Texas Capacity Market on Hold

During 2013, the competitive power market participants in the Electric Reliability Council of Texas (ERCOT) watched a debate unfold: Should regulators create incentives to stimulate construction of new generating plants or should market forces alone determine when, where and how much new generation is to be built?

In January 2014, the Texas Public Utilities Commission (PUC) decided on a 2-1 vote to endorse the replacement of the “target reserve margin” of 13.75% with a mandatory reserve margin of 15%. The PUC would manage the capacity market. But on 28 March, the PUC put the debate on hold until the Texas legislature weighs in during 2015. About 85% of the electricity generated and sold in Texas occurs in the region called ERCOT where most customers can choose their electric supplier. Generators are paid only for the kilowatt hours they produce. In anticipation of the competitive market, new combined cycle plants were built that drove many of the older plants into retirement. This was supplemented by a $7.9 billion investment in transmission called CREZ (Competitive Renewable Energy Zone), a project that has enabled construction of 11,000 MW of wind turbines in the Texas panhandle.

But today, there is concern that ERCOT may soon be short of generating reserves. Power consumption in Texas usually peaks during the first two weeks in August. This high demand window often makes or breaks the financial performance of a generating company. These companies say that there are not enough “scarcity hours” to provide the profit margin needed to stay in business, let alone build new generation capacity. Most generators would prefer a capacity payment similar to the (Pennsylvania, New Jersey, Maryland Interconnection (PJM) market.

PJM is the largest regional transmission operator in the U.S. In PJM, forward capacity auctions are held every two years. All of the winning bidders receive a monthly capacity payment during the next two years if their plant is kept in good running condition, even if never called upon to run. The underlying premise is to incentivize investment in new generation and to delay premature retirement of plants that still run reliably but are only marginally profitable.

It all boils down to the reliability of the grid. Having a higher capacity reserve margin does not necessarily produce a meaningful increase in system reliability. How much more would you pay for your electricity if the annual outage time was reduced by 1.7 minutes? Or to say it another way, if the reliability of supply to you was reduced by 0.0003%? Would you pay an extra 5% on your monthly electric bill? How about 1%? There is no single correct answer since different customers will have different values for reliability.

The debate is healthy. But one thing seems certain. The 1960s rule of thumb setting 20% as a prudent reserve margin has gone the same route as drive-in movies. As smart meters and a demand response are used more effectively, maybe the new normal reserve margin will become closer to 10%.