Business & Money
The consequences of exuberance are all around us.
Much of the 160 GW of new generation capacity added to the U.S. inventory since 1998 is now under water, economically speaking. At a per-megawatt cost of $300, this represents $50 billion of investment-much of which is concentrated in Texas (23 GW), Illinois (14 GW), and Georgia (11 GW). The key question for both merchant and other plant owners is how long it will take for plant values to recover.
Although the value of electric generating capacity has probably bottomed out, the pace and extent of any rebound must be assessed on a county-by-county level. Some areas face an immediate need to build; others have enough generation for the foreseeable future. New capacity will have to be pulled in by clear signals from those in charge of the grids, which will be a varied lot thanks to FERC's diverse treatment of regional wholesale markets.
Investors put $50 billion into new generating capacity because they expected that electricity restructuring would lead to the formation of a small number of effective, regional transmission organizations (RTOs), which would make the location of a generating facility less important in the future. Based on that assumption, developers placed many plants close to a source of fuel, not close to market. For many companies, that has turned out to be a fatal mistake.
Developers and the banks that financed them also expected revenues to come from capacity payments-an expectation that now seems to many merchant power plant owners like a distant dream of something that existed once, and might one day return, but is now typically absent and much missed.
The consequences of the exuberance in generation development are all around us. Among the most interesting:
- Generation development is at a standstill. No one will finance a plant without a capacity revenue stream.
- Only bargain-hunters are active. Fire sales of power plants include the recent acquisition of the Congentrix fleet of plants by Goldman Sachs-a firm that has been pretty good at calling the tops and bottoms of the generation value cycle. We take their acquisition as a good sign that the cycle is at or near the bottom.
- Lingering uncertainty about transmission and capacity rules. This prevents most buyers from re-entering the market. Regulatory risk is deemed to be very high.
- Regional differences persist. Some areas, like Entergy, are so well endowed that relief simply is not in sight. But other areas, like New York and Connecticut, need either generation or transmission projects to begin or resume development.
- The buyer matters. The nascent state of competitive retail markets makes the incumbent utility the only buyer of capacity services. Usually, a monopsonist and buyer's market is a deadly combination for sellers-the inverse of the market power problem FERC usually worries about-and it exists in most of the areas that had a lot of merchant generation development (see Figure 1).
These factors conspire to effectively negate the value of most merchant plants for investors. Demand is there for a qualifying facility (QF) or other plant with a power purchase agreement (PPA), but such plants are worth only the discounted value of their contractual revenue streams; the iron can usually be had for free.
In announcing the $2.4 billion acquisition of the 3,300 MW Congentrix fleet, a Goldman Sachs executive stated, "The value is in the long-dated offtake contracts, not in the steel."1
This seems a little disingenuous. There certainly is value in owning a fleet of state-of-the-art generating facilities, and Goldman was shrewd to capture the bucketful of real options embedded in the Cogentrix assets.
Drivers of Generation and Transmission Values
Figure 1 on the previous page provides a high-level forecast from Energy Security Analysis Inc. of capacity values in selected markets. Note that this chart presents several dramatically different capacity situations and consequently valuation challenges:
- The chronically oversupplied. This includes Entergy, Texas, and Nepool. In these areas, capacity is so abundant that for all practical purposes merchant generation has no value. Given the effects of discount rates, by the time the plant comes "into the money" in the capacity market it has little or no present value. QFs have some value, but there is a lot of regulatory risk in this arena, and monetizing much, if any, of this value may be difficult. Plants with long-term PPAs have whatever value the spreads in those agreements generate.
- The balanced and the under-supplied. New York, California, parts of the Midwest. In these areas, we make distinctions between three types of capacity outlooks:
- Existing generation facilities with PPAs and QFs have whatever the values of those contracts are, plus some modest additional value for the steel in the ground, minus a discount to account for regulatory risk (for example, changes in utility obligations to buy power from QFs).
- Merchant facilities without PPAs and QFs have very modest values because of the general investor aversion to owning power plants.
- Facilities that need to be built to accommodate a specific need are the nirvana of generation development. A few projects-the SCS Astoria project in New York City is one-have secured capacity PPAs and therefore are financially secure. This is probably how the next 5,000 MW of California capacity will have to be developed.
Beyond these typologies, buyers should appraise plants in terms of their location and in terms of how future transmission expansions affect the deliverability in their area. For example, currently low/no-value facilities in Southeast Massachusetts and Rhode Island would gain value, while theoretically high-value urban capacity might lose value if major transmission projects currently under development are completed.
New England as a whole has no foreseeable need for new capacity, but southwest Connecticut needs a solution for its congestion issues. FERC had ordered the New England ISO (ISO-NE) to develop a locational capacity market (pioneered by the NY-ISO), by which the promise of higher capacity payments in the load pocket would motivate investment in either local generation or merchant transmission. That device might work one day, when investors regain faith in power-market regulation.
Meanwhile, in the absence of merchant investment, the burden falls on the ISO and the incumbent utility. From a practical standpoint, two paths remain open for southwest Connecticut:
- Postage-stamp transmission financing. Try to get FERC approval to develop a transmission line with its cost borne by all the ratepayers of New England; for a given utility in a given load pocket, this is naturally the preferred approach. FERC is likely to stick to its "beneficiary pays" principles and deny this request, hence...
- License-plate financing. Develop a transmission line with its cost borne by the ratepayers in the constrained area. This is closer to FERC's "beneficiary pays" principles but still raises the issue of when such mandatory congestion relief would be ordered. New York has embarked on a variation on this theme, in which the load pocket's utility issues RFPs to extend a PPA to a generator or to a merchant transmission line to meet zonal requirements.
FERC will decide whether the RTOs with major load pockets (most of them outside the South) get to impose the postage stamp or will have to settle for the license plate. If FERC approves ISO-NE's request to rate-base the $600 million southwest Connecticut transmission project across all of New England, the postage stamp will be the favored mechanism for financing transmission and for relieving congestion, with huge implications for capacity values both inside and outside the load pockets.
How Much Should You Pay For Capacity?
What is a power plant worth? It depends on this evolving transmission policy.
Simply stated, the postage stamp will tend to equalize the value of capacity and put the RTOs in the position utilities have always been in-that is, they must use public financing to build transmission lines. The difference-and it's a big one-is that the RTOs have a bigger footprint and will do more to knit disparate control areas together. That is, in the minds of many, a pretty good angle of repose for power markets for the next 10 years or so. In this world, power plants are worth pretty much the same (given technology and fuel type), wherever they are located.
The license plate acknowledges the disparate economic realities of load pockets-that it is simply more expensive to bring power to cities, and there is no compelling social or political imperative to equalize electric costs between areas where it is easy to build generation facilities and areas where it is not. In this world, power plant values reflect much better the shrewdness of the locational choices of their developers.
If FERC sticks with the license plate principle and urges RTOs to socialize transmission costs sparingly, it will preserve the possibility of merchant investment in generation and transmission, and location will continue to be a dominant determinant of capacity values. If FERC veers to postage-stamp principles everywhere, then location will matter much less.
- Dow Jones, "Goldman Buys Cogentrix for Utility Contracts, Not Plants," Oct. 20, 2003.
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