RESTRUCTURING THE MEXICAN ELECTRIC INDUSTRY. AN EVALUATION OF THE USE OF FINANCIAL TRANSMISSION RIGHTS.

Alfredo Mier-y-Terán Economics Student at Centro de Investigación y Docencia Económica (CIDE, Mexico)

Carretera México-Toluca no. 3655, Col. Lomas de Santa Fe, 01210 México D. F. Tel./Fax: 57279800 / email: alfredo.mier@cide.edu

ABSTRACT The Mexican electric industry was partially opened to private investment in power generation in 1992, but suffers from an inappropriate regulatory framework. This paper provides a current overview of the Mexican electric industry and analyzes the literature and international experience in the use of financial transmission rights to evaluate their potential use in the Mexican industry.

The first section describes the development of the electric industry in Mexico and explains the architecture of the industry today. Furthermore, it provides an economic analysis of the reforms the last two administrations sent Congress for deregulating the electric industry. The second section reviews the literature and international experience concerning financial transmission rights. The third section uses the analysis made in the second section to propose some recipes for determining the model best suited to enhancing competition and introducing financial transmission rights in the Mexican industry while pointing out the regulations and reforms needed to make it viable. The fourth and last section concludes by simulating the performance of financial transmission rights in the Mexican industry. To that end, I employ a representative 26-node model that takes into account the current market’s main generator prices and capacities, demand, and transmission capacities. Introduction The electric industry is very similar around the world. Its functions are divided into generation, system operation, transmission, distribution, wholesaling and retailing. The typical organization of the industry prior to deregulation consisted of vertically integrated companies (usually owned by the state) that incorporated all of these functions. In the last 20 years many industries have been deregulating to allow competition in this sector. Why competition? There are several reasons. In markets like the ones in the U.S. Northeast, industrial customers began to view regulated utilities as barriers to the lower-priced power available in wholesale markets. These customers generated the initial political pressures to reform in theses markets in order to obtain retail competition, and thus a reduction in retail prices. The political debates focused on the long term benefits that competition could provide to customers. They argued that competitive wholesale markets for power would provide better incentives for controlling the capital and operating costs of generation capacity; encourage innovation in power supply technologies; and would shift the risks of technology choice, construction cost and operating mistakes to suppliers and away from consumers.

These arguments were accompanied by a growing philosophy among capitalist countries of the need to shift away from central planning by shrinking the role of the state in industry. The Central Electricity Generating Board (CEGB), for example, was privatized as part of Margaret Thatcher’s widespread reforms of the U.K. public sector during the 1980s and 1990s. CEGB had been demanding mammoth outlays for a massive program of investment in nuclear power to displace British coal. The Prime Minister believed that the

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generation business could find more efficient ways to conduct its investments and operations, if given the right incentives. Competition in the electric sector generally takes place on the level of power generation, and the commercial functions of wholesaling and retailing. Competition in generation was made possible with a technological advance in the 1980s, which combined the steam generators with direct fuel combustion that increased the efficiency levels of plants from an 18%-36% range to between 60% and 65% (Hunt, 2002). These new plants, called combined cycle gas turbines, made it clear that economies of scale were not an inevitable part of electricity production. Nevertheless, the transportation functions (transmission and distribution) remain natural monopolies. It doesn’t make economic sense to build multiple sets of competing transmission systems; everyone has to use the same wires. They have to serve everyone, and they have to be regulated. Likewise, the system operator has to be a monopoly that coordinates the dispatch in all plants in order to meet demand in real time without overloading the system. The problem in restructuring the electric industry is that the competitive parts need to be separated form the regulated parts, and the coordination that was working under vertically integrated companies may be lost. The greatest challenge for electric industries that want to combine competition with natural monopolies lies in the proper design of institutions and successful implementation of mechanisms that replace the previous internal coordination without loosing efficiency. 1. Electric Industry in Mexico The electric industry in Mexico was born in 1879 with the construction of a thermo-electrical plant inside the Asier y Portillo textile factory in the city of León Guanajuato. In 1881 Mexico City installed public lighting and eight years later the first hydroelectric plant was built in the state of Chihuahua. In the subsequent years the biggest contributions to the electric industry were made with the idea of developing more efficient mining and textile industries. Subsequently these small, regional, vertically integrated systems were scaled to offer a public lighting service to the major cities. Between 1897 and 1911 more than a hundred light and power companies emerged to satisfy the growing demands of industry, municipalities and transportation services.

As the first quarter of the 20th century passed, companies such as The Mexican Light and Power Co. Ltd. and the American and Foreign Power Co. (represented in Mexico by Compañía Impulsora de Empresas Eléctricas) invested in the industry to consolidate as the first interconnected electric networks in the country. These companies centered their interest on developing an electric system that responded to their economic interests. In order to assure that the power needs of low-demand rural areas were met, the Mexican government began regulating through various public entities. Nevertheless, Rodriguez (1994) argues that this attempt to control the system was a major failure because of constantly shifting attributions on the level of policy development, the awarding of concessions, and the regulation and supervision of the industry. The Comisión Federal de Electricidad (CFE) was created in 1937 to replace all the past regulatory entities and to create the appropriate institutional framework to develop a central entity for procuring the power needed to achieve economic growth. According to the Mexican Constitution, the principal activities of the CFE are to generate, conduct, transform, distribute and supply electric power.

In the next three decades the national government gave financial support to the CFE in such a way that by 1960 the CFE owned 11 interconnected systems with a 1,855 MW capacity in the country that represented around 60% of the national flow. (Hernández, 2004) That same year, President Adolfo López Mateos, added a paragraph to Article 27 of the Constitution that awarded the state the exclusive right to generate, conduct, transform, distribute and supply electric power for public service. Furthermore, the state was also given exclusive access to the natural resources needed for electric power generation.

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This nationalization was the most prominent event in the evolution of the Mexican electric industry. In 1960 the Mexican government became the main shareholder of the Mexican Light and Power Co. and its subsidiaries L.M. Guiba Sucesores, S en C. and Compañía Mexicana Hidroeléctrica y de Terrenos, S.A. In April of that year, the government bought the assets of Compañía Impulsora de Empresas Eléctricas, S.A. for US$65 million. The government took control of the entire public service and started a process of price and frequency unification followed by an electric system interconnection to reduce local operational reserves and reduce costs. The network was developed with tensions of 400 kV for the southern and central regions where high demand was concentrated, and 230 kV for the low-demand regions of the north.

In subsequent presidential administrations, the electric sector as well as the oil industry grew as source of national pride, political power and financial resources for the state. Labor unions became increasingly powerfull and the financial administration of utilities was centralized. Consequently, state owned companies increasingly lost flexibility and their capacity to modernize in time. It is worth noting that after the nationalization of the electric industry the retail prices of power remained unchanged until 1973 and even then failed to keep pace with inflation until the early eighties. In 1983, after Mexico defaulted on its external debt, President Miguel De la Madrid was able to raise these depressed rates to reduce the sector’s financial losses. This adjustment was achieved with a cross-subsidy from industrial and commercial users to residential and agricultural users. Nevertheless the structural problems of the CFE were not resolved. In 1985 the federal government had to assume a debt of 360 billion pesos from the CFE. (Rodriguez, 1994). In the aftermath of the debt crisis of the eighties, Mexico’s central-planning government began a series of reforms to lead Mexico into a merchant economy. Many state owned companies were privatized or opened to private investment. Toward this end, President Carlos Salinas proposed in 1992 a constitutional reform to reopen the electric sector to private parties as a way to finance the added capacity needed to respond to growing demand following a prolonged period of inadequate investment.

Congress balked at the constitutional reforms, but agreed to amend Mexico’s law on public electric power service (Ley del Servicio Público de Energía Eléctrica (DOF, 1992)) with an eye toward complying what would become the energy chapter of the North American Free Trade Agreement (NAFTA) and still retain state control of the energy sector. On December 23, 1992 the following activities were opened to private investment:

• Self-supply to meet an industrial facility’s own needs. • Cogeneration of electricity generated with steam or other types secondary thermal

energy. • Independent Power Production (IPP) with plants of capacities larger than 30 MW

built and operated by private companies who were required to sell their power to the CFE under Power Purchase Agreements (PPA).

• Small scale generation with plants of capacities not larger than 30MW built and operated by private companies obligated to sell electricity solely to the CFE.

• Imports for self supply purposes • Exports of electricity produced under cogeneration, IPP or small scale generation.

However IPP did not emerge as an answer to the industry’s large scale investment needs

until late 1995 with the approval of changes to the laws on public debt and budgets that allowed for the creation of a new arrangement known literally as Productive Infrastructure Projects with Differed Expenditure Impact or PIDIREGAS. This scheme was created for the development of long term infrastructure projects and became a perfect tool for the CFE to contract debt via IPP projects. The CFE is now allowed to account as liabilities only the first two years of payments for capacity of a PPA and consider further payments as contingent liabilities. IPP projects are approved by Mexico’s Finance Ministry (Hacienda) and Congress

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once the CFE proves that these projects will generate enough income for the commission to pay for themselves. In this way the CFE has been empowered to contract enough debt to fulfill its investment needs.

In December 2004 the installed capacity of IPP, self-supply and cogeneration projects reached 7,265 MW, 2185 MW and 909 MW respectively out of an industry-wide total of 50,679 MW. According to the CFE’s expansion program, IPPs are expected to grow rapidly (see Figure 1).

Figure 1. Percentage of installed capacity

0%

20%

40%

60%

80%

100%

120%20

00

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

CFEIPP

Source: Sener and CFE.

In February 1999, President Ernesto Zedillo, sent Congress a bill to amend Articles 27 and 29 of the Mexican Constitution. The initiative was designed to clear the way for a structural reform of the electric industry. His administration stressed the fact that without this reform the CFE and LyFC would not be able to meet demand growth of 6.1% in period 2000-2005.

Zedillo’s reform proposed to leave in the hands of the state nuclear power plants and part of the hydroelectric generation in the south of the country owing to national security concerns and because the state manages the supply of water for other purposes, such as irrigation. It also suggested keeping in the state the operation of the system, transmission and distribution while opening to private investment the generation, and retail of electricity. The proposal was divided in three stages:

1. The CFE and LyFC were to be split up into several independent generation, transmission and distribution companies while the state would create an independent system operator (ISO).

2. An electric wholesale market would be established and power generation, transmission without interconnection, and commercialization were to be opened to private investment. The market starts operating and the ISO starts the physical and financial dispatch. Generators compete with each other for contracts from distributors and consumers.

3. State owned generation, transmission and distribution enterprises would be privatized. Carreón and Rosellón (2002) analyzed the implications of this reform and found several problems. In terms of the national transmission company (REN), the reform was contradictory since it didn’t define clearly the property rights of the transmission network. Moreover they charged that the proposal lacked coordinated incentives to solve congestion problems in the short run and to recover fixed costs and investment to expand transmission capacity in the long run. They underlined the fact that the ISO didn’t have well defined duties that could be duplicated with those of the regulatory entity (CRE), the Ministry of Energy (SENER) and REN. In accordance with the vertical integration proposed they found that problems of cross

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subsidies might arise between big and small consumers in which the latter would not benefit from competition. Another problem with prices arises from the second stage of the proposal in which private generators could be discriminated against by state owned distributors, thereby leaving them in an unfavorable position to compete against the companies to be privatized in stage three. Among other problems, Carreón and Rosellón point out that the commitments assumed by the state with IPP would represent a burden for privatized distribution companies that would encourage them to raise the rates they charge consumers. The proposal never passed Congress. With the presidential elections approaching, the outgoing administration wasn’t able to gain the support of all factions neither within the governing Institutional Revolutionary Party (PRI) nor from the opposition on this issue that so inflamed nationalist sentiments. The 2002 Fox’s administration’s proposal called for creating an electric market along the same lines of the one proposed by Zedillo. Nevertheless there were some differences that were designed to deal with the questions of national pride that surround the issue. Rather than privatizing the existing resources of the CFE and LyFC, Fox sought to restrict the state monopoly on the dispatch and nuclear generation of electricity by making matters of generation and transmission confined to a simple law rather than the Constitution. In doing so, he would make it much easier to change the law in a latter stage of negotiations for opening the power generation and distribution businesses. But this proposal failed to avoid the same pitfalls that arose in stage two of the Zedillo proposal. The state owned company would have the incentive to discriminate against private generators by restricting their access to the transmission grid, but in this case the problem would persist over the long run. Carreón and Rosellón (2002) sustain that the proposal lacks the mechanism of incentives to expand generation and transmission and that it does not clearly state who would have to assume this responsibility. Moreover they argue that the CFE might find line congestion profitable. The Mexican Electric Industry Today Today the sector reflects a vertically integrated industry, developed mainly by the two state owned companies: the CFE and LyFC. There are small segment of social and private generators who produce primarily for self-supply or for sale to the CFE. All other activities within the sector are considered public services and are restricted to the state. The Ministry of Energy sets the general policies and the Energy Regulatory Commission (Comisión Reguladora de Energía, CRE) regulates the activities of the electric industry. LyFC provides service to the Federal District (Mexico City) and parts of the neighboring states of Mexico, Morelos, Hidalgo and Puebla. The rest of the country is covered by the CFE through three interconnected systems: the main one covers almost all of the rest of Mexico while two others separately attend to the states of Baja California, and Baja California Sur.

The whole system’s installed generation capacity is currently 50,579 MW, which breaks down as Figure 2.1 shows. To satisfy the expected growth in electricity demand between 2004 and 2012, the CFE estimates around US$50 billion in investment is needed to install 25,757 MW of new capacity and modernize transmission and distribution systems. As Figure 1 shows, IPP are expected to carry out most of the expansion as CFE lacks the means to fund such investment on its own. (The CFE reported losses totaling US$720 million in 2003 and US$174 million through the first nine months of 2004.) Without a new mechanism to attract private investment, it might not be possible to sustain that growth even with IPP because the CFE is exhausting its ability to contract debt via PIDIREGAS. Although the CFE’s debt is considered by international financial markets as low risk because it viewed as a form of sovereign debt, it is important to note that the ratio between liabilities and assets within the CFE have grown from 25% in 1998 to more than 40% in 2004 mainly due to PIDIREGAS liabilities. (see Figure 2.2)

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Figure 2.2. Liabilities as a Percentage of Total Assets (1998-2004)

Figure 2.1 Installed Capacity

Source: CFE 2. Literature and International Experience Physical and economic attributes of electricity What makes the transformation of a regulated electric power industry monopoly into one that relies on competition so challenging? Paul L. Joskow (2003) lists the unusual physical and economic attributes that complicate the task of replacing hierarchies with decentralized market mechanisms as follows: • Electricity can not be stored economically and demand must be cleared with just-in-time

production from generating capacity available to the network at almost the same time that electricity is consumed.

• The short-run demand elasticity of electricity is very low and supply gets very inelastic at high demand levels. As a result, spot electricity prices are inherently very volatile and unusually susceptible to the creation of opportunities for suppliers to exercise market power.

• Network congestion, combined with non-storability, may limit significantly the geographic expense of competition by constraining the ability of remote suppliers to compete, further enhancing market power problems.

• Loop flows, resulting from the physics of power flows, create unusual opportunities for suppliers to take unilateral actions to affect market prices, complicating the definition of property rights, and creating coordination and free riding problems.

• Because electricity can not be stored and demand varies widely over a year, a significant amount of the generation capacity connected to the system operates for a relatively small number of hours during the year to meet peak demand. This means that the ability of some generators to recover investment and fixed costs is not guaranteed.

• There are important complementarities between energy markets and transmission operations, especially congestion management and responses to emergencies. Thus, integrating spot energy and ancillary service markets with the allocation of scarce transmission capacity is necessary for wholesale power markets to operate efficiently.

Transmission Expansion and Financial Transmission Rights

Liabilities/Assets

0%

5%

10%

15%

20%

25%

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45%

1998 1999 2000 2001 2002 2003 2004

1. Insatlled Capacity Mexico 2004 (MW)

3 7,512

83 4

1,973

7,2 65

2 ,185 9 09

CFE LFC Pemex

IPP Self-Supply Cogeneration

6

Every investment in generation of a significant size has to be accompanied by an expansion of

y Bushnell and Stoft (1997), transmission investment needs

s the efficient coordination in terms o

regional transmission onopo

96, 1997; Chao and Peck 1996) p

erchant Transmission Investment: The Simple Model

or simplicity’s sake, we assume that there exist only two nodes, one in the north and another

pensive generators necessa

d by a transmission line with capacity K. If K is less than required in equilibrium we will not reach equilibrium and the price in the south (pS) will be

the transmission network. In an industry where transmission and generation are vertically integrated in a national monopoly, such decisions are made centrally. Nevertheless, when these two kinds of investments are made independently, problems of coordination arise because: a) an investment in generation requires at least the connection to the network; b) additional capacity can be inefficient if the increased power causes congestion costs, constrains the operation of low-cost generating plants at particular locations, or reduces reliability; c) the decisions to allocate new plants and to retire existing generators depend on the forecasts of network congestions; d) transmission congestion may enhance market power (P. Joskow and J. Tirole, 2003). Moreover, as explained bto be regulated as transmission expansion does not necessarily increase the network’s capacity, in fact it can even reduce it in the presence of loop flows. Joskow and Tirole (2003) also explain how transmission investments are interdependent and may lead to games in which participants have incentives to invest bellow a social optimum.

It is necessary to have a regulatory frame that guaranteef the social welfare of investment in the generation and transmission of electricity.

The literature on transmission expansion has generally associated the design of such frames to economic models that stressed the importance of the price of electricity. However, in recent years, this study has focused on the design of the institutional frame that, together with the price structure, generates the proper incentives to expand the network. On the one hand there is the approach in which a national orm ly exists that is subject to a regulation that provides the proper incentives to minimize economic rents considering the information problems that arise between regulated company and regulator. Joskow and Tirole (2003) refer to this approach as regulated Transco (or regulated transmission company). Vogelsang (1999a, 1999b) suggests a two part tariff to coordinate long- and short-term incentives in which congestion problems are solved with variable costs, while the incentives to expand the network are made through the proper rebalancing of fixed and variable costs. Incentives in this model work as follows: when there is excess capacity the variable charge is reduced and there is an increase in consumption, yet the fixed charge increases making the total income increase. Consequently, the Transco will not have incentives to expand capacity, and net profits will increase since costs don’t change. On the contrary, when there is congestion, the variable charge will be a congestion charge and, if congestion charges are on the margin greater than the marginal costs of expanding capacity, the Transco will have the incentive to invest in new capacity.

On the other hand (Hogan 2002a; Bushnell and Stoft 19ropose decentralized institutional models that create incentives for transmission

expansion through the assignment of transmission rights to market participants. This approach is known as merchant transmission investment. The present study focuses on evaluating the performance of this approach. M Fone in the south. In the north generation is cheap and demand is low, while in the south generation is expensive and demand high. So, the power will flow from north to south and the price will be determined by the equilibrium between demand and supply.

The supply curve will just consist of an ordered list of the least exry to meet demand on the system. In this way, the most expensive generators will not

dispatch and all suppliers will have an incentive to reveal their marginal costs. The price will be the equal to the marginal cost of the last generator dispatched and will be consistent with the consumer willingness to pay.

North and South are linke

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larger t

Consider a δK. This increase allows ne more KWh to

ow form the north to the south, which represents a social value of area ACDE. This model suggest

s

define transmission rights, and give them to people who expand the transmi

arise, prices between different locations vary. The problem that rises is that of defining how many different locations should be taken into account. At one

atible. For example, if a

han the one in the north (pN) As shown in Figure 3, the shadow price of the capacity constraint in transmission will be η = pS - pN. The area ηK is known as the congestion rent and triangle ABC is the congestion cost.

marginal increase in capacity ofl

s that the investor should be awarded with a transmission right that pays a dividend of η. In this way, a new investment will be conducted if η > δK. However, if the investment is to be conducted by the owner of the line, η > δK is not a sufficient condition for him to invest ince an investment in K may reduce his congestion rent. To solve this problem it is necessary

to assign a capacity K1, not too different from actual capacity, and auction financial transmission rights with the value ηK1. In this way, a new entrant could be able to take care of the investment

In general terms, the theory of market-based mechanisms for transmission expansion states that if we

ssion system, and then this people will have the incentives to expand the system if the rights are valuable. The rights will be valuable when there is congestion in a certain line, therefore expansion incentives will be made when and where transmission is needed. The incentives will match the need because the alternative to building will be to pay the cost of congestion. However, many technical and structural characteristics of the electric industry complicate this model. Nodal vs. Zonal Pricing When system constraintsaextreme there is nodal pricing, determining a unique price for each node of the transmission system. A single price for the whole system is the other extreme and zonal pricing stands somewhere in between. Almost every restructured market has had zonal pricing, but eventually moved to nodal pricing, which represents the true underlying prices that come out of the dispatch process. Zonal price systems are approximations that average nodal prices or recalculate prices in simulations that ignore losses and congestion. Although averages and simulations may save transaction costs, zonal pricing can run into problems that make the market no longer incentive-compgenerator with an offered price of $20/MWh is told to run, and the market price subsequently averages down to $18/MWh, the generator will be losing $2/MWh.

A

B

C

δK

K K*

SNET

DNET

Congestion rent Price

Congestion cost

Quantity

E

D

η

p

n Rents vs. Congestion Costs

pS

Figure 3. Congestio

N.

8

This problem may be solved using constrained-on and constrain-off payments so that prices become incentive compatible. In our example the generator would get a $2 extra constrai

a zone. As a part of a market reform, California is planning to introduc

hts

h to transmission rights entails market participants acquiring rights that atch their expected transactions in order to utilize the system and obtain physical access.

If they are not able to do so they will lose the valu

uous trading in real time with the SO involved to match or reconfig

l not flow nment of property rights

become

e in the nodal prices between its hoice of two points, which is equal to the congestion rent multiplied by the number of MW

es • They can assist in meeting installed capacity obligations in conjunction with parallel

.

• ith market power problems.

ned-on payment. However these calculations become complicated because it is necessary to know exactly why a generator was or wasn’t running. The less zones, the bigger the mess (S. Hunt, 2002).

California and Texas are an example of zonal pricing. The systems aggregate nodes with little congestion into

e locational marginal pricing. Likewise, PJM started with zonal pricing and since April of 1998 changed to zonal pricing due to the inefficiencies showed by the first system. (Méndez, 2002) Transmission Rig The physical approacmFiona Woolf (2003) points out that the burden on the SO of a complex network would be considerable in ensuring that each physical transaction scheduled was accompanied by exactly matching physical rights.

The problem for market participants is to match their physical rights with actual transactions when they make last minute changes.

e of their rights and would not obtain access to the transmission system. Market participants would be discouraged from entering into more profitable transactions or more efficient dispatch if it meant having to change their physical rights at short notice. (F. Woolf, 2003) Moreover, a market participant may use physical transmission rights to exclude its competitors from using the transmission system. This problem may be solved by implementing use-it-or-lose-it rules but again the participant will face the problem of last minute changes explained before.

Hogan (2002a) explains that the institutional framework needed for physical rights to work would have to provide contin

ure many individual capacity reservations. Moreover, he points out that the information requirements and transaction costs would be daunting.

Furthermore, because of the laws of physics and the fact that the power wilin a manner that can be physically directed by the SO, the assig

s impossible It has generally been accepted that the most efficient answer for the SO is to ignore who owns what rights and instead dispatch a plant in a manner that ensures that the entire transmission system is used most efficiently. Financial rights are the means to do so; they act as if they were tradable physical rights that are automatically traded by the SO assigning it to the users who place the highest value on them. Financial transmission rights entitle the holder to the differencccorresponding to the number of rights that it holds. The funds to pay these rights come form the surplus generated by the SO while charging market participants for congestion. Normally traders would want the rights between locations where they typically buy and sell energy. In this way the payment they receive from their rights would serve as a perfect hedge for the congestion payments they make to the SO. Other advantages of FTRs are:

• They can provide a degree of price insurance for load serving entiti

property rights • They encourage market participants to make transmission expansion investments as

described earlier• They can lower the incentives for investing in inefficient transmission.

They help to deal w

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ctions held by the SO. The market

articipants (generators, distributors, retailers and large customers) place their price offers or bids

place in most of the markets currently trading FTRs is known as retail ccess or customer choice. This Model permits all customers to choose their suppliers, so that

roblems with Merchant Transmission Expansion

FTRs are normally acquired through periodical aup

for FTR which, together with the requests for quantities of energy injected and withdrawn at particular nodes, enter into a dispatch model that includes all potential constraints on the transmission system for satisfying the simultaneous feasibility test. The test involves ensuring that the quantity of rights issued never exceeds the quantity of physical transactions that can be accommodated on the transmission system under expected system conditions. The FTRs of existing transmission facilities are usually allocated to the holders of existing transmission contracts and load serving entities for an interim period, after which they are required to participate in a mandatory auction for all rights. If the transmission facilities are in the hands of a single stat-owned company there would be an initial auction for these rights. Afterwards, auctions are normally held on a weekly, monthly or yearly basis. The existence of secondary markets may make FTR trading more liquid. Financial rights may be in the form of obligations or options. An obligation entitles the holder to receive or pay the difference in nodal prices, while options hedge the holder to pay when de difference in prices are negative. The problem with options is that they may not allow for the fullest possible use of counterflows in managing congestion and maximizing the use of the transmission system. Markets of FTRs The model put inacompeting generators can sell to anyone, although small customers usually buy through aggregators or retailers. In the wholesale market generators, distribution companies (Distcos), retailers, and large customers trade electricity constrained to the SO which operates under a bid-based, security-constrained, economic dispatch with locational marginal cost pricing. This model also contemplates the existence of a retail marketplace where Distcos, Retailers and customers trade electricity. The basic idea is that it pulls through the benefits of a competitive wholesale market by allowing many competing retailers to pressure generators into better prices, and to offer deeper and more liquid markets for financing new plants. (see Figure 4) Figure 4. Retail Competition Model

CUSTOMER

IPP IPPIPP

TRANSMIS WIRES

SION

WHOLESALE MARKETPLACE

IPP

RETAILERDISTCOS / RETAILER

RETAILER DISTCOS / RETAILER

IPP

CUS

SYSTEM OPERATOR

P

TOMER CUSTOMER CUSTOMER

DISTRIBUTIONRETAIL MARK

WIRES ETPLACE

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According to Joskow and Tirole (2003), the merchant transmission model theory has enerally assumed simple cases where transmission investments have no increasing returns to

ey demons

ere will be incentives to reduce the capacity

hey have massive economies of scale. Once the land has been pu

hip of the transmi

nd are non-stochastic. In practice, even in the two-node m

Moreover, it is sh

gscale; there are no sunk cost or asset specificity issues; nodal energy prices fully reflect consumers’ willingness to pay for energy and reliability; all network externalities are internalized in nodal prices; transmission network constraints and associated point-to-point capacity is non-stochastic; there is no market power; markets are always cleared by prices; there is a full set of futures markets; and the transmission owner (TO) or system operator (SO) have no discretion to affect the effective transmission capacity and nodal prices over time.

Under these assumptions, Hogan (1992), and Bushnell and Stoft (1996, 1997) have written the primary foundation for relying on the merchant transmission model. Th

trated that efficient transmission investments that create simultaneous feasible transmission rights are profitable. Nonetheless, they recognize that relaxing these assumptions undermines key results regarding optimality of merchant transmission. Furthermore, Perez-Arriaga (1995) and Joskow and Tirole (2003), among others, have helped highlight the problems that arise when assuming more realistic cases:

[Market power] Assuming the existence of market power among generators of a certain importing location with capacity constraints, th

on the network in order to raise prices. This behavior will give the market over-incentives to invest in transmission.

[Lumpiness] On the other hand, there will be sub-incentives to invest because some transmission investments are lumpy; t

rchased and the towers built, there isn’t much difference in cost between a low and a high capacity line. For theses reasons, when built, transmission investments tend to eliminate congestion. This may contradict the model since in the absence of congestion the value of the transmission rights awarded to the investor for the expansion will have no value. This is not a problem per se because the investment may be of great value to cheap isolated generators that gained access to a bigger market and the possibility to sell power at the same price as everyone else. The problem is the existence of strong incentives for free riding. Cheap generators will be better off waiting and hoping that someone else makes the investment. Joskow and Tirole (2003) also demonstrate that lumpiness may make merchant investment occur too early when it takes place in order to pre-empt additional entry. In a system with growing demand, pre-emption leads to an investment at the first date at which the discounted value of financial rights on the additional capacity is equal to the investment cost.

[Asymetric information] Joskow and Tirole (2003) also show the existence of a moral-hazard-in-teams problem caused by the separation of dispatching and owners

ssion network. An outage, for example, can be claimed to result from poor line maintenance or from imprudent dispatch.

[Contingencies]Moreover, the merchant investment model assumes that the capacities of the transmission lines are well defined a

odel, the actual capacity of the link depends on exogenous environmental parameters and other exogenous contingencies that may call into question the viability of the system. In response, Hogan (2003), states that most of these contingencies are foreseen in a security-constrained dispatch in a meshed network with loops and parallel paths. He recognizes that contingencies outside the control of the SO could lead to a revenue inadequacy of FTRs, but assures that such cases do not describe the most important contingency conditions.

[Loop Flows] Additionally, Bushnell and Stoft (1997) show that in a network with loop flows, an addition in transmission capacity might have negative social value.

own that a transmission expansion may turn the prevailing allocation of rights infeasible. To solve this problem they suggest that the investor takes rights that have negative values. Hogan (2002a) analyzes this issue and makes a preliminary attempt to provide some general axioms to properly define long term (LT) FTRs. He suggests that under non-fully allocation of FTRs in the grid, the awarding of incremental LTFTRs should satisfy some basic criteria: a) they should remain simultaneously feasible even if certain unallocated rights (proxy awards) are preserved, b) investors should maximize their objective function, and c) their awarding process should apply for increases and decreases in the grid capacity. Bushnell

11

and Stoft (1996, 1997) show that under these conditions the allocation of new point-to-point FTR obligations will not reduce social welfare. However, Hogan explains that the definition of proxy awards is not straightforward (see Hogan, 2002a). Performance of FTR Markets The United States decided to open access for wholesale trading of electricity with The Energy

olicy Act of 1992 (EPACT), and set the general rules for energy trading in 1996 through

ission ghts in the form of obligations and options. There are four ways to purchase FTRs in this

ive some rights and obligations. They receive FTRs form the inje

ce between two points. Firm ustome

ice consisting of network integration service and firm point-to

an be traded to create new FTRs. PJM members and transmission service custome

mission congestion contracts (TCC) in September 999. TCCs are financial instruments for hedging against transmission congestion fees. The

POrder No. 888, but retail access and the deregulation of generation was left in the hands of the states. The big states and the tight pools of the Northeast historically had some of the highest prices, which gave them incentives to reform. The tight pools, now the ISOs, of Pennsylvania, New Jersey, Maryland and New York, changed their pricing rules and allowed merchant generators to sell power to the pool under the same terms as the utilities. In these markets everything was fairly straightforward to arrange given the history of pooling (Hunt, 2002). However, California and Texas were different stories. These states were large enough to take deregulation initiatives within their own borders, and had to invent a new trading system from scratch. Next, I will present a survey of the markets for FTRs around the United States. The market of Pennsylvania, New Jersey, and Maryland (PJM) uses financial transmrimarket: network integration service, firm point-to-point transmission service, monthly FTR auctions and secondary markets.

All load serving entities (LSEs) must buy network integration service for all their loads; in exchange, the LSEs rece

ction point, or the interconnection point with an external control area, to the withdrawal point for the aggregate load; and they have the obligation to identify the production capacity that will deliver peak-load plus 20 percent. The request of FTRs is annual, and modifications are allowed at any time. Network customers can choose combinations up to an amount equal to their peak load and can freely add and subtract FTRs as long as the amount of the outstanding FTR is feasible (Kristiansen, 2004) Firm point-to-point transmission service FTRs can be purchased by paying a fixed fee that basically equals the entrance fee for a network servic rs may receive FTRs for their transmission reservations and their bilateral contracts. In this case, it is also necessary for PJM to approve the proposed FTRs based on the simultaneous feasibility test (SFT).

There are also long term rights, called auction revenue rights or ARRs that are allocated to firm transmission serv

-point transmission service. ARRs are acquired for one year and are allocated for the entire capability of the transmission system. ARR holders are entitled to the price difference between the sink and the source prices established in the FTR auction times the number of ARRs they hold. ARRs can be converted into FTRs by scheduling the FTR into auctions on the exact same path as the ARR. FTRs are also awarded to those who invest in transmission expansion, to the extent that the expansion allows FTRs that are simultaneously feasible with the existing ones.

After the initial allocation of FTRs, an auction is held where any existing FTR or residual capacity c

rs can submit bids to purchase residual FTRs and submit offers to sell existing contracts, and the ISO determines the winning offers and bids for capacity by maximizing the total surplus without violating SFT. The SFT decides the number of possible FTRs by calculating a market price for each node, selecting the highest bid-based value combination of feasible FTR paths. The price of an FTR path is the difference between the injection and the withdrawal-point market clearing price. The New York market introduced trans1

12

contracts are settled in a day-ahead market in which locational prices are calculated based on an AC network with marginal losses. Nonetheless TCCs are only a hedge against congestion. The contracts are unidirectional and they become an obligation with reverse congestion (Kristiansen, 2004). In contrast to PJM, in New York the acquisition and trading of TCCs can only be made through auctions and secondary markets. The initial allocation of TCCs was also

Cs aves l

correctly most of the time, but the market does not appear

alifornia have one financial and one physical aspect. Contracts give the holder e right to transfer power and to receive the potential share in the distribution of usage charge

he day-ahead market, but they do not afford exclusive rights. This allows

butes these revenues to sellers of FTRs and auction revenue ghts holders. ARRs are awarded to entities paying for transmission upgrades, which make it

ansmission grid is congested in the day-ahead market, and differences in day-ahe

different. While PJM initially allocated the rights to network integration service customers, New York converted the existing transmission agreements into either grandfathered rights or grandfathered TCCs that in a second stage should be converted into TCCs. The revenues from these market auctions as well as the revenues received from the sale of TCCs are credited against the transmission owner’s cost of service to reduce the transmission service charge. Each TCC has a specific source and sink. This creates considerable diversity in the TCCs that can be formulated and limits the trading of TCCs because such diversity in TCle ess of a chance that one party will have the exact TCCs that another party desires. To address the diversity issue the New York market decided to unbundle TCCs into standard components. The belief was that by unbundling TCCs into a) TCCs from source to zone containing the source, b) TCCs from source zone to sink zone, and c) TCCs form source zone to source, they would be easier to sell. The auctioned volumes of TCCs after this unbundling showed an increase of 120 percent in the next year (2001) and of an additional 50 percent the following year (Kristiansen, 2004). Siddiqui et al. (2003) analyze the performance of TCCs for 2000 and 2001. They find that TCC buyers predict congestion efficient at hedging complex transactions; buyers pay prices including an excessive risk premium. Likewise, arbitrage of price differences might not be possible because of liquidity risk aversion. The FTRs in Cthrevenues collected by the ISO due to congestion between two predefined areas (Kristiansen, 2004). In this market the owner of an FTR receives the contract quantity times the shadow price on available transmission capacity on a specific flowgate associated with a transaction in the day-ahead market when the congestion is in the same direction as specified in the contract. However FTRs do not entitle owners to usage charges generated by counterscheduling. The physical aspect of the FTRs gives the owner priority in the scheduling of energy across interfaces in tthe ISO to allocate the outstanding capacity in the real-time power markets. FTRs are provided in an annual auction and have a one-year duration. FTRs can also be traded in secondary markets and in the hour-ahead markets. The surplus from the auction goes to the owners of the transmission lines to cover a part of fixed costs in order to reduce the connection fees for customers. The New England market distriripossible to award additional FTRs and allocate them to the entities responsible for paying congestion charges.

In this market the FTRs entitle the holder to receive compensation for congestion fees that arise when the tr

ad locational marginal prices result from the dispatch of generators to relieve congestion. These FTRs function as obligations on a monthly base. If the monthly total of the positive FTR target allocation is less than the transmission congestion rent, the holders receive a congestion credit. In the opposite case the holders receive shares of the monthly congestion revenues proportional to their total positive target allocations.

13

ERCOT, the Texas market, implemented a direct-assigned allocation method for settlement of

ong-term contractual commitment for annual capacity and energy

oskow (2003) comments that the development of well-functioning competitive wholesale

eneration vestm

What w

he California crisis raised many questions about the convenience of deregulating the electric

(2002b) states that California had the most prominent market design built on

zonal congestion costs. The ERCOT market does not contain a spot market; it is only a bilateral and ancillary service market. However ERCOT annually identifies relatively small number of commercially significant transmission constraints (CSCs). There are transmission congestion rights (TCRs) associated with these CSCs that entitle the holder to receive remuneration from ERCOT for congestion fees. These contracts are in the form of options that take only positive values. Their clearing price is determined through a single round auction held by ERCOT ISO, and equals the corresponding shadow price of the marginal TCR awarded on that CSC. Revenues from these auctions are credited to load entities in proportion to their load ratio share.

Entities that own or have a lfrom a specific remote generation unit have access to another type of congestion rights:

the pre-assigned congestion rights (PCRs). PCRs exempt the holder from a certain amount of congestion payment. About 20 percent of the rights are assigned as PCRs at reduced prices to municipally-owned utilities and electric cooperatives that have grandfathered rights to the transmission system (Kristiansen, 2004). Jmarkets and retail markets for electricity in the U.S. has encountered more problems and proceeded less quickly than anticipated. He states that the most visible success to date has been the substantial investment in generating capacity, and the shifting of the associated construction costs, operating performance, and market risks to suppliers rather than to consumers as under regulation. Retail customers in a number of states have benefited from lower regulated prices as a component of restructuring programs, although the direct benefits have been limited and were primarily addressed to the largest electricity consumers. The merchant transmission model has not proved to be effective. While gin ent grew enormously during the last few years, transmission investment has been declining. Transmission congestion has grown steadily over the last several years. PJM state of the market reports from 2001 to 2003 show congestion costs increased from US$53 million in 1999 to US$499 million in 2003, while similar reports show an increase of congestion costs in the New York market of nearly 122%. (NYISO, 2003). Many argue that this situation is due to local Nimby (Not In My Backyard) opposition. However, many transmission investments do not involve opening up major new transmission corridors or significantly expanding the footprint of the transmission network. Joskow (2003) points out that the sub-investment in the network comes from a failure of FERC’s conceptualization of congestion management. He argues that ISOs do not have the people, trucks, materials, money, or financial incentives needed to fully manage congestion. An ISO is limited to allocating scarce transmission capacity based on current constraints. Moreover, FTRs have not given the incentives to the market to invest in transmission, although they have served to provide hedge against differences in nodal prices to market participants and helped address market power problems. Joskow also argues that there is too little response in the demand side because few, if any consumers actually see LMPs.

ent wrong in California?

Tindustry and became the natural argument for deregulation opponents around the world. The spot market prices grew by up to 10 times historical levels, the state system suffered from shortages and subsequent rolling blackouts, and Pacific Gas and Electric (state’s biggest utility), the Power Exchange, and a number of small power producers went bankrupt. What went wrong? Hoganthe fallacy that the special characteristics of the electricity transmission grid were just details that could be ignored when designing the market. One of the major problems in designing the Californian trading arrangements for the electric market was that the process was highly

14

politicized. Hunt (2002) mentions that they built a bridge voting where the girders should go. One defining trading-arrangement mistake was that significant portions of the transmission grid remained under the control of operators other than the independent system operator (CAISO). A further mistake was the creation of the California Power Exchange (PX) as an entity separate from the ISO. This separation posed serious coordination issues between the two entities and duplicated functions, thereby creating immense inefficiency, and many opportunities for arbitrage. Furthermore, there was no provision of demand response, directly or by proxy, in setting the prices. The legislature imposed a temporary frozen rate that impeded the exposure of customers to the market price of energy. However, there was no transition from frozen retail prices so that the demand bidding that had at one point been part of the design of the trading arrangements lost all meaning. Thus, the wholesale prices were virtually uncontrolled and the utilities were not able to hedge against spot prices because they were required to divest about half of their fossil generation, and they were not allowed to enter into bilateral contracts for the purchase of power. Moreover they were also taking the entire risk of increases in input prices.

These arrangements, combined with the increase of gas and environmental permit prices,

. Restructuring the Electric Industry in Mexico

efore coming to the transmission business model I will go through some basic aspects that

le market would help to avoid this problem. For such a market to work, a set of trading arrangements that would imply some restructuring of the

an increase in demand, and low hydro supply, led to credit problems for the utilities. Some of them went bankrupt and generators (afraid of the utilities’ credit situation) withheld supply from the system leading to worse shortages, higher prices and five rolling blackouts. In the meantime, five big independent generators in California were ranked in Standard and Poors’ top 10 for 2000 with earnings that in some cases had quadrupled. This situation could have been prevented with the pass through of cost increases, adequate hedging of wholesale prices, and demand responsiveness. 3 Bshould be considered in the restructuring of the electric industry in Mexico to introduce the use of financial transmission rights. As mentioned in section 2, the Mexican electric sector reflects a vertical integrated industry, developed mainly by the state owned companies the CFE and LyFC. There exists a small participation of social and private generators primary for self-supply or to the delivery to the CFE as a single buyer. A single buyer model (see Figure 5.1) is a step further to competition than that of a vertically integrated monopoly. This model was first adopted in the late seventies in the United States to enable public utilities to purchase power from small generators, and has become the first step, among many countries, to liberalization and as a way of attracting much needed investment by private capital. The single buyer model requires long-term contracts to reduce risk posed to investors by the existence of a single buyer. Without a contract, investors would be running the risk of being beaten back to marginal costs in price negotiations and wouldn’t have the incentives to invest in generation capacity. These contracts represent a major problem to the model for several reasons. IPP contracts in Mexico, transfer the market risk, technology risk, and most of the credit risk from investors to the CFE and thus to consumers. Moreover, the contracts are generally two-part covenant in which IPPs are paid an annual fee to cover fixed costs along with amounts designed to cover the variable costs for each unit of power generated. The problem here is how to get the plants to run if they are paid their profits in advance in the fixed charges, or, if the profits are paid in the variable payments, how to get the plants to stop running when they are not needed. Secondly, IPP contracts are usually specified by purchaser as to technology, fuel, and location, but this limits the effectiveness of competition, which often achieves efficiency by finding new technologies, fuels, and locations. Finally, the CFE’s IPP contracts are made non-dispachable (outside the control of the SO), because the independent generators fear that the SO would discriminate against them while dispatching. However, non-dispachable contracts can only work for a few relatively small plants, or the SO will lose control of the system.

The existence of a wholesa

15

industry

lesale Competition Model

E needs to completely separate the ownership of system operation and transmission

om generation. In this way, investors would loose its fear of dispatch discrimination on the

structure in the market if it were to begin after 2004 and the CFE were to divid

are needed. CFE has taken this into account and, in the absence of a political agreement for the industry, is moving toward a process of internal structural change to improve efficiency and prepare for competition. The CFE designed a scheme in which the company is divided into twenty independent business units: six generation, one transmission and thirteen distribution companies. As part of this internal change, the CFE designed a shadow electricity model. This model was created in 1997 and redesigned in 2000 to improve transparency in internal operations and administration, to measure the efficiency of the generation and distribution units, and to provide and develop the rules and abilities to operate in an open market environment. To implement a market of financial transmission rights this restructuring has to go a step forward.

Figure 5. Single Buyer Model and Who

Supply

CUSTOMER

IPP

1. Single Buyer Model 2. Wholesale

The CFfrpart of the SO, and IPP contracts could cease to be non-dispachable. The separation of transmission and generation is also a key factor to inhibit an improper use of the national transmission system by the CFE to exercise market power. All generators should have open access to transmission. Yet, even with open access there is the risk of market power issues in the existence of dominant suppliers that could benefit by the rise of prices caused by withdrawing capacity. However, with the demand growth expected by CFE entrants would be able to have around 50% of the market in the next eight years if they simply met the load growth in México. It is worth noting that 73% of the new projects planed for the period 2004-2013 are going to be combined cycle, thus merchant generators would be able to enter the market. (Sener, 2004)

Using simple concentration indexes, Marcelino Madrigal (2002) shows that there could be a competitive

e its six generation business units into different independent companies by 2010. However he warns that such moves would not suffice to assure the existence of a power market. Therefore, it would be necessary for the regulatory agency to monitor the market and ensure the existence of enough competitors by making entry easier, through divestiture, by relieving transmission constraints, and by allowing plants to close if they are not economically viable, together with a price-responsive demand side. Hunt (2002) refers to price caps, bidding restrictions and profit controls as non desirable mechanisms for avoiding market power issues, though she recognizes that they may serve as transitional measures. Demand

GEN (CFE) IPP

SINGLE BUYER (CFE)

DISTRIBUTION (CFE)

CUSTOMER CUSTOMER

IPP IPP

CUSTOMER

DISTCOS (CFE)

CFE TRANSMISSION WIRES WHOLESALE MARKETPLACE

Competition Model

GEN (CFE)

GEN (CFE)

DISTCOS (CFE)

16

The Mexican electric industry would have to allow multiple buyers into this wholesale market order to make demand side non-monopsonic. This could be achieved, initially by

le market

del such as the one performing in the markets of PJM, New York, and New ngland has been shown to be the least flawed means to make competition work in electricity.

helping the indu

rch has been devoted to analyzing and proposing

lternative models for the electric industry in Mexico, but there has been little interest in

inseparating the CFE´s 13 distribution companies (Distcos) into independent players while retaining the monopoly over all the smaller final customers (see Figure 5.2). With many buyers, generators would no longer require long term contracts with the CFE. Consequently, the market risk, technology risk, construction cost risk, and the entire credit risk would be taken by investors. Distcos would purchase power competitively in the wholesale market and resell it to customers at regulated prices. Therefore, Distcos would have the right incentives to purchase at lower cost, and customers would be offered predictable prices. In order to avoid the problems seen in California, Distcos should be allowed to hedge against input price variations and differences in nodal prices, and there would have to be a mechanism to provide demand responsiveness. Hourly metering together with a price structure that exposes customers to higher prices during peak demand could be one way to achieve this. Another way could be to have interruptible customers who agree to be cut off when wholesale prices are too high, or in the event of a shortage, near shortage, or for short term stability reasons.

FTRs could serve as hedges for differences in nodal prices, and, in some way, to supplant the long-term contracts of the CFE with IPPs, because in a competitive wholesa

FTRs encourage participants to enter into long-term generation or purchase arrangements because they hedge the uncertainty of transmission usage charges. Trading Model An integrated moEMexico’s Centro Nacional de Control de Energía (CENACE) currently operates a shadow market similar to the ISOs in the markets referred to above. Its functions would be to buy energy on behalf of consumers; provide and charge for transmission and ancillary services, and proportion the necessary dispatch in order to maintain a constant balance between demand and supply subject to the constraints of the system. CENACE uses the day-ahead and spot markets to determine energy prices, and the payment to be made to producers and service providers. The participants in this shadow market are the generation, transmission and distribution units of the CFE and LyFC; the self-supply companies that sell their surplus to the CFE or that use the CFE’s transmission network; and foreign producers and consumers that trade energy with Mexico. Under this model, the shadow market acts like a pool where all electricity that is traded is injected and extracted. On the one hand, the prices of energy are determined for each node according to the marginal price in each hour, and on the other hand, the prices of capacity are determined according to the incremental cost of expanding generation and guaranteeing the recovery of the generators’ fixed and variable costs.

However, CFE’s shadow market is not a real wholesale market for electricity, it is only used to evaluate the performance of the company’s business divisions, and it is

stry become accustomed to a wholesale market. Moreover, it is providing a history of pooling that could enable regulators to understand the characteristics of the Mexican industry in order to design the model that best suits the market.

4. Transmission Expansion in Mexico

Much academic and institutional reseaaproviding the proper incentives needed to solve short-term congestion problems, recover long-term fixed costs, and expand the transmission network. (Carreón and Rosellon, 2002; Rosellon, 2003; and Instituto de Investigaciones Eléctricas, 2003 are some exceptions) Instituto de Investigaciones Eléctricas (2003) proposed a transmission charge based on the benefit-factor methods of Rubio-Odériz and Pérez-Arriaga (2000). This method considers complementing a variable charge with a charge based according to the economic benefit that each transmission network facility provides each agent. Yet the model only considers positive

17

benefits. However, Rosellon (2003) believes that this approach presents serious implementation hurdles due to the subjectivity in the allocation of benefits. He explains that the non-negative-benefits assumption is inappropriate since Hogan (2002c) shows that negative benefits could occur during transmission expansion projects due to the power flow nature. Alternatively, Rosellón (2003) proposes a second-best pricing scheme for the Mexican transmission network combining merchant and regulatory mechanisms for electricity transmission expansion in the understanding that there is no optimal mechanism. Under this scheme small transmission expansion relies on the merchant approach while large and lumpy projects are developed through incentive regulation. He suggests that an LTFTR method should be used within meshed transmission regions, while a price-cap rule could be applied to develop the large and lumpy links among such regions. He assumes that large links joining transmission regions are ‘approximately node-to-node radial lines’. Furthermore, he shows that under such conditions the best institutional structure for expanding the Mexican transmission grid would be one of a single transmission firm that charges an even tariff structure throughout the Mexican territory. Nonetheless, he recognizes that this method is difficult to implement due to the difficulty in defining electricity transmission output or throughput.

Currently, CFE centrally plans the needed investments and, on an annual basis, divides the costs among all the industry. I will now evaluate the potential use of FTRs in the Mexican elec

ransmission Expansion in Mexico

adow market during 2004. With a mean of S$52.67 per MWh, nodal prices show great fluctuation during the year. The minimum

mpeche, Cozumel, Chetum

igure 6. CFE’s nodal prices for 26 transmission regions during 2004

tric industry to hedge market participants and create incentives to expand the transmission network. Merchant T Figure 6 shows nodal prices from CFE’s shUstandard deviation is 9.91 for CENTRAL-node while the maximum is 19.65 for CAMPECHE-node. On the one hand there are fluctuations that correspond to exogenous variables like changes in input prices or temperatures that affect all prices equal. This kind of movement can be seen for 2004 form January to April, and could be hedged by market participants through long term arrangements of purchase and generation.

On the other hand, fluctuations between nodal prices, like the ones shown from August to December, are due to congestion. The high prices in Ca

al and Yucatan arise from the transmission constraints linking these nodes with the rest of the network. FTRs could be used to perfectly hedge these differences if, for example, a Distco in a low price node buying from a generator at a high price node holds a point-to-point FTR obligation for the same path. Although the Distco has to pay for congestion rent between the nodes, he will be entitled to receive that same amount as revenue from the FTR.

F

18

Source: CFE

o evaluate the use of financial transmission rights I take the model showed in Figure 9 in

igure 7. Demand in each Node

Twhich there are 26 transmission regions, 80 generators and 35 transmission lines between nodes. Demand is assumed to be made by one independent Distco at each node. Distcos must acquire all the power needed to fulfill demand at the wholesale market. Demand is distributed at each node as Figure 7 shows. F

The supply curve is made by listing in merit order (from least expensive (right) to most

igure 8. Merit Order

expensive (left)). In the absence of transmission constraints the price in all nodes should be US$26.54 per MWh. (see Figure 8) F

19

fter taking into account the demand per node, the cost of generation and capacity of every

igure 9. A 26-Node Model for the Mexican Transmission System

Aplant, and the transmission constraints of the grid assuming no losses in transmission I solve the problem of providing the least expensive energy to every node as a way to maximize social welfare. F

he transmission lines between node 6 and 8, 9 and 11, 15 and 17, 15 and 16, 17 and 19, and

igure 10. Annual Incentives to Invest

T25 and 25 are congested. They are impeding the buyers at nodes 8, 9, 12, 15, and 17

to acquire cheaper electricity from other nodes and thus creating incentives for them to build generating plants within their transmission region or invest in a transmission expansion. Figure 10 shows the amount that buyers are paying in excess for having congestion. F

20

Node Congeted Lines Cost of congestion CENTRAL ( 7) (1 ) .60 Node 1 7 - 19 and 15 - 17 $784,709,901GUADALAJARA (Node 15) (15 - 16) $ 33,856,569.60 MONTERREY (Node 9) (9 - 11) $ 17,179,944.22

In 2004 the total payment of demand was 2.088 billion dollars greater than the income perceived by generators during the same period. This amount could have been awarded to the owners of the corresponding FTRs. Under these assumptions FTRs show to be a significant incentive to invest in the transmission grid in Mexico considering that the required investment in transmission for 2005 according to CFE are around 1.334 billion. However this should not be taken as a conclusion since the model is only a simplification of the real transmission grid. Notwithstanding, we can state that the use of FTRs in the Mexican market could not only hedge market participants from differences in nodal prices, but provide incentives to invest and signal where the investment should be directed. References

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Bu Incentives for Electric Grid Investment,

Ca sector eléctrico mexicano:

CF

B

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