Electricity Contracting and



Trabalho apresentado no 6th IAEE

European Conference "Modelling in

Energy Economics and Policy", Zurich,1-3, 2004

Electricity Contracting and

Risk Management Tools in the Brazilian Energy Market

Paulo S.F. Barbosa

State University of Campinas-UNICAMP

Av. Albert Einstein 951, 13084-970 Campinas, SP, Brazil

Tel. 55-19-3788-2359 Fax: 55-19-3788-2411 franco@fec.unicamp.br

Alberto L. Francato

State University of Campinas-UNICAMP

Av. Albert Einstein 951, 13084-970 Campinas, SP, Brazil

Tel. 55-19-3788-2359 Fax: 55-19-3788-2411 francato@fec.unicamp.br

Abstract: Evaluating multiple alternatives of electricity contracts has become a complex task for traders, end consumers and energy suppliers in deregulated markets. Based on previous models of other sectors, many players of liberalized energy markets have been developed a variety of physical and financial contract types, including bilateral, multilateral, standard, custom, must take, take or pay, take options, fixed or variable pricing, market pricing (and derivatives), fixed term, recurring, etc. In deregulating markets of emerging countries only a few of these new innovative instruments are in use, mainly because of the lack of knowledge about how they can help consumers to make better decisions whilst buying energy. In a context of permanent institutional changes taking place in the Brazilian deregulating energy market, this paper aims at: a) to present the main steps of the electricity market deregulation in Brazil, paying attention to the most relevant risk factors affecting contract management for end users; b) to highlight the most significant aspects of the Brazilian competitive retail program, also including comments about answers to a survey among consumers that have changed their electricity supplier; c) to evaluate some modeling results derived from different contracting alternatives for end consumers, using risk management tools (options) designed for hedging spot price volatility.

Keywords: electricity markets; contract management; retail competition; risk management; deregulating markets.

I. Introduction

Contract management is one of the key competencies necessary to achieve business success in the deregulated electricity industry. The energy industry has developed a variety of physical and financial contract types, with some of them exhibiting more difficulties than their counterparts in interest rate, foreign currency and equity markets. This is partially because electricity cannot be easily stored or transported thus determining a very complex price behavior. Each one of the contracting alternatives can be more appropriate for a certain company, depending on several factors, including the external characteristics of the existing power market (volume of trade, number of participants, relationship of the long term to short term market) and certain characteristics of the company (size and nature of the generation assets, corporate culture, attitude against risks, etc.). When considering the uncertain environment where decisions have to be taken, the design of new contractual instruments (including components for risk management) tailored to the deregulating electricity markets, is highly recommended.

Despite innovation on contract engineering in most liberalized energy markets, partially tracking financial instruments models, many commercial and industrial electricity consumers still take energy purchase decisions based on conservative practices. This consumer behavior has been emphasized in Brazil during several years after the beginning of market liberalization (1995), mainly derived from the following factors: (a) lack of tradition to run business in competitive markets, associated to the previously long period of large state owned utilities dominance; (b) emphasis of government on developing wholesale market with only few efforts to create the retail markets; (c) the weakness of the institutional framework to support new market development. However, during the past 2 years, a higher wage of electricity supplier switches is occurring, with a variety of contract types related to duration, delivery point, seasonal and hourly flexibility and also including hedging mechanisms. A general picture of this trend is presented in the paper based on a survey among big Brazilian commercial and industrial consumers. Some results of contracting alternatives are also showed to highlight the volatility of electricity energy expenditures for an end consumer and the effects derived from hedging mechanisms.

II. The Dynamic Changing of Electricity Industry under Deregulation in Brazil

With a power generation installed capacity of some 85 GW, Brazil is by far the largest electricity markets in South America, with the Brazilian total primary energy consumption being twice as large as the aggregated figures for Argentina, Bolivia, Chile, Paraguay and Uruguay. The total power generation installed capacity in the country at October 2003 was 84,934 MW, with 67,127 MW (79%) from hydropower plants; 15,778 MW (18.6%) from thermal plants; 2,007 MW (2.4%) from nuclear plants and 22 MW (0,03%) from wind power plants.

There are approximately 54 million customers (85% residential) and total consumption has increased from 70 to 300 TWh in the last 20 years. The total electricity consumption is distributed among the following sectors: industrial (42%), commercial (17%), residential (26%) and others (15%). Currently, nearly 95% of the Brazilian households have access to electricity.

A high changing pace in the regulatory and institutional context has been pointed out as one of the key issue in the Brazilian electricity market since the beginning of the country deregulation in 1995. The market design was based on the general guidelines of UK deregulation experience by implementing the following major steps: (a) the privatization of generation and distribution companies, thus attending the needs for revenue generation; (b) break up vertically integrated state companies into independent units for generation, transmission and distribution; (c) the creation of a national regulatory agency (ANEEL); (d) to set up competitive market mechanisms and institutions, granting independent producers free access to transmission and distribution networks; (e) gradually phasing the transition from regulated to competitive pricing as the new electricity market went from 98% state ownership to private participation (f) the creation of a spot market trading organization (wholesale energy market-WEM); (f) the creation of a national independent system operator (ISO), working on tight pool basis. Of course, this standard model of reform was implemented using a strategy tailored for Brazil, which has envisioned that private investors would assume key roles as owners and operators of the power system, under the control of the independent regulator. The role of government (Ministry of Energy) would be limited only to empowering the regulator and providing strategic policy guidance.

Under the privatization program, government generation and distribution companies were sold to private investors to raise US$ 21 billion mainly to service public debt, of which US$17.5 billion came from sale of state utilities and only US$3.5 billion from sale of federal companies. A critical issue was the beginning of privatization even before a regulatory structure was established by law and organized (Baer and McDonald, 1998). Although, the big market (48% of South America) encompassing a total of 54 million customers (85% residential), with an annual revenue of U$ 24 billion, has attracted significant additional investments since 1997 (U$ 11.2 billion). Actually, Brazil is placed at the first position in the ranking of the top six recipients attracting investments in power sector. In the present context, the fifteen biggest private investors (3 domestic and 12 foreign groups) run 61% of the distribution market share and 28% of the generation market share. Foreign companies are represented by holding groups from Portugal, France, USA, Spain and Belgium. Table 1 and Table 2 present additional country data.

Table 1 – Electricity industry data of Brazil compared to South America

| |South America |Brazil |

|Population (million) |353 |179 |

|Power generation installed capacity (GW) |175.2 |84.9 |

|Electricity production |706.7 |300.6 (85% hydro) |

|(TWh) |(73% hydro) | |

|Annual consumption per capita (KWh/ residential |2,000 |1,988 |

|consumer) | | |

Table 2 – Recent evolution of the Brazilian electricity consumption

|Year |Total Annual |Residential Consumption |Annual Growth Rate (%) |

| |Consumption |(KWh/consumer) | |

| |(TWh) | | |

| | | |Industrial |Resident. |Commercial |Total |GDP |

|2000 |307.27 |2064 |5.9 |2.7 |8.7 |5.1 |4.4 |

|2001 |283.26 |1757 |-6.6 |-11.8 |-6.3 |-7.9 |1.3 |

|2002 |290.47 |1658 |4.7 |-1.3 |1.8 |2.5 |1.9 |

|2003 |300.60 |1988 |1.7 |5.0 |5.0 |3.7 |-0.2 |

During the first stage of power reform (1997-2000), a significant set of good results were achieved, including the expansion of installed capacity for generation (13.4%), the growth of the residential consumers (from nearly 34 to 40.4 million) and more labor efficiency (reduction of the number of employees from 138,000 to 104,000 in the electricity industry). However, restructuring has been showing many difficult issues for public and private sector. As mentioned by Oliveira (2003), the privatization-for-cash approach to reform generated early income for the government but did not resolve key problems in making the power business a profitable and reliable enterprise. The growing concern to foster electricity industry profitability was underway when a drought in 2001 changed the focus from this to the power system reliability. A national rationing programme, mainly based on consumer awareness about supply risks, did avoid a big disaster. Although, that has create the opposite problem, with the biggest demand reduction (-7.9%) in electricity consumption over the past 50 years, thus pushing many electricity companies deep into debt. During the year of 2002 the power sector and the country economy were under political uncertainties concerned with presidential elections. With Lula’s election, the Worker’s Party initiated discussions about the market model for electricity. A new institutional model was designed and approved by law in April 2004.

The new regulatory arrangement aims to emphasize strategic planning in long run. The main goals of this new energy model are to hold tariffs down, to give fair return to investors and to connect up the 13 million Brazilians who lack electricity. One of the key characteristics of this new regulatory arrangement is to attract investment to expand power generation. Under the current institutional model, generators are exposed to market and their risks related to the highly volatile wholesale spot prices. If demand is too low (like it became just after the Government’s rationing programme in 2001) generators risk not find buyers. In addition to this, hydropower reservoir storages are always quite full during wet years that generators cannot sell their outputs at profitable prices. During shortages, generators are often forced to supplement their output by buying in the spot market, at very high market prices. In other words, spot market prices do not incentive power generation expansion. The new regulatory system obligates distributors to forecast demand five years in advance and to contract 100% of their market. There will be a new national pool, the Electric Power Commercialization Chamber, where generators will offer their energy sales through a scheduled bidding process along the year to cover the distribution forecasted demand. Assured of steady returns through power purchase agreements, generators might build new plants. Older state-owned hydroelectric generators also participate in the bidding pool. Therefore, these big generators would be more appropriately paid according to their (low) costs rather the market rate, thus contributing to lower the average prices.

Under the new institutional electric system, new power plants will be required to bid their output in yearly auctions and the federal regulatory agency(ANEEL) will obligate these power contracts to be subject to a cap regime. Distributors are prohibited from generating their own power to supply their customers as they did before (self-dealing regime). Otherwise, they will have to purchase power from the central Electric Power Commercialization Chamber through bidding.

III. Retail Competition and Risk Factors in the Electricity Market

The Brazilian electricity retail competition has started in 1995 based on the creation of multiple new players in the market: (a) energy trading companies, which might be or not part of electricity supply holding groups; (b) independent power producers (IPP), able to sell its power production directly to end consumers; (c) open access to grid. This program was gradually implemented defining as eligible consumers those ones with demand of 10 MW and up connected at 69 kV and above. The threshold limit for demand was reduced to 3 MW in July 2000.

During the initial years of the retail competition only few companies switched its electricity suppliers. This can be understood not only from uncertainties related to electric sector but also from macro-economic and political factors that had strong impact on business decisions. A list of these factors is showed in Fig. 1 with the associated assessment of risks for both consumers and suppliers.

[pic]

Fig. 1 – Risk Factors and Opportunities in the Brazilian Deregulating Electricity Market

After some successful switch experiences during 1998 and 1999, a growing migration process into retail competition market took place in the country. A survey among selected big Brazilian commercial and industrial consumers that have switched their electricity suppliers was undertaken at the end of 2002. These consumers were selected from different sectors (chemical, industrial gas suppliers, car manufacturers, etc.) with peak demand ranging from 22 to 94 MW. From this survey, the following findings can be highlighted:

a) The driven motivation to participate in the retail competitive market was the risk perception about growing tariffs while connected to distributors (regulated rate regime). Uncertainties about annual updating tariff rate, defined by the regulatory agency (ANEEL), could not allow planning energy purchases. Therefore, the option to set up contracts at steady price, or with prices being defined as a function of an economic index, through bilateral contracting between a consumer and an electricity provider, was considered as a valuable alternative to those consumers interviewed in the survey;

b) The main factors considered to choose a new supplier are taken separately into account through two decision making stages. In the first stage (pre-qualification) most consumers selected the big generators or distribution companies with brand mark in the electricity market. No discriminatory decision between domestic or foreign suppliers was mentioned by consumers. Also, no differentiation related to geographic location of the supplier was mentioned. Although, they did not consider contracting proposals from pure trading companies without significant past track on electricity business neither those generators using only alternative sources for power production (small power plants, wind plants, etc);

c) In the second decision making stage, consumers selected two or three suppliers based on price, evidences for improvement on customer relationship and flexibility to meet their customized needs. Final decisions consider financial guarantees, evidences about the potential capability to meet all contract requirements and further specific items related to contract flexibility defined at the final round of negotiations;

d) Most of the contracts were set up with annual updating of electricity energy prices, according a national indicator of inflation (general index of price). At their first experience in retail competitive market, consumers preferred standard forms of contracting as a mean to avoid possible risks associated to lack of understating with more complex items and options from derivatives, for example. Actually, energy purchase managers always considered an already significant evolution step to convince their CEO about the advantages of switching electricity supplier. Only from their second switching experience they considered more sophisticated contracting alternatives, including financial hedging tools.

Recent data (2004) shows significant growth in Brazilian retail competitive electricity supply over the past 18 months. Since mid-2002, competitively priced electricity supply more than doubled. Right now, an estimated 14,400 megawatts (MW) of peak electricity demand (nearly 17% of the total installed capacity) are competitively supplied. Customer participation in competitive markets is also on the rise, with more than 120 big size customers switched energy suppliers during last 18 months, out of about 160 customers that have switched since the beginning of retail competitive market (1995). From this growing and diverse experiences some sophistication on power purchase contracting has been developed, mainly considering opportunities and risks derived from spot price volatility.

IV. Evaluating Contracting and Risk Management Alternatives for Consumers

IV.1 The nature of spot price volatility in Brazilian hydrothermal system

The Brazilian power system is highly dominated by hydropower generation (85% of the annual production). In contrast to thermal-based systems, hydro-based systems exhibits low short-term spot price volatility and high seasonal / inter-annual spot price volatility. System reservoirs can transfer energy from off-peak to peak hours, thus minimizing load deficits along with successive time periods of the short-term horizon. However, if a dry period occurs when reservoir storage are low, spot price may experience significant increase and even grow up to rationing cost. Reservoir capacity of hydropower plants are designed to avoid frequent situations of deficit. Therefore, most of the operating time hydropower plants produce energy at low-cost, with just a few periods (droughts) of higher cost. The corresponding spot prices have a skewed probability distribution, where most price scenarios are very low, and only a few are high. This effect can be seen in Fig.2, where spot prices of the Southern system are showed. They were calculated by the national ISO with the aid of optimization models that compute opportunity costs for hydro plants (Barroso et al., 2003). The power system is dispatched in a least-cost centralized basis by ISO using a dual stochastic optimization model ( Pereira and Campodonico, 1997) formulated to include the entire country hydrothermal system. One of the main features of this model is the short-run marginal costs for each sub-system (North, Northeast, South, Southeast-Central) of the country, and these are the spot market prices. Therefore, spot prices in Brazilian market are not the result of supply-demand equilibrium from a bid-dispatch as it is in most electricity markets.

Fig. 2 – cumulative probability distribution of spot prices with distinct starting dates

(generated by dual stochastic dynamic programming using 2000 river flow series)

IV.2. Evaluating contract alternatives with hedging instruments

The most frequent low spot prices have opened opportunities to end consumers buying low cost energy from generators through bilateral contracts by, partially based on spot prices. Of course, no generator will sell its whole power production at spot prices since hydro-dominant power systems determine higher spot prices in drought situations although their reservoir storages usually are quite empty (Barbosa and Braga, 2003). Also, consumers cannot be exposed to high volatility of spot prices all fraction of their loads. Therefore, the best contracting alternative for both counterparties are based on a mixed solution. Fig. 3 illustrates such situation with a big size consumer. He intends to plan his electricity purchase contract during the period spanning from 2004 to 2007. The total load is divided between three parts, with the first one (Lf ) to be purchased at fixed price (PPA: power purchase agreement); the second one ( Lsc ) to be purchased at spot price plus trading costs (charged by any trading company to allow consumers to have access to the Wholesale Energy Market-WEM) and hedged by a call option and the third one (Ls) to be purchased at spot prices (without any hedging mechanisms). Of course, this is only one among multiple alternatives of contract arrangement.

The load part (Lf ) could be divided in two or more parts with different magnitudes along total length duration of the contract; a put option could also be included in the formulation and many other contracting alternatives would be available to be evaluated. The problem can be formulated as a stochastic optimization model taking 2000 spot price series that are generated by the least-cost centralized model at ISO using a dual stochastic optimization model. When using a stochastic optimization with simple recourse, the first-stage decision variable would be the load part (Lf ) that is purchased at fixed price that is determined for the whole set of spot price scenarios.

[pic]

Fig.3 – A possible power purchase contract arrangement for end consumer

Instead of using stochastic formulation, a simple example is presented using simulation through SisRisk, a decision support system designed to aid consumers whilst evaluating contract alternatives. Assuming a particular scenario i for spot price, the total electricity cost associated to the purchase of the total consumer load (Lf + Lsc + Ls) is calculated (monthly basis) by:

[pic] (1)

where,

i : a particular spot price scenario;

j: a particular year of the contract time horizon;

t: a particular month;

t1: initial month of the period of time that a call option is active;

t2: final month of the period of time that a call option is active;

[pic]: total annual cost of the electricity purchases associated to a contract for year j ;

[pic]: unit fee ($/MWh) charged by the trading company from consumers to have access to WEM;

[pic]: strike price of the call option ($/MWh);

Lf : part of the consumer load to be purchased at fixed price (PPA: power purchase agreement);

[pic]: part of the consumer load to be purchased at spot prices with hedging (call option);

[pic]: part of the consumer load to be purchased at spot prices (without any hedging mechanisms);

[pic]: spot price at month t in the Wholesale Energy Market assuming occurrence of scenario i;

[pic]: monthly premium (R$/MWh) charged from the consumer for the call option.

A variety of alternative contracting can be tested using SisRisk and taking into account the spot price variability through computation over the 2000 spot price series. The calculation of mean value of total purchase costs and standard deviation of such costs (as a measure of risk) for each alternative will allow consumers taking better decisions facing the whole set of possible contracting alternatives. Therefore, the mean values of total purchase costs can be calculated by:

[pic] (2)

where:

M: number of spot price scenarios (default value: 2000);

MCj: mean value of the contract price (R$/MWh) for year j;

Lj : total load (summation of Lf + Lsc + Ls);

Tj : number of hours in the year j.

4.3 Case Study

An industrial consumer is evaluating possible contracting alternatives offered by a power generator, according the methodology described before. The length duration is five years for all contracting alternatives, starting in 2004. The evolution of the consumer load and also the most simplified contracting alternative (which is called CA-1, with fixed annual prices) offered by generator is showed in Table 3.

Table 3 – Evolution of load requirements for an industrial consumer and corresponding prices

offered by a generator with the contracting alternative CA-1

|Year |2004 |2005 |2006 |2007 |2008 |

|Electricity energy consumption | | | | | |

|(average MW´s) |60,00 |63,00 |66,15 |69,46 |72,93 |

|Unit price offered by generator | | | | | |

|(contract alternative CA-1) |50,00 |58,00 |R$ 62,00 |R$ 72,50 |R$ 81,00 |

|R$/MWh | | | | | |

The mean annual spot price calculated for every year along length duration over the 2000 series is showed in Fig. 4 and also. The fixed annual prices offered by generator through contracting alternative CA-1 are clearly advantageous when compared to mean spot prices for every year except in 2004.

[pic]

Fig. 4 – Consumer Load, Mean Spot Price Growth and Fixed Prices of Contract CA-1

Other two contracting alternatives investigate mixed solutions, including:

a) CA-2: 70% of the consumer load is contracted at fixed annual price (Table 3), and the

remaining load is contracted at spot prices without hedging (results: Fig. 5);

b) CA-3: same characteristics of CA-2 but including hedging through a call option from 2005-

2008, with monthly premium PC = $ 4.58/MWh and strike price K = $ 97,60/MWh

(results: Fig. 6)

The comparison of performance between CA-2 (Fig.5) and CA-3 (Fig. 6) clearly shows the significant hedging effects occurred in CA-3 in terms of reducing max annual prices for years when the call option is active (from 2005 to 2008). The comparison of CA-1 and CA-3 also shows nearly higher performance of CA-3 when considering the mean value of annual prices and only a low risk exposition when max or P95% of annual prices is considered.

[pic]

Fig. 5 – Simulation Results for Contract Alternative CA-2

[pic]

Fig. 6 - Simulation Results for Contract Alternative CA-3

V. Conclusions

Despite many uncertainties and difficulties faced by government and other players during deregulation of electricity industry in Brazil, competitive retail supply has opened great business opportunities for consumers. Commercial and industrial consumers have experienced substantial savings through retail competitive market. They have observed savings levels over the utility default rates (regulated) in the 10-30 percent range. However, benefits of retail competition go so far beyond savings. Consumers have reported significant improvement on customer relationship, with value added services and a broaden scope of customized energy solutions. For all customers that had experienced the participation in competitive markets through retail choice, there is no way back to distributors companies running the regulated tariff regime.

In this new context, there is much more available information about electricity prices through reverse bidding pools organized by trading companies and from the bigger number of transactions among consumers, electricity suppliers and traders. Contract innovation and management represent a key competence for both suppliers and consumers in this new market place, and this is also another benefit that came from retail competition. The potential threat of switching electricity suppliers has also contributed towards some improvement in service quality of distribution companies for all their customers.

The big challenge for government is to promote further steps towards market efficiency, including changes on the current requirements to allow the expansion of the basis of eligible customers (reducing the minimum load from 3 MW to 1 MW, for example), and also, to extend such benefits through remaining stages of electricity supply chain (wholesale market included).

Acknowledgment: This work has been supported by CNPq (National Scientific and Technologic Brazilian Council) through the grant no. 552364/01-0.

VII. References

Baer, W., McDonald, C., A Return to the Past? Brazil´s Privatization of Public Utilities: the

Case of the Electric Power Sector, The Quarterly Review of Economics and Finance,

v.38, No.3, pp.503-523, Fall 1998.

Barbosa. P.S.F., Braga, B.P.F., Electric Energy Sector and Water Resource Management in the

New Brazilian Private Energy Market, Water International, USA, v.28, no.2, June

2003

Barroso , L.A., Granville, S., Trinkenreich, J., Pereira, M.V., Lino, P., Managing Hydrological

Risks in Hydro-Based Portfolios, IEEE Transactions on Power System, 2003

Oliveira, A., The Political Economy of the Brazilian Power Industry Reform, working paper#2,

PESD, Stanford University, Feb. 2003.

-----------------------

Regulatory

Uncertainties:

1995-2004

New regulatory framework: 2003-2004

Expansion of the retail choice: 2003

Growth of Inflation rate: 2002

Potential for growing regulated tariff rate:

2000-2003

Bidding for low prices energy offers of state-owned generators: 2002

Uncertatinties about power supply expansion: 1999-2002

Impacts of external crisis: Asia, Russia, Argentina,

California, Enron

Potential savings from improvements on energy efficiency 2001

Power supply excess: 2003

Power shortage crisis 2001

Currency devaluation:

1999 e 2002

Ls : load fraction to

be purchased at

spot prices

Oportunities to Consumers

Oportunities to Electricity Suppliers

Risks to Electricity Suppliers

Risks to Consumers

Year

Consumer´s Load (MW)

2004

2005

2006

2007

Lf: load fraction to be

purchased at fixed

price (PPA)

Consumer load forescating (MW)

Lsc : load fraction

hedged with a call

option

[pic]

Load (MW)

0

40

50

60

70

80

90

100

2004

2005

2006

2007

2008

Year

Price (R$/MWh)

0

20

40

60

80

Mean Annual Spot Price

(70% PPA e 30% Spot without hedging)

Average Annual

Price –CA-1

Consumer Load (MW)

Annual Prices for Contract Alternative CA-2

20

40

60

80

100

120

140

2004

2005

2006

2007

2008

Year

Prices (R$/MWh)

Mean Values of the

Annual Prices

0

Max of the Annual Prices

20

P95% of the Annual

Prices

(70% PPA e 30% spot with call option from 2005-2008)

Min of the Annual

Prices

Annual Prices for Contract Alternative CA-3

40

60

80

100

120

2004

2005

2006

2007

2008

Year

Price (R$/MWh)

Mean Values of the

Annual Prices

Max of the

Annual Prices

P95% of the Annual

Prices

Min of the Annual

Prices

.

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