Electricity Pricing—Fair Trade vs. Free Trade—Which is High/Lower

When I got married in 2004, my wife introduced me to the term “Fair Trade” as in fair trade coffee, where coffee growers are paid a price that allows a “living wage” to be paid to the workers on the coffee plantation where the coffee beans were grown.  I quickly realized that Fair Trade could be used to describe the standard regulated electricity market, including a fair rate of return to the investors.  In contrast, the term Free Trade could be used to describe a competitive market, such as the ones then being developed by Independent System Operators (ISOs).  Free Trade could also be used to describe the bulk power markets between large vertically integrated electric utilities, such as when my former employer American Electric Power (AEP) sold electricity to other utilities, whether Commonwealth Edison to its northwest or TVA to its south.  However, both these Free Trade examples have some aspects of Fair Trade, as has been shown by regulators intervening in the Free Trade markets when prices have appeared to be excessive, such as the imposition of caps on the ISO markets.


In 1978, the Federal government implemented a mixed form of Fair Trade/Free Trade for Qualifying Facilities, requiring many utilities to buy electricity at Avoided Cost under the Public Utilities Regulatory Policy Act (PURPA).  In 1984, Ernst & Whinney, my employer at the time, won a contract with the Texas Study Group on Cogeneration to investigate the way Houston Lighting & Power (HL&P) was paying (or not paying) cogenerators for the electricity that was being produced.  I invented the Committed Unit Basis[1] (CUB) for evaluating long term contracts under which utilities bought power from cogenerators.  CUB was adopted by name by the Texas Public Utilities Commission in its regulations and was used to determine the reasonableness of three large cogeneration contracts that HL&P signed over the next year.


CUB develops an inflation adjusted annual revenue requirement for the next generating unit that the utility would build were it not for the presence of the cogeneration plant.  The inflation adjustment results in economic depreciation rates, which could be negative in the first few years of the model.  Thus, not only did CUB reduce the first year payment to a levelized rate below the standard utility model for the revenue requirement, but the first year payment was below even that levelized rate.  The payment escalated with inflation over the life of the contract.


I saw HL&P sign three major contracts in 1984/5 based on CUB.  My analysis suggested that the second and third contracts were for rates that were successively lower than the first contract.  Some suggested that the lower rates reflected the loosening of the market for electricity.  The first contract reflected the full value identified by CUB, while the subsequent markets reflected competition, effectively going from a Fair Trade price to a Free Trade price.  When I subsequently addressed the concept of a competitive market for unscheduled flows of electricity, I concluded that sometimes the Free Trade price needed to be above the Fair Trade price, not always below the Fair Trade price.  This concern was included in the name of my model for a competitive market for electricity, WOLF, or Wide Open Load Following.


The Free Trade/Fair Trade issue comes up most starkly in the discussion of dispatchability, an issue that dramatically affects wind and solar generation.  They are not dispatchable and many argue that they should be paid a price that is lower than the price paid to dispatchable generators, such as gas turbines.  This lower price would be paid to any “as available” wind and solar (as well as many other forms of QF power, such as surplus cogeneration).  But sometimes, the “as available” power happens to occur when it is needed.  Should “as available, as needed” power always be paid a lower price than dispatchable power?  Should there be a way for “as available, as needed” power be made whole relative to the lower prices that they are paid during many of the hours when dispatchability is important?  How can that be done?


WOLF provides a price adjustment to reflect the concurrent need for power.  When load outstrips supply, the price follows the load upward above the standard price for scheduled power.  Conversely, when load is much below supply, the price follows the load downward below the standard price for scheduled power.  For electricity, the standard measure for whether load and supply are in balance on a utility is Area Control Error.  When the utility is synonymous with the entire grid, the standard measure for whether the load and supply are in balancer is frequency error.  Since both ACE and frequency error can be positive or negative, the price adjustment can serve to raise or to lower the settlement price relative to the standard price.


There are times when dispatchable generators fail to meet their obligations and the utility is able to meet its load because of the availability of non-dispatchable generators.  During such times, the value of the non-dispatchable generation is equal to the value of the dispatchable generators, perhaps even more valuable.  WOLF provides a way to set a price based on the value of “as available, as needed” generation.  When there is a shortage, the Free Trade price for “as available, as needed” generation should even exceed the Fair Trade price for dispatchable generation.

[1] Recently I googled “Committed Unit Basis” and had ten hits, including a paper written in Portuguese by Brazilian authors, but I had include the quotation marks to reduce the hits down to ten.

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Mark Lively earned a BS in Electrical Engineering from MIT in 1969 and a MS in Management from MIT Sloan School in 1971. He worked for American Electric Power Service Corporation in New York City from 1971 to 1976 and at Ernst & Ernst, Ernst & Whinney, Ernst & Young in its Washington Utility Group from 1976 to 1991.

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