Starting December 1, 2010, if all goes as planned, the way power is bought and sold in most of Texas will change dramatically, with implications for how Texas businesses buy power from their retail electric providers.

The Electric Reliability Council of Texas (ERCOT) runs the high voltage transmission grid for about 85% of the state, including areas like Dallas, Houston, and Corpus Christi.  ERCOT is currently transitioning the way it operates the system, dispatches generation, and prices electricity from a "zonal" system to a "nodal" system.

The current zonal system is pretty straightforward.  The ERCOT electric grid is broken up into four "zones" based on geography and power flows.  Each zone has a unique price for electricity, representing the cost for power plants in that region to generate power.

The new nodal system will replace the four basic zones with some 8,200 new "nodes" for operating the grid.  Each of these nodes will have a unique price reflecting the cost of local generators near the node, or the cost to transmit power to the node.  In constrained regions of the grid (cities like Houston and Corpus Christi), where the local generation is old and inefficient (meaning expensive) and there's not enough transmission capacity to import cheaper power, prices at the nodes are expected to be much higher than outlying areas where transmission and generation is plentiful.

Whether Texas customers actually pay higher prices depends on their contract with their retail electric provider, and how the electric provider takes into account pricing at the customer's node.

There's more to the new system than just the introduction of thousands of nodes, however.  One of the biggest changes in a new "day-ahead" market, which allows power buyers and sellers to trade one day into the future.  The idea is to give power buyers and sellers a snapshot of what tomorrow's market will look like, providing them with an opportunity to line up supplies to cover expected needs, and provide price discovery and transparency.

Participating in the day-ahead market isn't mandatory, and there's concern that there may be some barriers which are discouraging retail electric providers from participating in the day-ahead market.  One of the biggest obstacles is the enormous amount of credit which must be posted by a retail electric provider to trade in the day-ahead market.  To avoid collateral costs, some retail electric providers may elect to just operate in the "real-time" market, and opt not to line up supplies a day ahead of time.

But the risks of not participating in the day-ahead market are high.  If a retail electric provider, for example, does not commit enough capacity in the day-ahead market to cover its load, it is exposed to ERCOT's backstop procurement process, known as Reliability Unit Commitment (RUC).  Generating units brought online under the Reliability Unit Commitment process are generally older, less efficient plants that were not economic to operate based on market conditions, but now have to come online to meet demand.  Because these units are much more expensive, retail electric providers exposed to the RUC end up paying higher costs for power -- costs they may attempt to pass onto their customers.

RUC costs are only one possible new pass-through which customers should be aware of in their retail contracts.  The nodal system is bringing a host of new risks to the market which retail electric providers may try to get the customer to bear, such as the risk that prices diverge between points known as "trading hubs," where the electric provider does its hedging, and "load zones," which is where the electric provider has an obligation to serve the customer.  If there's congestion on the grid between these two points, the cost to supply a customer with power may spike -- a cost the electric provider may try to pass on to the customer.

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