are forbidden.
In addition to the CCEE, the creation of two new entities has been proposed (Fig 4): EPE, the entity responsible for planning activities similar to those performed by Eletrobras prior to market reforms in 1997; the Monitoring Committee (CMSE) responsible for overseeing security of supply issues within a five year timeframe. No further details have been disclosed about the type of instruments available to CMSE and currently are not in place with major stakeholders namely MME, ANEEL, market participants and BNDES (the national economic development bank).
Tender of new generating plants will be underpinned by a known recipe used in the industry in the past and accepted by commercial and multilateral lenders during the 1970s and 80s: least cost planning and tariff equalisation. Major features of this approach include: asset specific secured-energy certificate – proposed by EPE and issued by ANEEL based on 5% supply deficit probability reliability criteria; list of assets to be tendered and required commissioning date; and a two-window tender calendar – five and three-years ahead – aimed at ensuring sufficient capacity is made available to meet demand and adjusted (three) to demand conditions when approaching commissioning;
Issues and implications
Market reforms could have far more reaching effects in the BESI than anticipated by the reform sponsors – four major themes deserve further analysis: competition and prices, trading environment and power exchange, pre-emptive regulations & price risk management, unbundling supply, vested rights and free-market uncompetitive electricity. Current proposals have adopted a narrow frame for competition: the focus relies exclusively on the tender of generating plants (i.e. secured-energy) and short-term market adjustments auctions. Current beliefs suggest low cost power is achieved by managing the market through pre-emptive price regulations initiatives rather than a combined efficiency of market instruments & regulations – experience has proved the latter approach has prevailed in liberalised markets.
Competition and prices
The proposals miss out at several core components of liberalised markets to become an efficient commodities market (central requirement for sustaining liberalisation):
Traded secured-energy certificates
Secured-energy certificates are the most important and tradable asset created in the hydropower industry which could underpin the required quantum leap forward in terms of evolving the industry.
Those certificates have two major components – dam capacity and power house size. The dam capacity is the key component of hydropower system which could be associated to a appropriate weather index (e.g. amount of rain at pre-defined pricing points), however. The ONS’ calculated CMO could therefore consider that value into the CMO calculations to determine power prices.
The value of water (e.g. fuel) no longer has to be the same for intra and interregional markets therefore replacing a mechanism that does not reflect market conditions as well as is unhedgeable as stands. Effectively, a secondary market for water is created similar to gas – the electricity industry worldwide has considerable experience in managing this kind of risks and spreads.
The industry would benefit from such approach by adding a new ways to hedge out water risks as well as introduce a different kind of derivatives required to manage them. Insurers would be interested in investing in this kind of products as verified in the US and Europe.
Introduction of market forward curve
The ONS’ year-ahead information could form the basis for this forward without bids from market participants it will not represent the market view, however. This forward curve as it stands reflects operational conditions of the system but not market sentiment in terms of gain/loss of returns – this clearly impact on prices, market value of operators and shareholders, usually insurers and pension funds.
Forward prices should include rain expectations/management which is distinct from optimal dispatches and marginal costing procedures. National Meteorology Agency and ANEEL have a track record of continuous improvement in rain metering and forecast. Operators should consider that information to hedge out some positions and reduce losses caused by dry seasons. Loss of revenues during the 2002 power rationing could had been partially offset using this approach in a proper hedging structure. Based on publicly available information it is possible that a new power shortage could arrive around 2007 – what could be done to manage this risk in a efficient fashion – the clock is ticking already.
Trading environment and power exchange
The proposals still maintain a quasi-exchange status of CCEE with a panacea of roles: trader (Demand Aggregator), quasi-exchange and quasi-clearing house. Financial and Commodities markets have long developed a common understanding that trading activity does not fit with exchange roles because of inside information – this can lead to price distortions. Exchanges, by creation, need to be efficient and impartial to sustain credibility as a market place.
The introduction of the contract aggregator – or a cooperative, as defined by the government creates a monopsony de-facto.
This demand aggregator is equivalent to the Single Buyer Model (SBM) advocated by Electricité de France (EdF) as an answer to the EU electricity markets liberalisation directive. The SBM may have a tendency to act inefficiently and be manipulated by the government for national policies purpose3. There is no economic case for restriction of choice implied by the creation of SBM. In addition the costs for running a SBM would be higher than the loss of revenues caused by market liberalisation. This model was later abandoned by EdF which embraced major investments in European liberalised markets.
Market liberalisation experience has shown true market principles adapted to national cultures could provide better results in long run although requiring regulatory guidance to avoid market abuse. As the CCEE runs the auction and settlement this may raise concerns on bias towards the Distribution Companies buying power. Brazilian generating companies – with a mixed ownership (domestic & foreign) structure – may not agree with this kind of procedure on the grounds of unfair trade. Market reforms sponsors may believe tough regulations could tackle those concerns; international experience has proved regulators have not succeeded in this task.
Compulsory contracting of 100% of electricity by distributors and tariff equalisation were major causes for changing the industry structure and commercial procedures in early 90s. Market participants are also still waiting for additional developments in an efficient balancing mechanism.
Creation of a proper power exchange
Electricity is a commodity delivered in different market conditions during a day, month or year. Efficient electricity commodity markets should be able to trade across the whole load curve spectrum. International experience in liberalised electricity industry has provided a vast range of products to be offered to clients in different points of the load curve. These products help market participants to manage risks and make prices hedgeabe via adequate market placement.
Brazil has the knowledge and experience of running the largest exchange in the Americas outside the US – BOVESPA and its futures exchange BM&F. As per NYMEX and UKPX experiences, this technology could be adapted to create an impartial and efficient power exchange. By doing so the market will benefit from a new class of derivatives and hedging instruments developed and made available to the energy industry for at least ten years. The ONS power dispatch is a dispatch schedule, not a price setting exchange. Commercial contracts & transactions associated to that dispatch set the prices through realistic market positions and perceptions. In addition, a weather exchange could also be incorporated. Brazilian regulators should acknowledge all these possibilities to successfully develop and strengthen the industry.
The market could be regulated by three existing entities – ANEEL (electricity), BACEN/MF (financial) and CADE (fair trade). Market abuse could be properly investigated and dealt with supported by primary and secondary legislation which could include price-caps and suspensions. This model has been successfully used in USA (SEC, FERC, CFTC), UK (OFGEM, FSA, OFT) and Germany which is setting up a new electricity regulator independent from the Fair Trade Office. As the proposal stands we can anticipate the demise of trading activity and reduced to load profiling from time to time.
Pre-emptive price regulations
A major reason for triggering the current market rules review was electricity prices volatility. The analysis of data publicly available provided by ONS and MAE reveal that volatility is within/below the range expected for electricity markets – around 15%. This level is compatible with major currencies volatility – US$, GB£, YEN, CHF – and well below oil price vols (40%).
It seems that market reform proposals may rely on a narrow focus on commodity markets regulatory approach – the choice has been just on pre-emptive price regulations a leaving aside the creation of a suitable price risk environment for market participants.
Avoidance of pure pre-emptive price regulation
The tender criteria works as a cap for future deliveries (three to five years ahead). It is unlikely that market conditions remain unchanged for such a long period therefore a different approach for winning the asset tender (lowest bid) and when the plant becomes operational (price band) should be developed. Market abuse clauses should be introduced rather than prohibitions, and dealt with by ANEEL, BACEN/MF and CADE. Further regulatory amendments are required to include the merchant energy business as well as alterations in existing & future licenses (Concession Contracts).
Regulators should guide but avoid doing the work of market participants. In the proposed approach inefficiencies are created in price and behaviour – once financial closure supporting the winner bid is achieved, investors could seat and enjoy project returns – eventually manage/claim FOREX/IR risks or withdrawal from the market if returns are not satisfactory. The government is bearing all risks, except in a dry year – this may not be a sounding approach to market liberalisation and attracting capital for investments. What is at stake is who has the rights to make decisions on hedging or create the best hedging structure – this not the regulators’ task.
The planning process has been brought too close to the market place – there is a risk of becoming part of the market itself but lacking of appropriate market instruments and transparency. Market participants may not be able to influence effectively – the risk of resurgence of former Eletrobras’s GCPS and clashes with ONS is on the radar screen – the industry could loose again. If planning is regarded an important component for the industry make part of it – but separated from an exchange, price regulator and market traders – and working with realistic and acceptable market parameters assumptions.
Finally lower prices come from an increased number of market participants and slight overcapacity bore by the market. Eletrobras still owns major hydro assets in Brazil – this per se becomes one of the most important market instruments available to the government in creating a price management breeding space into a proper exchange.
Price risk management
Pre-emptive price hedging via tender provides little guarantees to market participants because developers are still exposed to currency, interest, fuels and weather risks. No hedging strategy is efficient and/or complete if financial contracts are not in place and traded outside the industry value chain.
Existing data from ONS and MAE suggest two major hedging circumstances could help market participants in offsetting risks: month-ahead price correlation and arbitrage between electricity markets. Initial analysis indicates that implied volatility and price for up to 4 months ahead has high correlation thus hedgeable. This could support a whole approach towards CFDs and derivatives that could easy off pressure on industry revenues. At same time customers – distribution companies and large industrials – would be able to hedge their purchase costs in a more efficient way.
A high degree of price correlation for some markets and diversity to others can be verifiable – it displays an important feature for price risk management. This is per se core feature for arbitrage and price risk management in the commodities market.
If market participants are not able to enter into financial hedging contracts their positions in the BESI and accept current & proposed rules it simply means their electricity market exposures are not hedged. This may not be welcome news for investors, lenders and shareholders for a simple reason – efficient and effective market hedging instruments are not available. As foreign investors could be governed by FAS133 (SEC) and IAS39 there will be very little will to hold positions that could make profit & loss accounts less manageable. If current market reforms proposal is implemented as it stands there may be no other choice than ask the BNDES to pick up the bill and provide required guarantees. When the new Basle II Accord comes into force in 2007/8, the cost of hedging may become prohibitive for the BNDES and less equipped electricity markets.
Unbundling supply activity
Unbundling the supply business from distribution is a welcome initiative but preventing self-dealing between generators and marketers may act as the nemesis for investors. It’s been clear in market liberalisation that distribution activity falls in the infrastructure investment category with extensive regulatory experience. Not all liberalised markets follow this rule but there is an ongoing movement towards that direction.
To prevent self-dealing is to expose buyers and sellers to a physical risks coming from demand and weather uncertainties; and price risks stemming from an artificial Pool – very little room will be given to market participants to hedge out unwanted positions.
Distribution companies may not agree with such initiatives on the grounds of commercial and political rights (depending on the nature of ownership). This could create a major obstacle or even trigger international court cases if investors from NYSE and LSE listed utilities feel that their interests have been affected. Regardless what the outcome of a case of this nature could be it stops investment flows immediately and may rise the Brazilian country risk and Foreign Developer credit risk spreads – an unbearable situation for all participants.
Lessons could be learned from the UK supply unbundling experience on how this process should be conducted. Generators were allowed to own supply-businesses to provide suitable physical hedge and placate investors and lenders. It was the scale of integration (i.e. Innogy, Powergen, ScottishPower and Scottish & Southern) that created market concentration leading some mispriced independent power producers close to insolvency. It has been debated whether or not there had been regulatory capture because lower prices in the exchange were not transferred to customers. Nonetheless customers are still enjoying low prices in the UK compared to other European countries. The next UK price review may be more stringent on this matter or even trigger market abuse clause for generators.
Finally large industrials could be penalised for achieving higher efficiencies and better returns when choosing the free-market. There may not be generators willing to provide competitive electricity if a better returns is offered by the regulated market. Exceptions would depend on the ability of market participants accessing global financial markets and ownership status (foreign generator and customer).
Setting an agenda
The BESI electricity market trades around 500TWh a year thus is to big to be disregarded by the international community. An agenda set towards creating an efficient commodities market could be agreed with stakeholders around the following main points:
• Create a transparent price exchange and market forward curve: that will be a cornerstone of making the risks manageable and introduce a new generation of structured trade and commodity-linked finance instruments and transactions capable of supporting capital requirements. This exchange should be able to produce reliable indexes for secured-energy certificates, electricity prices and any additional index required by the industry, in line with international standards for liquidity purposes.
• Regulations are an important component of market liberalisation: ANEEL, BACEN/MF and CADE should strengthen and refocus their regulatory powers to guide, support market functioning and deal with market abuse, not avoid its development.
• BESI funds and levies should be vested into a proper fund management structure: Eletrobras could refocus and further strengthen its financial and investor roles. The operational side should be left with subsidiaries themselves coordinated by MME.
• Restrict price equalisation: lower residential prices could be achieved by either levying the electricity price or residential market segment. This should be paid as rebate to supplier/infrastructure developer based on specific guidelines as an extensions of existing regulatory framework.
• Prevent planning and operating processes of becoming Market Rules: understanding how regulators, EPE and ONS calculated cost is an important part of the game. The incorporation of realistic market parameters for cost of financing (above 10%), cost of equity (above 10%) and risks are fundamental to market success. The supply deficit values should be just another parameter for planning decision not the forward curve itself.
• Allow re-jiggling of corporate picture for generators to face new markets challenge and risks: if the industry is going to face a monopsony may be an oligopoly is the appropriate vehicle to counterbalance such initiative;
• Communicate changes in the industry effectively: making easier for other energy players (e.g. gas & coal) and international lenders to understand the industry and its complexity. Clarity, simplicity of concepts and alignment with market principles are fundamental for sustaining capital inflows and lower interest rates.
After all, benefits from the creation of efficient electricity markets and low cost cannot be achieved prior to correct market foundations being laid down.
There is a major opportunity in front of the BESI to improve, reshape and promote sweeping changes in the industry – current market reforms proposal as it stands will make the industry ready to walk backwards. If going a couple of steps backwards before going forward is the ultimate game plan maybe it is time for the sponsors to show their hands as there is high probability for the BESI becoming a ‘dead man walking’. Fundamentally the reforms deny the creation of a truly efficient electricity markets and effective price risk management environment. Investors, lenders and customers could throw a lifeline of goodwill to keep it alive, but not forever – Brazil is still too big and influential to be ignored in the short term. In the future if better opportunities become available elsewhere, investors and major large industrial may consider moving on.
There is no painless market reforms for a industry of such a scale as the BESI, negotiations on sustainable market principles adapted to the Brazilian business culture seems the only way forward. Forty years ago Celso Furtado, a well known Brazilian economist, inspired a generation of professionals who helped to build the country’s energy infrastructure. Brazil is now immersed in the global markets (physical & financial) tough reality, its increased complexity & risks and stifling competition for capital and competitive products. It seems the BESI requires further advice soon to progress and realise its potential and fulfil stakeholders’ expectations. Otherwise General Charles de Gaulle’s comments about some of the Brazilian policies may remain true for a while: ‘Brazil was, is and will be a country for the future’.