State and federal incentives provide the carrot for utilities to invest in grid intelligence. But regulatory and technological incentives are not enough without customer participation. Smart-grid...
No Generator Left Behind
A new theory on capacity markets and the missing money.
On Wednesday May 7, the Federal Energy Regulatory Commission (FERC) will host a conference in Washington, D.C. that might prove extraordinary. The commission staff promises not only to review the forward capacity markets now operating in New England and PJM—each a story unto itself—but also to discuss a new rate-making theory that has come virtually out of nowhere and which proposes to help solve the notorious “missing money” problem (see sidebar, “I’ll Take the Blame.”)
This new theory, thought up essentially by one person (a utility lawyer, no less), seeks to harness recognized quirks in predictive human behavior to better define and manage the most important single financial risk in the electric industry today. That risk, present in all areas of the country where independent power producers are active, concerns the fixed costs (financing, construction, site permitting, etc.) of adding new generating capacity to the power grid. The risk remains pervasive because, for political reasons, the market operators at RTOs and ISOs (with exceptions in Texas and the Midwest) generally prevent peak-period energy prices from rising high enough above marginal operating costs for power-plant owners to recoup all or even a portion of their fixed costs.
The theory’s architect is attorney Donald J. Sipe (Preti, Flaherty, Beliveau & Pachios, Augusta, Maine), who has long represented the American Forest and Paper Association before the FERC.
Sipe is a perpetually curious student of behavioral economics. He delights in discovering the mysteries of markets. For example, why is it that a typical stock market investor will behave differently when offered twin chances to lose money or earn an equal gain, even if the risks are the same? How do economists explain such behavior? Can regulators apply this wisdom to regional capacity markets?
Armed with such quaint notions, Sipe developed an entirely new electric industry contract (an option, really) that he calls a “financial performance obligation” (FPO). He offers this construct as a superior method of pricing the fixed-cost risk.
Paying for Scarcity
For regulators, at least, the allure of capacity markets is easy to grasp. Without such a market or a separate capacity payment, plant owners would be forced to recover all fixed costs through the energy price. That’s the so-called “energy-only market,” now being tried in Texas (in ERCOT) and at the Midwest Independent System Operator (MISO). That suggests that regulators must allow scarcity pricing during shortage periods that reflects the value of lost load (VOLL).
An EO market means that the probability of lost load (LOLP) must equal the cost of building a new plant (the gross cost of new entry, or CONE) divided by VOLL. Assume a target LOLP of one day (24 hours) every ten years. Assume also that it costs about $72 per kilowatt-year to build a new plant that will operate on the margin in RTO markets (more than likely, an aero-derivative simple-cycle gas-fired combustion turbine). You’ll find that VOLL