Contracting for Power in a Deregulated Market

December 05, 2001

Clients who have begun shopping for new electricity suppliers to serve them January 1, 2002 when the Electric Reliability Council of Texas (“ERCOT”) market opens to competition need to be aware of recent regulatory developments aimed at modifying important aspects of the market shortly after it opens. These changes may dramatically affect the cost of  their  contracts for electric service provision.

These events are particularly important to clients that have facilities which, either singly or as aggregated load, exceed 1 mW.  These customers are some of the most sought after customers in the new market because they use large amounts of electricity.  For these clients, their largest single cost of doing business is almost always the price per kwh of electricity consumed.  As clients take advantage of competition, several terms and conditions of their contracts may be more important than the ultimate price for power.

In examining a retail power contract many clients first look to the ultimate price per kwh.  However, what that price includes or does not include is more representative of the actual benefits of the contract.  Key to this analysis is how the agreement provides for payment of congestion management fees, ancillary service charges, qualified scheduling entity fees, independent system operator fees, transmission and distribution wires charges, scheduling penalties for requirements outside of the stated bandwidth, and costs associated with failure of delivery.  Although virtually any aspect of the charge could amount to a great deal of additional cost to you as a customer, we will focus on congestion management charges which will, by regulation, be substantially modified in February.

A careful review of any retail electric provider (“REP”) agreement includes the particular method for payment of congestion management fees.  These fees currently are socialized to all users of the grid, however, by February the congestion management system will be changed to a “zonal” approach.  The zonal approach requires direct assignment of congestion costs to entities scheduling in a manner that creates such costs, rather than allowing all customers to bear the costs on a load ratio share basis.  Two types of congestion costs that must be accounted for in contracts today are the intrazonal and interzonal congestion costs.

Many agreements currently in negotiation do not contemplate the change in congestion cost calculation, even though the term of the agreement far exceeds the February date for moving to zonal congestion management.  Where the charges listed in a particular retail supply agreement are itemized without reference to congestion, these costs are likely to be  passed through to the customer.  For ERCOT, in four months, the aggregate congestion costs, including costs associated with the lack of penalties in the ERCOT protocols for overscheduling which operates to create congestion (referred to as BENA or balancing energy neutrality adjustment charges) have amounted to $96 million.

Only a REP can reduce these costs under a zonal congestion system, as they are related to the manner in which electricity is scheduled.  Additionally, the Public Utility Commission has stated a preference for a third mechanism, nodal congestion pricing.  Contracts signed today should provide clear language for all three types of congestion cost assignment mechanisms.  Given the risk associated with these costs, congestion provisions should be carefully scrutinized.

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