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15.2 Defining a Competitive Framework
Preparing for Competition • Present View of Overall Problem • Economic Evolution • Market Structure • Fully Evolved Marketplace • Computerized Auction Market Structure • Capacity Expansion Problem Definition
15.4 Other Sections on Planning
Capacity expansion decisions are made daily by government agencies, private corporations, partnerships, and individuals. Most decisions are small relative to the profit and loss sheet of most companies. (Aggarwal, 1993; Bussey, 1981; Daellenbach, 1984). However, many decisions are sufficiently large to determine the future financial health of the nation, company, partnership, or individual. Capacity expansion of hydroelectric facilities may require the commitment of financial capital exceeding the income of most small countries. Capacity expansion of thermal fossil fuel plants is not as severe, but does require a large number of financial resources including bank loans, bonds for long-term debt, stock issues for more working capital, and even joint-venture agreements with other suppliers or customers to share the cost and the risk of the expansion. This section proposes several mathematical optimization techniques to assist in this planning process. These models and methods are tools for making better decisions based on the uncertainty of future demand, project costs, loan costs, technology change, etc. (Binger, 1998). Although the material presented in this section is only a simple model of the process, it does capture the essence of real capacity expansion problems.
This section relies on a definition of electric power industry restructuring presented in Sheblé (1999). The new environment within this work assumes that the vertically integrated utility has been segmented into a horizontally integrated system (Ilic, 1998). Specifically, generation companies (GENCOs), distribution companies (DISTCOs), and transmission companies (TRANSCOs) exist in place of the old. This work does not assume that separate companies have been formed. It is only necessary that comparable services are available for anyone connected to the transmission grid.
As can be concluded, this description of a deregulated marketplace is an general version of the commodity markets. It needs polishing and expanding. The change in the electric utility business environment is depicted generically below. The functions shown are the emerging paradigm. This work outlines the market organization for this new paradigm.
Attitudes toward restructuring still vary from state to state and from country to country. Many electric utilities in the United States have been reluctant to change the status quo. Electric utilities with high rates are very reluctant to restructure since the customer is expected to leave for the lower prices. Electric utility companies in regions with low prices are more receptive to change since they expect to pick up more customers. In 1998, California became the first state in the United States to adopt a competitive structure, and other states are observing the outcome. Some offer customer selection of supplier. Some offer markets similar to those established in the United Kingdom, Norway, and Sweden, but not Spain. Several countries have gone to the extreme competitive position of treating electricity as a commodity as seen in New Zealand and Australia (Outhred, 1993). As these markets continue to evolve, governments in all areas of the world will continue to form opinions on what market, operational, and planning structures will suit them best.
15.2 Defining a Competitive Framework
There are many market frameworks that can be used to introduce competition between electric utilities. Almost every country embracing competitive markets for its electric system has done so in a different manner. The methods described here assume an electric marketplace derived from commodities exchanges like the Chicago Mercantile Exchange (CME), Chicago Board of Trade (CBOT), and New York Mercantile Exchange (NYMEX) where commodities (other than electricity) have been traded for many years. NYMEX added electricity futures to their offerings in 1996, supporting this author’s previous predictions (Sheblé, 1991, 1992, 1993, 1994) regarding the framework of the coming competitive environment. The framework proposed has similarities to the Norwegian-Sweden electric systems. The proposed structure is partially implemented in New Zealand, Australia, and Spain. The framework is being adapted since similar structures are already implemented in other industries. Thus, it would be extremely expensive to ignore the treatment of other industries and commodities. The details of this framework and some of its major differences from the emerging power markets/pools are described in Sheblé (1999).
These methods imply that the ultimate competitive electric industry environment is one in which retail consumers have the ability to choose their own electric supplier. Often referred to as retail access, this is quite a contrast to the vertically integrated monopolies of the past. Telemarketers are contacting consumers, asking to speak to the person in charge of making decisions about electric service. Depending on consumer preference and the installed technology, it may be possible to do this on an almost real-time basis as one might use a debit card at the local grocery store or gas station. Real-time pricing, where electricity is priced as it is used, is getting closer to becoming a reality as information technology advances. Presently, however, customers in most regions lack the sophisticated metering equipment necessary to implement retail access at this level.
Charging rates that were deemed fair by the government agency, the average monopolistic electric utility of the old environment met all consumer demand while attempting to minimize their costs. During natural or man-made disasters, neighboring utilities cooperated without competitively charging for their assistance. The costs were always passed on to the rate payers. The electric companies in a country or continent were all members of one big happy family. The new companies of the future competitive environment will also be happy to help out in times of disaster, but each offer of assistance will be priced recognizing that the competitor’s loss is gain for everyone else. No longer guaranteed a rate of return, the entities participating in the competitive electric utility industry of tomorrow will be profit driven.
15.2.1 Preparing for Competition
Electric energy prices recently rose to more than $7500/MWh in the Midwest (1998) (Midwest ISO, website) due to a combination of high demand and the forced outage of several units. Many midwestern electric utilities bought energy at that high price, and then sold it to consumers for the normal rate. Unless these companies thought they were going to be heavily fined, or lose all customers for a very long time, it may have been more fiscally responsible to terminate services.
Under highly competitive scenarios, the successful supplier will recover its incremental costs as well as its fixed costs through the prices it charges. For a short time, producers may sell below their costs, but will need to make up the losses during another time period. Economic theory shows that eventually, under perfect competition, all companies will arrive at a point where their profit is zero. This is the point at which the company can break even, assuming the average cost is greater than the incremental cost. At this ideal point, the best any producer can do in a competitive framework, ignoring fixed costs, is to bid at the incremental cost. Perfect competition is not often found in the real world for many reasons. The prevalent reason is technology change. Fortunately, there are things that the competitive producer can do to increase the odds of surviving and remaining profitable.
The operational tools used and decisions made by companies operating in a competitive environment are dependent on the structure and rules of the power system operation. In each of the various market structures, the company goal is to maximize profit. Entities such as commodity exchanges are responsible for ensuring that the industry operates in a secure manner. The rules of operation should be designed by regulators prior to implementation to be complete and “fair.” Fairness in this work is defined to include noncollusion, open market information, open transmission and distribution access, and proper price signals. It could call for maximization of social welfare (i.e., maximize everyone’s happiness) or perhaps maximization of consumer surplus (i.e., make customers happy).
Changing regulations are affecting each company’s way of doing business and to remain profitable, new tools are needed to help companies make the transition from the old environment to the competitive world of the future. This work describes and develops methods and tools that are designed for the competitive component of the electric industry. Some of these tools include software to generate bidding strategies, software to incorporate the bidding strategies of other competitors, and updated common tools like economic dispatch and unit commitment to maximize profit.
15.2.2 Present View of Overall Problem
This work is motivated by the recent changes in regulatory policies of inter-utility power interchange practices. Economists believe that electric pricing must be regulated by free market forces rather than by public utilities commissions. A major focus of the changing policies is “competition” as a replacement for “regulation” to achieve economic efficiency. A number of changes will be needed as competition replaces regulation. The coordination arrangements presently existing among the different players in the electric market would change operational, planning, and organizational behaviors.
Government agencies are entrusted to encourage an open market system to create a competitive environment where generation and supportive services are bought and sold under demand and supply market conditions. The open market system will consist of GENCOs, DISTCOs, TRANSCOs, a central coordinator to provide independent system operation (ISO), and brokers to match buyers and sellers (BROCOs). The long-term planning has been separated under the organization known as regional transmission organization (RTO). The energy market exchange has been absorbed into the ISO instead of being a separate energy mercantile association (EMA). The energy contracts segmented to the distribution companies are often partially segmented to energy service suppliers (ESS), which may include energy service companies (ESCOs) or energy management companies (EMCOs). The services offered to the customers are not different from the traditional average pricing as of this writing. However, the impact of the smart grid is expected to change this dramatically. The interconnection between these groups is shown in Figure 15.1.
The ISO is independent and a dissociated agent for market participants. The roles and responsibilities of the ISO in the new marketplace are yet not clear. This work assumes that the ISO is responsible for coordinating the market players (GENCOs, DISTCOs, and TRANSCOs) to provide a reliable power system functions. Under this assumption, the ISO would require a new class of optimization algorithms to perform price-based operation. Efficient tools are needed to verify that the system remains in operation with all contracts in place. This work proposes an energy brokerage model for all services as a novel framework for price-based optimization. The proposed foundation is used to develop analysis and simulation tools to study the implementation aspects of various contracts in a deregulated environment.
FIGURE 15.1 New organizational structure.
Although it is conceptually clean to have separate functions for the GENCOs, DISTCOs, TRANSCOs, and the ISO, the overall mode of real-time operation is still evolving. Presently, two possible versions of market operations are debated in the industry. One version is based on the traditional power pool concept (POOLCO). The other is based on transactions and bilateral transactions as presently handled by commodity exchanges in other industries. Both versions are based on the premise of price-based operation and market-driven demand. This work presents analytical tools to compare the two approaches. Especially with the developed auction market simulator, POOLCO, multilateral, and bilateral agreements can be studied.
Working toward the goal of economic efficiency, one should not forget that the reliability of the electric services is of the utmost importance to the electric utility industry in North America. In the words of the North American Electric Reliability Council (NERC), reliability in a bulk electric system indicates “the degree to which the performance of the elements of that system results in electricity being delivered to customers within accepted standards and in the amount desired. The degree of reliability may be measured by the frequency, duration, and magnitude of adverse effects on the electric supply.” The council also suggests that reliability can be addressed by considering the two basic and functional aspects of the bulk electric system—adequacy and security. In this work, the discussion is focused on the adequacy aspect of power system reliability, which is defined as the static evaluation of the system’s ability to satisfy the system load requirements. In the context of the new business environment, market demand is interpreted as the system load. However, a secure implementation of electric power transactions concerns power system operation and stability issues:
1. Stability issue: The electric power system is a nonlinear dynamic system comprised of numerous machines synchronized with each other. Stable operation of these machines following disturbances or major changes in the network often requires limitations on various operating conditions, such as generation levels, load levels, and power transmission changes. Due to various inertial forces, these machines, together with other system components, require extra energy (reserve margins and load following capability) to safely and continuously actuate electric power transfer.
2. Thermal overload issue: Electrical network capacity and losses limit electric power transmission. Capacity may include real-time weather conditions as well as congestion management. The impact of transmission losses on market power is yet to be understood.
3. Operating voltage issues: Enough reactive power support must accompany the real power transfer to maintain the transfer capacity at the specified levels of open access.
In the new organizational structure, the services used for supporting a reliable delivery of electric energy (e.g., various reserve margins, load following capability, congestion management, transmission losses, reactive power support, etc.) are termed supportive services. These have been called “ancillary services” in the past. In this context, the term “ancillary services” is misleading since the services in question are not ancillary but closely bundled with the electric power transfer as described earlier. The open market system should consider all of these supportive services as an integral part of power transaction.
This work proposes that supportive services become a competitive component in the energy market. It is embedded so that no matter what reasonable conditions occur, the (operationally) centralized service will have the obligation and the authority to deliver and keep the system responding according to adopted operating constraints. As such, although competitive, it is burdened by additional goals of ensuring reliability rather than open access only. The proposed pricing framework attempts to become economically efficient by moving from cost-based to price-based operation and introduces a mathematical framework to enable all players to be sufficiently informed in decision-making when serving other competitive energy market players, including customers.
Some economists speculate that regional commodity exchanges within the United States would be oligopolistic in nature (having a limited numbers of sellers) due to the configuration of the transmission system. Some postulate that the number of sellers will be sufficient to achieve near-perfect competition. Other countries have established exchanges with as few as three players. However, such experiments have reinforced the notion that collusion is all too tempting, and that market power is the key to price determination, as it is in any other market. Regardless of the actual level of competition, companies that wish to survive in the deregulated marketplace must change the way they do business. They will need to develop bidding strategies for trading electricity via an exchange.
Economists have developed theoretical results of how variably competitive markets are supposed to behave under varying numbers of sellers or buyers. The economic results are often valid only when aggregated across an entire industry and frequently require unrealistic assumptions. While considered sound in a macroscopic sense, these results may be less than helpful to a particular company (not fitting the industry profile) that is trying to develop a strategy that will allow it to remain competitive.
GENCOs, energy service suppliers (ESSs), and DISTCOs that participate in an energy commodity exchange must learn to place effective bids in order to win energy contracts. Microeconomic theory states that in the long term, a hypothetical firm selling in a competitive market should price its product at its marginal cost of production. The theory is based on several assumptions (e.g., all market players will behave rationally, all market players have perfect information) that may tend to be true industrywide, but might not be true for a particular region or a particular firm. As shown in this work, the normal price offerings are based on average prices. Markets are very seldom perfect or in equilibrium.
There is no doubt that deregulation in the power industry will have many far-reaching effects on the strategic planning of firms within the industry. One of the most interesting effects will be the optimal pricing and output strategies generator companies (GENCOs) will employ in order to be competitive while maximizing profits. This case study presents two very basic, yet effective means for a single generator company (GENCO) to determine the optimal output and price of their electrical power output for maximum profits.
The first assumption made is that switching from a government regulated, monopolistic industry to a deregulated competitive industry will result in numerous geographic regions of oligopolies. The market will behave more like an oligopoly than a purely competitive market due to the increasing physical restrictions of transferring power over distances. This makes it practical for only a small number of GENCOs to service a given geographic region.
The strongest force in the economic evolution is the demand for electricity. Customerdemand was assumed to be inelastic under many of the early market analysis studies. This ignored the success of demand side management in the regulated environment (Le et al., 1983; Cohen et al., 1987; Mortensen and Haggerty, 1990; Lee and Chen, 1992; Chu et al., 1993; Rupanagunta et al., 1995; Wei and Chen, 1995; Kurucz et al., 1996) and the cost reduction noticed by industrial and commercial customers (Bentley and Evelyn, 1987; Chen and Sheen 1993). Such asset flexibility is a large leverage in the management of the risk with portfolio management tools used in the competitive market. The drive to install smart grid components provide the infrastructure for demand side management as well as for distributed generation.
FIGURE 15.2 Business environmental model.
Although nobody knows the exact structure of the emerging deregulated industry, this research predicts that regional exchanges (i.e., electricity mercantile associations [EMAs]) will eventually play an important role. Electricity trading of the future will be accomplished through bilateral contracts and EMAs where traders bid for contracts via a double auction. The electric marketplace used in this section has been refined and described by various authors. Fahd and Sheblé (1992) demonstrated an auction mechanism. Sheblé (1994b) described the different types of commodity markets and their operation, outlining how each could be applied in the evolved electric energy marketplace. Sheblé and McCalley (1994) outlined how spot, forward, future, planning, and swap markets can handle real-time control of the system (e.g., automatic generation control) and risk management. Work by Kumar and Sheblé (1996b) brought the above ideas together and demonstrated a power system auction game designed to be a training tool. That game used the double auction mechanism in combination with classical optimization techniques.
In several references (Kumar, 1996a, 1996b; Sheblé 1996; Richter 1997a), a framework is described in which electric energy is only sold to DISTCOs, and electricity is generated by GENCOs (see Figure 15.2). The NERC sets the reliability standards. Along with DISTCOs and GENCOs, ESCOs, ancillary services companies (ANCILCOs), and TRANSCOs interact via contracts. The contract prices are determined through a double auction. Buyers and sellers of electricity make bids and offers that are matched subject to approval of the independent contract administrator (ICA), who ensures that the contracts will result in a system operating safely within limits. The ICA submits information to an ISO for implementation. The ISO is responsible for physically controlling the system to maintain its security and reliability. As of this writing, the ISO has integrated the functions of EMA, MARKCO, and BROCO within itself.
The ESS provide basic or extended services to the customers. ESCOs have provided minimal contracts simply to provide energy. EMCOs provide contracts and services to reduce the costs of energy. The advent of the smart grid enables customers to participate on the hourly transactions and pay by time of use instead of average price. Market companies (MARKCO) enable anyone to invest in the energy markets, especially speculators. Speculators already exist at most trading companies but the general public is not able to participate as in the other commodity markets. Until the general public is enabled to enter the markets, brokerage companies (BROCOs) are not needed.
15.2.5 Fully Evolved Marketplace
The following sections outline the role of a horizontally integrated industry. Many curious acronyms have described generation companies (IPP, QF, Cogen, etc.), transmission companies (IOUTS, NUTS, etc.), and distribution companies (IOUDC, COOPS, MUNIES, etc.). The acronyms used in this work are described in the following sections.
15.2.5.1 Horizontally Integrated
The restructuring of the electric power industry is most easily visualized as a horizontally integrated marketplace. This implies that interrelationships exist between generation (GENCO), transmission (TRANSCO), and distribution (DISTCO) companies as separate entities. Note that independent power producers (IPP), qualifying facilities (QF), etc. may be considered as equivalent generation companies. Nonutility transmission systems (NUTS) may be considered as equivalent transmission companies. Cooperatives and municipal utilities may be considered as equivalent distribution companies. All companies are assumed to be coordinated through a regional Transmission Corporation (or regional transmission group).
15.2.5.2 Federal Energy Regulatory Commission (FERC)
FERC is concerned with the overall operation and planning of the national grid, consistent with the various energy acts and public utility laws passed by Congress. Similar federal commissions exist in other government structures. The goal is to provide a workable business environment while protecting the economy, the customers, and the companies from unfair business practices and from criminal behavior. GENCOs, ESCOs, and TRANSCOs would be under the jurisdiction of FERC for all contracts impacting interstate trade.
15.2.5.3 State Public Utility Commission (SPUC)
SPUCs protect the individual state economies and customers from unfair business practices and from criminal behavior. It is assumed that most DISTCOs would still be regulated by SPUCs under performance-based regulation and not by FERC. GENCOs, ESCOs, and TRANSCOs would be under the jurisdiction of SPUCs for all contracts impacting intrastate trade.
15.2.5.4 Generation Company (GENCO)
The goal for a generation company, which has to fill contracts for the cash and futures markets, is to package production at an attractive price and time schedule. One proposed method is similar to the classic decentralization techniques used by a vertically integrated company. The traditional power system approach is to use Dantzig–Wolfe decomposition. Such a proposed method may be compared with traditional operational research methods used by commercial market companies for a “make or buy” decision.
15.2.5.5 Transmission Company (TRANSCO)
The goal for transmission companies, which have to provide services by contracts, is to package the availability and the cost of the integrated transportation network to facilitate transportation from suppliers GENCOs to buyer ESCOs. One proposed method is similar to oil pipeline networks and energy modeling. Such a proposed method can be compared to traditional network approaches using optimal power flow programs.
15.2.5.6 Distribution Company (DISTCO)
The goal for distribution companies, which have to provide services by contracts, is to package the availability and the cost of the radial transportation network to facilitate transportation from suppliers GENCOs to buyers ESCOs. One proposed method is similar to distribution outlets. Such proposed methods can be compared to traditional network approaches using optimal power flow programs. The disaggregation of the transmission and the distribution system may not be necessary, as both are expected to be regulated as monopolies at the present time.
15.2.5.7 Energy Service Supplier (ESS), Energy Service Company (ESCO), Energy Management Company (EMCO)
A primary tool of the ESS company is to implement demand side management (DSM) to control demand not only to reduce the peak demand but also to provide flexibility for risk management, for alternative ancillary service sources, and for other more complex risk and service enterprises (Daryanian et al., 1989; Ng and Sheblé, 1998; Lee and Chen, 1992, 1993, 1994). A secondary tool is the availability of distributed generation with natural gas micro turbines, wind generators, and solar cells. The advent of more biofuels will provide more flexibility of hybrid diesel automobiles as distributed generation. The eventual implementation of the hydrogen economy as methane gas (hydrogen combined with CO2) will extend the use of distributed generation with cost-effective storage of CH4 for micro turbines and hybrid automobiles (Sheblé, 1999a,b).
The goal for energy service companies, which may be large industrial customers or customer pools, is to purchase power at the least cost when needed by consumers. One proposed method is similar to the decision of a retailer to select the brand names for products being offered to the public. Such a proposed method may be compared to other retail outlet shops.
15.2.5.8 Independent System Operator (ISO)
The primary concern is the management of operations. Real-time control (or nearly real-time) must be completely secure if any amount of scheduling is to be implemented by markets. The present business environment uses a fixed combination of units for a given load level, and then performs extensive analysis of the operation of the system. If markets determine schedules, then the unit schedules may not be fixed sufficiently ahead of realtime for all of the proper analysis to be completed by the ISO.
15.2.5.9 Regional Transmission Organization (RTO)
The goal for a regional transmission group, which must coordinate all contracts and bids among the three major types of players, is to facilitate transactions while maintaining system planning. One proposed method is based on discrete analysis of a Dutch auction. Other auction mechanisms may be suggested. Such proposed methods are similar to a warehousing decision on how much to inventory for a future period. As shown later in this work, the functions of the RTG and the ISO could be merged. Indeed, this should be the case based on organizational behavior.
15.2.5.10 Independent Contract Administrator (ICA)
The goal for an ICA is a combination of the goals for an ISO and an RTG. Northern States Power Company originally proposed this term. This term will be used in place of ISO and RTG in the following to differentiate the combined responsibility from the existing ISO companies.
15.2.5.11 Energy Mercantile association (EMA), Market Company (MARKCO), Brokerage Company (BROCO)
Competition may be enhanced through the various markets: cash, futures, planning, and swap. The cash market facilitates trading in spot and forward contracts. This work assumes that such trading would be on an hourly basis. Functionally, this is equivalent to the interchange brokerage systems implemented in several states. The distinction is that future time period interchange (forward contracts) are also traded.
The futures market facilitates trading of futures and options. These are financially derived contracts used to spread risk. The planning market facilitates trading of contracts for system expansion. Such a market has been proposed by a west coast electric utility. The swap market facilitates trading between all markets when conversion from one type of contract to another is desired. It should be noted that multiple markets are required to enable competition between markets.
The structure of any spot market auction must include the ability to schedule as far into the future as the industrial practice did before deregulation. This would require extending the spot into the future for at least 6 months, as proposed by this author (Sheblé, 1994). Future month production should be traded for actual delivery in forward markets. Future contracts should be implemented at least 18 months into the future if not 3 years. Planning contracts must be implemented for at least 20 years into the future, as recently offered by TVA, to provide an orderly, predictable expansion of the generation and transmission systems. Only then can timely addition of generation and transmission be assured. Finally, a swap market must be established to enable the transfer of contracts from one period (market) to another.
To minimize risk, the use of option contracts for each market should be implemented. Essentially, all of the players share the risk. This is why all markets should be open to the public for general trading and subject to all rules and regulations of a commodity exchange. Private exchanges, not subject to such regulations, do not encourage competition and open price discovery.
FIGURE 15.3 Interconnection between markets.
The described framework (Sheblé, 1996) allows for cash (spot and forward), futures, and planning markets as shown in Figure 15.3. The spot market is most familiar within the electric industry (Schweppe et al. 1988). A seller and a buyer agree (either bilaterally or through an exchange) upon a price for a certain amount of power (MW) to be delivered sometime in the near future (e.g., 10 MW from 1:00 p.m. to 4:00 p.m. tomorrow). The buyer needs the electricity, and the seller wants to sell. They arrange for the electrons to flow through the electrical transmission system. A forward contract is a binding agreement in which the seller agrees to deliver an amount of a particular product in a specified quality at a specified time to the buyer.
A futures contract is further into the future than is the spot market. In both the forward and spot contracts, the buyer and seller want physical goods (e.g., the electrons). A futures contract is primarily a financial instrument that allows traders to lock in a price for a commodity in some future month. This helps traders manage their risk by limiting potential losses or gains. Futures contracts exist for commodities in which there is sufficient interest and in which the goods are generic enough that it is not possible to tell one unit of the good from another (e.g., 1 MW of electricity of a certain quality, voltage level, etc.).
A futures option contract is a form of insurance that gives the option purchaser the right, but not the obligation, to buy (sell) a futures contract at a given price. For each options contract, there is someone “writing” the contract who, in return for a premium, is obligated to sell (buy) at the strike price (see Figure 15.3). Both the options and the futures contracts are financial instruments designed to minimize risk. Although provisions for delivery exist, they are not convenient (i.e., the delivery point is not located where you want it to be located). The trader ultimately cancels his position in the futures market, either with a gain or loss. The physicals are then purchased on the spot market to meet demand with the profit or loss having been locked in via the futures contract.
A swap is a customized agreement in which one firm agrees to trade its coupon payment for one held by another firm involved in the swap. Finally, a planning market is needed to establish a basis for financing long term projects like transmission lines and power plants (Sheblé, 1993).
15.2.6 Computerized Auction Market Structure
Auction market structure is a computerized market, as shown in Figure 15.4. Each of the agents has a terminal (PC, workstation, etc.) connected to an auctioneer (auction mechanism) and a contract evaluator. Players generate bids (buy and sell) and submit the quotation to the auctioneer. A bid is a specified amount of electricity at a given price. The auctioneer binds bids (matching buyers and sellers) subject to approval of the contract evaluation. This is equivalent to the pool operating convention used in the vertically integrated business environment.
FIGURE 15.4 Computerized markets.
FIGURE 15.5 Electric market.
The contract evaluator verifies that the network can remain in operation with the new bid in place. If the network cannot operate, then the match is denied. The auctioneer processes all bids to determine which matches can be made. However, the primary problem is the complete specification of how the network can operate and how the agents are treated comparably as the network is operated closer to limits. The network model must include all constraints for adequacy and security.
The major trading objectives are hedging, speculation, and arbitrage. Hedging is a defense mechanism against loss and/or supply shortages. Speculation is assuming an investment risk with a chance for profit. Arbitrage is crossing sales (purchases) between markets for riskless profit. This work assumes that there are four markets commonly operated: forward, futures, planning, and swaps (Figure 15.5).
Forward Market: The forward contracts reflect short term future system conditions. In the forward market, prices are determined at the time of the contract but the transactions occur at some future time. Optimization tools for short term scheduling problems can be enhanced to evaluate trading opportunities in the forward market. For example, short term dispatching algorithms, such as economic unit commitment dispatch, can be used to estimate and earn profit in the forward market.
Futures Market: A futures market creates competition because it unifies diverse and scattered local markets and stabilizes prices. The contracts in the futures market are risky because price movements over time can result in large gains or losses. There is a link between forward markets and futures markets that restricts price volatility. Options (options contracts) allow the agent to exercise the right to activate a contract or cancel it. Claims to buy are called “call” options. Claims to sell are called “put” options.
A more detailed discussion of an electric futures contract is discussed in Sheblé (1994b). The components include trading unit, trading hours, trading months, price quotation, minimum price fluctuation, maximum daily price fluctuation, last trading day, exercise of options, option strike prices, delivery, delivery period, alternate delivery procedure, exchange of futures for, or in connection with, physicals, quality specifications, and customer margin requirements. The implementation proposals include optimization techniques at the hourly level (or faster) with the unit commitment selection under the GENCO decision domain (Fahd and Sheblé, 1992; Fahd et al., 1992; Smith, 1993; Post et al., 1995) and integrated unit commitment models with optimal power flow dispatches for each hour (Kumar and Sheblé, 1994, 1996a,b; Schweppe et al., 1988; Dekrajangpetch and Sheblé, 1998).
Swap Market: In the swap market, contract position can be closed with an exchange of physical or financial substitutions. The trader can find another trader who will accept (make) delivery and end the trader’s delivery obligation. The acceptor of the obligation is compensated through a price discount or a premium relative to the market rate.
The financial drain inflicted on traders when hedging their operations in the futures market is slightly higher than the one inflicted through direct placement in the forward market. An optimal mix of options, forward commitments, futures contracts, and physical inventories is difficult to assess and depends on hedging, constraints imposed by different contracts, and the cost of different contracts. A clearinghouse such as a swap market handles the exchange of various energy instruments.
Planning Market: The growth of transmission grid requires transmission companies to make contracts based on the expected usage to finance projects. The planning market would underwrite equipment usage subject to the long term commitments to which all companies are bound by the rules of network expansion to maintain a fair marketplace. The network expansion would have to be done to maximize the use of transmission grid for all agents. Collaboration would have to be overseen and prohibited with a sufficiently high financial penalty. The growth of the generation supply similarly requires such markets. However, such a market has been started with the use of franchise rights (options) as established in recent Tennessee Valley Authority connection contracts. This author has published several papers outlining the need for such a market. Such efforts are not documented in this work.
15.2.7 Capacity Expansion Problem Definition
The capacity expansion problem is different for an ESCO, GENCO, TRANSCO, DISTCO, and ANSILCO. This section assumes that the ICA will not own equipment but will only administer the contracts between players. The capacity expansion problem is divided into the following areas: generation expansion, transmission expansion, distribution expansion, and market expansion. ESCOs are concerned with market expansion. GENCOs are concerned with generation expansion. TRANSCOs are concerned with transmission expansion. DISTCOs are concerned with distribution expansion. ANSILCOs are concerned with supportive devices expansion. This author views ancillary services as a misnomer. Such services are necessary supportive services. Thus, the term “supportive” will be used instead of ancillary. Also, since supportive devices are inherently part and parcel of the transmission or distribution system, these devices will be assumed into the TRANSCO and DISTCO functions without loss of generality. Thus, ANSILCOs are not treated separately.
Based on the above idealized view of the marketplace, the following generalizations are made. GENCOs are concerned with the addition of capacity to meet market demands while maximizing profit. Market demands include bilateral contracts with the EMA as well as bilateral contracts with ESCOs or with the ICA. ESCOs are concerned with the addition of capacity of supplying customers with the service desired to maintain market share. ESCOs are thus primarily concerned with the processing of information from marketplace to customer. However, ESCOs are also concerned with additional equipment supplied by DISTCOs or TRANSCOs to provide the level of service required by some customers. ESCOs are thus concerned with all aspects of customer contracts and not just the supply of “electrons.”
The ICA is concerned with the operation of the overall system subject to the contracts between the buyers and the sellers and between all players with ICA. The overall goal of the ICA is to enable any customer to trade with any other customer with the quick resolution of contract enforcement available through mercantile associations. The ICA maintains the reliability of the network by resolving the unexpected differences between the contracts, real operation, and unplanned events. The ICA has the authority, through contracts, to buy generation services, supportive services, and/or transmission services, or to curtail contracts if the problems cannot be resolved with such purchases as defined in these contracts. Thus, the ICA has the authority to connect or disconnect generation and demand to protect the integrity of the system. The ICA has the authority to order new transmission or distribution expansion to maintain the system reliability and economic efficiency of the overall system. The economic efficiency is determined by the price of electricity in the cash markets on a periodic basis. If the prices are approximately the same at all points in the network, then the network is not preventing customers from getting to the suppliers. Similarly, the suppliers can get to the buyers. Since all buyers and suppliers are protected from each other through the default clauses of the mercantile agreement, it does not matter which company deals with other companies as the quick resolution of disputes is guaranteed. This strictness of guarantee is the cornerstone of removing the financial uncertainty at the price of a transaction fee to cover the costs of enforcement.
The goal of each company is different but the tools are the same for each. First, the demand must be predicted for future time periods sufficiently into the future to maintain operation financially and physically. Second, the present worth of the expansion projects has to be estimated. Third, the risks associated with each project and the demand-forecast uncertainty must be estimated. Fourth, the acceptable value at risk acceptable for the company has to be defined. Fifth, the value at risk has to be calculated. Sixth, methods of reducing the value at risk have to be identified and evaluated for benefits. Seventh, the overall portfolio of projects, contracts, strategies, and risk has to be assessed. Only then can management decide to select a project for implementation.
The characteristics of expansion problems include
1. The cost of equipment or facilities should exhibit economies of scale for the same risk level baring technology changes.
2. Time is a primary factor since equipment has to be in place and ready to serve the needs as they arise. Premature installation results in idle equipment. Delayed installation results in lost market share.
3. The risk associated with the portfolio of projects should decrease as time advances.
4. The portfolio has to be revalued at each point when new information is available that may change the project selection, change the strategy, or change the mix of contracts.
The capital expansion problem is often referred to as the “capital budgeting under uncertainty” problem (Aggarwal, 1993). Thus, capital expansion is an exercise in estimating the present net value of future cash flows and other benefits as compared to the initial investment required for the project given the risk associated with the project(s). The key concept is the uncertainty and thus the risk of all business ventures. Uncertainties may be due to estimation (forecasting) and measurement errors. Such uncertainties can be reduced by the proper application of better tools. Another approach is to investment in information technology to coordinate the dissemination of information. Indeed, information technology is one key to the appropriate application of capital expansion.
Another uncertainty factor is that the net present value depends on market imperfections. Market imperfections are due to competitor reactions to each other’s strategies, technology changes, and market rule changes (regulatory changes). The options offered by new investment are very hard to forecast. Also the variances of the options to reduce the risk of projects are critical to proper selection of the right project. Management has to constantly revalue the project, change the project (including termination), integrate new information, or modify the project to include technology changes.
Estimates have often been biased by management pressure to move ahead, to not investigate all risks, or to maintain strategies that are not working as planned. Uncertainties in regulations and taxes are often critical for the decision to continue.
There are three steps to any investment plan: investment alternative identification, assessment, selection and management of the investment as events warrant.
Capacity expansion is one aspect of capital budgeting. Marketing and financial investments are also capital budgeting problems. Often, the capacity expansion has to be evaluated not only on the projects merits, but also the merits of the financing bundled with the project.
The regulated industry is structured as a vertically integrated business model. This organization is typified by the structure shown in Figure 15.6. This structure should be compared with the previously defined competitive business environmental model shown in Figure 15.2. The entities previously described function in the same manner in this business model. The difference is that the utility company is an umbrella company or an integrated company with divisions segmented by type of expertise and equipment. All divisions report to the utility and take direction from the utility in all business operations. The utility seeks tariff approval from the state public utility commission and the federal energy regulatory commission. The interchange between utility companies is approved by both FERC and SPUCs. The interchange capabilities and contract approvals are handled by the network reliability management company (NETRELCO), which coordinates network activities between utilities.
FIGURE 15.6 Regulated business environmental model.
Alternative umbrella company structures are in use within the United States. American Electric Power and Southern Company are umbrella companies that own several utilities in several different states within the United States. Due to SPUC regulations and tariff approvals, utilities are located within a state boundary within the United States for ease of accounting and of regulation.
The Mid-America Interpool Network (MAIN) Company was one such network reliability management company that coordinated maintenance and interchange schedules between utilities in the Midwestern part of the United States. MAIN was announced on November 24, 1964, by American Electric Power, Commonwealth Edison, the Illinois-Missouri Pool, the Indiana Power Pool, and the Wisconsin Planning Group. It later became Mid-America Interconnected Network, Inc. and was the first regional electric reliability council. When the North American Electric Reliability Council (NERC) was later formed, MAIN became 1 of the 10 electric reliability councils that comprised NERC. MAIN served the electric utilities in the Midwest for over 41 years.
The need for a NETRELCO was due to the large amount of interchange between utilities. Interchange is beneficial to lower costs each hour (economy a), to lower costs over a number of sequential hours (economy b), and to increase reliability with more inertia and capacity as a response to disturbances (Wood and Wollenberg, 1996). The types of interchange grew quickly justifying more transmission between companies for short- and long-term economic reasons as well as for reliability reasons (Kelley et al., 1987; Winston and Gibson, 1988; Parker et al., 1989; Rau, 1989; Shirmohammadi et al., 1989; Clayton et al., 1990; Happ, 1990; Svoboda and Oren, 1994; Tabors, 1994; Post et al., 1995; Vojdani et al., 1995). Interchange on the east cost of the United States led to pool operation as demonstrated by the formation of the PJM power pool.
An alternative form was the pool company (POOLCO) such as the Pennsylvania-New Jersey-Maryland (PJM) power pool. PJM was formed in 1927 when three utilities, realizing the benefits and efficiencies possible by interconnecting to share their generating resources as if one utility, formed the world’s first continuing power pool. The power pool operated a joint dispatch amongst the utilities for continuous economy, a type of interchange that was operated as if by one company [PJM]. Additional utilities joined in 1956, 1965, and 1981. Throughout this time, PJM was operated by a department of one member utility with contractual interchange agreements to dynamically alter the amounts of interchange and the costs of interchange amongst the participants.
In 1962, PJM installed its first online computer to control generation and dispatch generation with dynamic interchange between the member utility companies. PJM broadcasted a system lambda that each unit used as the economic solution to the overall dispatch of all companies. PJM completed its first energy management system (EMS) in 1968 and included transfer limitations between the member companies using a linear network solution technique. The EMS is the information technology system that makes it possible to monitor transmission grid operations in real time as a NETRELCO. The primary task of a NETRELCO was to study the reliability of the electric power system (Breiphol, 1990; Billinton and Lian, 1991, Billinton and Wenyuan, 1991, Billinton and Gan, 1993, Billinton and Li, 1994). In 1996, PJM launched its first website to provide its members with current system information. PJM transitioned to an ISO in 1997. PJM includes the functions of an ICA, EMA, NETRELCO, and RTO in the competitive environment. The transition of PJM from regulated to competitive market environment is a study of the subtle changes between the two environments.
Dynamic interchange was extended for the joint operation of jointly owned units. Planning solutions in the Midwest section of the United States found that sharing the cost of unit construction and operation was economic (Podmore et al., 1979; Lee, 1988). Such units were called jointly owned units (JOUs) and the interchange between member owners became dynamically dispatched so each member could use the unit for economic operation continuously. The resulting dynamic alteration of a unit’s output led to dynamic interchange between the members, mimicking a power pool with the JOUs. The ultimate JOU in the United States is the Intermountain Power Project (IPP). This JOU installation is owned by over 50 companies. Some of the companies receive the output through dynamic interchange agreements on the Utah-based alternating current (AC) transmission system, others receive the output across the high-voltage direct current (HVDC) link to California.
The Florida Energy Broker was another implementation of a pool type operation for continuous (hourly) economic dispatch of generation within the state of Florida. This organization collected unit bids and asks for auction matching in the 1980s. The resulting matches were implemented by each utility each hour resulting in significant operational savings. As such, this was the first implementation of a competitive environment using an auction mechanism (Cohen, 1982). That implementation was the basis for auction market simulation (Sheblé, 1994a,b).
The planning of utilities under such a business environment has been well documented by general textbooks and papers (Adams et al., 1972; Booth, 1972; Chao, 1983; Merril, 1991; Merril and Wood, 1990; Sullivan, 1977; Wang and McDonald, 1994; Willis, 1996; Seifi and Sepasian, 2001; Li, 2011). The production costing of generation was one of the first computerized planning tools used in both business environments (Baleriaux, 1967; Day, 1971). The application of probabilistic production costing has been one of the most thoroughly researched areas (Lee, F, 1988; Lin et al., 1989; Wang, 1989; Billinton and Lian, 1991; Billinton and Wenyuan, 1991; Billington and Li, 1992; Billington and Gan, 1993; Delson et al., 1991; Huang and Chen, 1993; Pereiran et al., 1992; Lee and Chen, 1992, 1993, 1994; Miranda, 1994; Parker and Stremel, 1996). The other area of intense research is in the area of transaction selection between utilities (Kelley et al., 1987; Winston and Gibson, 1988; Parker et al., 1989; Rau, 1989; Clayton et al., 1990; Happ, 1990; Shirmohammadi et al., 1989; Roy, 1993). The mixed business models used within the United States has spawned a number of mixed tools to provide the benefits of both environments (David and Li, 1993; Krause and McCalley, 1994; Rakic and Markovic, 1994; Post et al., 1995; Vojdani et al., 1995; Wu and Varaiya, 1995; Clayton and Mukerji, 1996; Richter and Sheblé, 1997a, 1997b, 1998). The application of competitive markets compared to traditional regulation has been analyzed but more work is required (Hobbs and Schuler, 1985; Hogan, 1977, Lerner, 1994; O’Neill and Whitmore, 1994; Oren et al., 1994; Oren, 1997; Smith, 1988; Bhattacharya et al., 2001; Loi, 2001).
15.4 Other Sections on Planning
The following sections on planning deal with the overall approach as described by Dr. H. Merrill and include sections on forecasting, power system planning, transmission planning, and system reliability. Forecasting demand is a key issue for any business entity. Forecasting for a competitive industry is more critical than for a regulated industry. Transmission planning is discussed based on probabilistic techniques to evaluate the expected advantages and costs of present and future expansion plans. Reliability of the supply is covered, including transmission reliability. The most interesting aspect of the electric power industry is the massive changes presently occurring. It will be interesting to watch as the industry adapts to regulatory changes and as the various market players find their corporate niche in this new framework.
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