Trading arrangements define how business transactions are performed to allow energy, reserves, and other ancillary services to be acquired by market participants.
In a vertically integrated market structure, the provision of these services is typically handled by the utility or, for small utilities, through a contract with a nearby larger utility. In regions that have implemented more competitive market structures, the acquisition of energy, reserves, and other ancillary services becomes a function of market transactions. Given the physical complexity of the electrical system, these functions cannot be left to chance. Regulators and legislators must carefully devise market-based arrangements to ensure that participants can efficiently acquire needed energy and that system operations can efficiently acquire reliability resources. The rules that determine how markets provide the necessary services are called trading arrangements.
Trading arrangements answer the following questions:
The three basic ways of structuring trading arrangements are wheeling, decentralized, and integrated. Each is described below:
Wheeling
Trading arrangements under wheeling are applicable only to the vertically integrated utility and the single-buyer electric market models. Under the wheeling method, each utility schedules its own generation plus any purchased power in the day ahead based on the utility’s load forecast. Ancillary services are scheduled by the utility from its own generation or are acquired by the utility from nearby utilities or IPPs through bilateral agreements (a bilateral agreement is simply a private contract between two parties). Generation, purchased power, and ancillary services are scheduled in an integrated manner to provide the lowest-cost service subject to transmission and other constraints.
Imbalances between scheduled generation and loads in real time are managed by the utility’s system operator who simply ramps up or down utility-owned or contracted units that the operator has under control. The transmission system is made available for use by parties who wish to wheel power (i.e. move the power across the utility transmission system for delivery to a neighboring utility) on an open-access basis but only to the extent that wheeling transactions do not impact the utility’s service to its own customers (native load). Transmission services and any necessary ancillary services are made available to the wheeling parties under regulated tariff rates. Long-term capacity adequacy is ensured by utilities with oversight by regulators. The wheeling model is currently used in areas where there is no Independent System Operator (ISO).
Decentralized
The decentralized method is one of two ways of structuring trading arrangements that are applicable to competitive markets with independent generators, an Independent System Operator (ISO), or a Transmission System Operator (TSO), and end users able to buy directly from marketers. The decentralized model moves as far away from the concept of a centralized market as is possible. An ISO or TSO is still required to handle scheduling, acquisition of ancillary services, access to transmission, and management of the system in real time. But in this model, the ISO or TSO is seen mostly as a scheduler and an arbiter of free markets. For electricity bought and sold for future periods (forward markets), all contracts are simply bilateral agreements between generators and end users or entities that supply end users (load serving entities or LSEs).
In some markets, a separate entity called a Power Exchange (PX) is created to facilitate trading. To obtain access to transmission, entities wishing to move power (known as scheduling coordinators) submit to the ISO or TSO balanced schedules that match specific supply to specific loads for each hour. Upon receiving the schedules for a specific hour, the ISO or TSO runs its power flow model to determine whether all requested schedules are feasible. If not, transmission congestion exists, and access to transmission is allocated by an auction or other established methodology.
Necessary ancillary services, in amounts that meet reliability criteria, are either self-supplied by each scheduling entity or are acquired from the market by the ISO or TSO on behalf of the customers. Customers who do not supply their own ancillary services pay their pro-rata share of ancillary services costs to the ISO or TSO in an ancillary services charge. The ISO or TSO manages the system in real time using offers from market participants willing to increase or decrease supply or usage in response to price. Entities who create an imbalance in real time (meaning they either have more or less generation than they do demand on the system among their generator/customer pool) are charged/paid an after-the-fact imbalance price that is based on the prices paid to the units or load ramped up or down in real time. Under this model there is no provision to ensure long-term capacity adequacy — it is assumed markets will provide the right amount.
The decentralized method was initially used by two markets in the U.S. – California and Texas. But they have since transitioned to the integrated model. The decentralized model is used extensively in Europe.
Integrated
The integrated method is the second methodology that can be applied to competitive markets. This method attempts to strike a balance between the complexity of the decentralized method and the lack of competition in the wheeling method. It recognizes the benefits of centralized markets and supply dispatch while creating ways for competition to be taken into account in the operation of centralized markets.
Under the integrated method, the historical concept of a power pool is modified into the concept of an Independent System Operator (ISO) that operates day-ahead and real-time energy markets, ancillary services markets, and performs other system operations functions. The ISO may also facilitate a voluntary or mandatory capacity market. The ISO is responsible for scheduling units in the day ahead, allocating transmission, scheduling reserves and other ancillary services, and balancing supply and demand in real time. Rather than running each of these as a separate and distinct market as is done in the decentralized method, the ISO operates all the markets in one integrated, optimized fashion.
Basically, the ISO uses the old system operations model from the vertically integrated utility days, which created optimized schedules subject to system constraints. But it replaces the model cost inputs (marginal cost in the utility days) with bids placed by market participants. Owners of units bid for what they wish to be paid to operate during a given hour and also what they wish to be paid to provide reserves. Suppliers of loads bid for what they are willing to pay to receive power during a given hour and, if they have flexible loads, what they would need to be paid to adjust their loads in real time.
Typically, the ISO runs a day-ahead energy and reserves market that matches supply to demand given the price bids, then minimizes overall system costs subject to constraints by creating a system schedule. If there are constraints on the transmission system, the ISO determines which units will be dispatched at what levels based on their bids. Locational prices are created and users of constrained transmission paths incur a congestion cost based on the difference in prices between the two locations (this is called locational marginal pricing). In real time, the ISO manages imbalances through a real-time market that ramps units up or down or reduces loads based on bid price. Under this model the ISO may also run a short- or long-term capacity market to ensure sufficient generation is built.