Utility executives face volatile energy markets, skyrocketing fuel prices, and changing federal energy policies. How are utilities benefiting from the turnaround in energy trading?
Capacity Markets Demystified
Emerging capacity auctions offer limited but valuable risk-management tools for asset owners.
Energy revenue is subject to volatility risks for both the price and volume of production. Price volatility can be measured based on historical observation. Volumetric risks take into account the overall market demand for electric energy and the relative competitive position of each power plant. Energy revenue ultimately translates into a gross margin (energy revenue minus production cost), and at that point the volatility on underlying fuel prices also becomes a major risk factor.
• Potential Capacity: There are no ICAP markets in the United States outside the PJM, ISO-NE and NY ISO markets. While some regions’ administrators are discussing potential future capacity markets, such discussions inherently are too speculative to rely on at this point. In these non-ICAP markets, payments for capacity typically are realized either through bilateral contracts or Reliability Must Run (RMR) payments from a central market authority, e.g. , the California ISO. In the case of bilateral contracting, there is significant competitive risk. This can arise from:
1) Supply and Demand: When a market’s installed capacity exceeds the installed capacity requirement (peak demand plus reserve margin) by even a small amount, the value of capacity can fall to very low levels. When power-plant owners have to compete to serve a market smaller than the available supply, competition quickly drives down the PPA value of capacity from full replacement cost to its option value in the energy market. In this scenario the reliability value of capacity is near zero.
2) “Falling off the cliff:” Once all reliability needs are met for a specific period of demand, there can be a world of winners and losers. The winners have secured their PPAs, while the losers (those who failed to secure contracts) have essentially a zero reliability capacity value until the next round of capacity purchasing.
• Administrative Capacity: Admittedly, a market’s willingness to pay ICAP to power plants demonstrates some revenue certainty compared to markets without ICAP. And the demand-curve constructs in PJM and NYISO were designed to mitigate the sudden value drop-off seen when capacity exceeds installed-capacity requirements. Still, those U.S. regions with existing ICAP markets are experiencing many changes in their administration. And these markets set ICAP prices for a relatively short time frame in comparison to the expected life of a new asset. So even though these are existing markets, future ICAP revenue streams are speculative as to the details of how they will be administered and how prices will be set, all of which creates risk for investors.
So, contrary to much conventional wisdom, capacity revenues are not the great risk reducers some would like to believe they are, and in non-ICAP markets capacity revenues even are less certain than the energy revenues. The counterpoint to these risks is that, in the long run, there must be some mechanism for allowing new power-plant investors to have a reasonable expectation of receiving their investment costs and making an acceptable return on their investments. This can be done with an ICAP market (of which there can be many different designs), reliance on bilateral contracts, enforcement of resource adequacy