Contrary to findings, the conditions seen in June 1998 were not that unusual. And next year could promise prices even worse (em or, for the first time, real reliability problems.

The recent report by the staff of the Federal Energy Regulatory Commission on the causes of the power price spikes that occurred in the Midwest performs an important service (em it acknowledges that in competitive markets, the price of wholesale power can be quite high in periods of peak demand.

Nevertheless, the staff went wrong in reporting that the conditions behind the price spikes were unusual.

In fact, given the uncertainty of the current transition period, the next year might likely see a repeat of the 1998 spikes, or worse. That's because the transition to full deregulation is likely to prove a bit more messy than the staff report might lead one to believe.

The FERC's misunderstanding stems from its failure to undertake a loss-of-load study. The staff report also misses the opportunity to explain more clearly the extent to which policy mistakes have and appear likely to continue to help make the transition more difficult than it needs to be. A number of reforms are urgently needed during this transition, such as (1) explicit rules on generation reliability, (2) publication of independent data about reliability, (3) identification of a lead regulatory authority, and (4) a rapid finish to key parts of wholesale and retail deregulation.

Price spikes are linked inextricably with reliability problems and blackouts. Most retail customers cannot participate in wholesale markets. Instead, they must rely on utilities and policy makers. Only government action can help.

Situation: Worse Than Acknowledged

In late June 1998, in the Midwest, prices briefly reached $7,500 per megawatt-hour. That price was "extraordinarily high," in the words of the recent FERC staff report entitled "Staff Report to the Federal Energy Regulatory Commission on the Causes of Wholesale Electric Pricing Abnormalities in the Midwest during June 1998." %n1%n The report, however, goes on to downplay the event by noting that average prices were closer to $40/MWh in August and that no blackouts occurred, nor did there occur any curtailments of service to firm customers.

Most importantly, the report concludes that "combination of factors was not typical, is not likely to recur, and is not representative of how wholesale markets usually work."

These statements represent both a service to industry and a missed opportunity. They reinforce the fact that deregulated wholesale prices will on occasion be extremely high (em even hundreds of times higher than on average. Publicizing this fact is especially welcome, since one motivation for the study was to allay concerns that the high prices reflected market manipulation and should be suppressed. %n2%n However, the report fails to highlight the fact that the current transition period could well prove much more difficult than expected, with blackouts or prices higher than equilibrium levels.

A price of $7,500/MWh is extremely high (em even if the FERC correctly concludes that some very high price spikes are part of a regulated power business. Were those prices to prevail for even 48 hours, the owners of a combustion turbine could pay off the costs of the investment in just two days, earning profits from all future sales for the next 30 years. %n3%n A more reasonable equilibrium price is below the current "into Cinergy" futures prices (prices for the futures contract at the Cinergy trading hub).

The FERC staff correctly notes that there were no blackouts in the Midwest, but it under-emphasized the fact that there were voltage reductions (em one step away from blackouts. Even more important, the past summer was not as unusual as the report concludes it was. %n4%n The Midwest has insufficient capacity and could have a similar generation shortage in 1999. This problem could even continue for the next few summers.

Had it realized how bad the situation really is, the FERC staff might have drawn the correct conclusions about the urgency of additional action. The region is sufficiently close to having future blackouts next summer (em so close that regulators and others should make it a primary concern to remove all impediments to deregulation and take proper steps to manage generation reliability during the transition to full deregulation. If we continue to move forward half-regulated and half-unregulated (i.e., with the wholesale market deregulated and the retail market regulated), then one of two transition strategies is required. Planning reserve margins sufficient to protect end users should be put in place and enforced with clear penalties, %n5%n as in NEPOOL. In the alternative, policy makers should rely on the market alone to set reserves. If the market route is chosen, the public should be warned of the potential for rolling generation shortage-caused blackouts, especially in major urban areas, and especially during the transition.

Capacity: The Specter of Shortage

The origins of this capacity shortage must be understood rather than minimized as in the FERC staff report.

First, the report notes that Midwest utilities have underestimated load growth over the last two years. However, the report fails to note that the industry has repeatedly and systematically underestimated load growth in the affected areas, those being MAIN, ECAR, SPP, SERC-TVA, and SERC-Southern. Note that these five areas were the only areas with super-high prices. (See Figure 1.) That fact emerges by comparing long-term forecasts of electricity demand growth with actual figures recorded over several recent years. It is not uncommon for actual demand to grow by two to four percent, but for utility forecasts to call for growth at only one to two percent. (See Tables 1 and 2.) Over the long run, these differences are huge; they are outside the range of forecast error (remember, these are 10-year averages). For example, a discrepancy of one percent a year for the identified five regions means an annual under-forecast of twelve 250 megawatt-sized plants and a 10-year under-forecast of over 120 individual plants sized at 250 MW.

The reason for this systematic problem is well known to insiders, though there are no depositions that one can identify to support this view. It is not simply that long-term average demand growth is difficult to forecast. Rather, utilities do not want to build new plants in the current in-between state of regulation and deregulation. The easiest way to avoid the need is to claim it does not exist. The greatest need to avoid appearances of impending shortages has emerged in the regions where this problem is most acute.

The state regulatory authorities have acquiesced in this situation for three main reasons. First, they do not want to have to raise customer rates to pay for new capacity. Second, they do not want to admit that the conservation estimates from their investments in demand-side management were exaggerated. Third, no one is really in charge in the mixed-up regulatory structure we currently have.

The FERC points out the problem in its own quotable argot, "The FERC does not have primary jurisdiction over all matters that may affect whether future spikes occur." Yet the grid is by its physical nature the supreme example of interstate commerce. If FERC does not take the lead, how can we expect anything but a very messy transition?

Reliable Information: Still Lacking

Where has FERC been on this issue of load forecasts? Not only has it been silent over these past few years; even today, the FERC remains relatively silent in the face of a transition crisis. In its staff report, the FERC failed to emphasize appropriately the essence of the problem: a chronic abuse of the public's need to have access to fair, independent forecasts from authorities with responsibility for grid generation reliability.

Another cause of this problem is the lack of transparent information from independent sources that reports the true state of the grid. The FERC staff did not address in its report the following issues:

• Blackouts (em There is a significant chance of blacking out %n6%n Midwest firm customers. In the jargon of the industry, there is a significant loss of load probability (LOLP) in many U.S. markets, especially in the Midwest. There is no mention of the term "loss of load probability" anywhere in the report (even in the footnotes or glossary).

• LOLP Analysis (em The report provides no explanation of the relationship between LOLP and high prices. Since wholesale prices explode because of the lack of capacity, it is impossible to separate a discussion of price spikes and reliability of firm load.

• Public Data (em The report should have demanded published, transparent LOLP planning estimates and for the supply of related information on plant availability, line capacity, and demand uncertainty.

• ISOs (em The report made no clear demand for accelerating the creation of independent system operators. How could the report not attribute the poor functioning and surprising character of the market in any way to the fact that there was no ISO in the Midwest? Even today, there are no clear boundaries set for regional Midwest ISOs.

Significantly, the appropriate analytic structure for analyzing June 1998 was completely ignored in the report.

First, loss of load occurs when firm demand exceeds supply. This is assessed probabilistically, accounting for uncertainty in supply and demand, including transmission limits. (See Figure 2.) For example, FERC shows that during the week of June 22, 1998, ECAR and MAIN averaged outages of 17,500 MWs or about 12 percent of capacity. If this fact had been set in a probabilistic analysis, it would not have been seen and described as unusual, but as falling in the range of events to be expected, given the situation with nuclear plant availability.

Note that every outage, whether plant or transmission, is unique, but the average effect and average variation is the proper focus of analysis. The same is true of demand, which was less extreme than indicated. For example, most MAIN utilities did not experience their annual peak during June because the weather was not uniformly hot. Usually, there is more correlation between MAIN utility peaks.

Second, it is true that a market in equilibrium will tend to have some period of significant LOLP during the summer peak. (See Figure 3.) However, a capacity-short market will have too much LOLP, too many shortages, and too many spikes.

Third, a significant LOLP correlates with the chance that the market will end up on the vertical section of the supply curve, where buyers set the price. The buyers in this case are utilities acting as agents, expressing their willingness to pay to avoid a blackout. (See Figure 4.) This situation reflects an implicit "contract" between customers and utilities, arbitrated by regulatory authorities. Decisions are ideally based on the survey literature, which indicates that the average end user is willing to pay about $7,000/MWh or higher to avoid a blackout.

If the FERC staff report had applied this three-step approach, in combination with microeconomic theory and common sense, it would have reached several conclusions:

• 1998 (em Prices reflected the fact that the market was very close to generation shortages and blackouts.

• 1999 (em Prices will likely be lower, but only if weather is normal. Hot weather over a broad Midwest area next summer could well mean 1999 will be worse than 1998.

• Uncertainty (em Hot weather and sudden retirements could make the transition even tougher than expected.

There is currently no procedure in place to prevent retirement of existing units, especially nuclear units, during the transition to competition. The retirement without warning and explicit make-up actions of the huge Zion nuclear plant in Illinois was a leading cause of the 1998 price spikes, though it was not described as such by the FERC staff report.

Moreover, the seeming complacency about the lack of ISOs in the Midwest (the recently approved Midwest ISO still leaves most of the region outside an ISO structure) only adds to problems. This lack leaves no independent forum for Midwest decision making on reliability. It also prevents any comprehensive approach in providing credible information on such key parameters as demand, plant availability, LOLP, and transmission. Price information is important but other information is also crucial, especially as long as nearly all end users are dependent on events in the wholesale markets in which they cannot legally participate.

Deregulation: A Too-Slow Transition

The complacency about retail wheeling is blocking moves to obtain more explicit interruptible contracts and remote control of loads. Contrary to the popular view that retail wheeling should go slow to avoid mistakes, true competition is needed to create incentives to pursue potentially controllable or interruptible load.

This failure to complete the transition to complete deregulation (em to have ISOs in place, to have state and federal governments commit to a market with adequate information and known rules (em is inhibiting construction of new plants. Investors, already befuddled by the lack of basic information, are understandably hesitant to invest when the rules of the game are not clear. For example, will states suddenly insist on over-construction of new rate-based peaking units (em thus killing merchant investments in peaking units (em or will they rely on the market? Will there be transition arrangements like enforceable planning reserves (e.g., structures like NEPOOL and PJM) or complete reliance on the wholesale market? In other words, can politicians credibly claim that they know who is in charge of generation reliability, or that deregulation is so organized and coherent as to warrant reliance on market forces?

The failure to identify the unique circumstances in the Midwest blocks actions to resolve them. This failing is especially glaring in a report on the Midwest. Specifically, in the Midwest, combustion turbines are urgently required. These plants are suitable only for meeting power demand at the super peak. Their economic viability depends on super high prices, which are highly uncertain. Further, there is little experience building and financing peaking plants in a deregulated market. Turning to Wall Street for debt financing or new capitalization initiatives for what amounts to a new sector will be possible but will take time (em all the more if deregulation remains incomplete and inefficient.

The uniqueness of the Midwest capacity situation is only fully seen by contrast. In New England, a huge construction boom is under way. Thus, one might expect a smooth transition to market-based construction in the Midwest. In New England, the revenue of the new plants appears more certain and more familiar to investors. These new plants do not depend on the exact balance between supply and demand at the extreme summer peak, but on the fact that their fuel costs are lower than old-style steam units now on line. These new plants employ new technology. They are thermally more efficient, for a given input in fuel cost. Their power production costs run about 30- to 40-percent lower. Thus, these plants are almost guaranteed to generate at least some income to cover debt obligation. These plants are also hedged. As fuel costs of new gas-fired combined cycles go up, so do power prices as they reflect the marginal costs of inefficient, old gas steam units. By contrast, Midwest peaking units could flip from feast to famine and have little or no income for debt.

Going Forward: At Least Identify the Risks

It is important that the market work as efficiently as possible. The market can ultimately handle the need for reliable supply (em even for peaking plants in the Midwest. However, regulators must acknowledge the urgent need to get rules in place, finish the work of deregulation and, until then, inform the public of the risks inherent during the transition period.

The public will ultimately benefit from deregulation. That fact gives all the more reason to understand and properly manage the precariousness of the current transition. Nearly all users lack hourly meters, remote control of load, explicit interruptible contracts, and hence, currently rely on utilities and regulators to act as their agents to obtain reliable power. They cannot yet legally participate in the markets. We owe them at least fair, impartial warnings about transitional risk, if not explicit protection.

Is it too difficult to imagine rolling blackouts, due to lack of generation? Skeptics should call Alberta or Colorado, where blackouts occurred this past summer, or Midwest power operators implementing emergency procedures last June.

Judah L. Rose is a vice president of ICF Kaiser International Inc., and a frequent contributor to Public Utilities Fortnightly.

1 Sept. 22, 1998.

2 Artificial price limits combined with partial deregulation would clearly be the worst of all possible worlds; generation shortages would occur as regulators rediscover supply and demand.

3 $7,000 per MWh ¥ MW ¥ 48hours=

1,000 KW

$336/kW per year

4 If circumstances were so unusual, why was this event forecasted? See J. Rose, "Last Summer's Pure Capacity Prices: A Harbinger of Things to Come," Public Utilities Fortnightly, December 1997, p. 36; J. Rose and C. Mann, "Unbundling the Electric Capacity Price in a Deregulated Commodity Market," Public Utilities Fortnightly, December 1995, p. 20.

5 Current procedure in MAIN, as described, is to use "peer pressure" to enforce planning reserve margins; peer pressure, not surprisingly, does not seem to be working.

6 Or voltage reductions or public appeals informing the public of the need for emergency customer self-curtailment.

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