DURING THE WEEK OF June 22 there was a major imbalance between supply and demand for electricity in the Midwest. Although demand was high enough to set a few records, the real problem may have been the lack of supply. Many generators were out of service and a few marketers reneged on contracts to deliver power. Market prices for bulk power allegedly soared as high as $4,000 per megawatt-hour. The industry was left in an uproar over these volatile prices, especially since a competitive market has been touted as a means to achieve lower prices, not higher ones.
Yet just as a multitude of competitive sellers can bid the price down to marginal cost of the supply curve in classical economics, a multitude of competitive buyers can bid the price up to the value of the demand curve. The principal is the same. These high prices should be viewed as the normal course of a competitive market for electricity. I agree with FERC Commissioner Hebert: The market works. The prices needed to get this high.
However, the prices may not have needed to stay as high as they were for as long as they did.
The market works better when the commodity is differentiated into finer increments, both with respect to the power sold and with respect to the duration of the delivery. Such a market needs to have a pricing formula that reflects the concurrent balance between supply and demand. The electricity market changes too quickly for all such deliveries to be negotiated one deal at a time. Further, the physics of electricity results in unscheduled deliveries that are not now priced.
Predicted Price Volatility
Electric utilities need to charge for unscheduled flows of electricity. Under the current protocol, an electric utility allows other utilities to use its generators and its transmission lines at no charge. The industry has lumped this generosity under the terms of inadvertent interchange, loop flow, and/or parallel path flow but has yet to develop a consistent approach for parsing a single meter reading among these three concepts. My solution, which I've touted for nearly a decade, is WOLF, or Wide Open Load Following, a unified pricing mechanism that could be applied to all three concepts at the same time.
WOLF is a pricing formula that responds to the concurrent physics of the electric system. For instance, when global supply exceeds demand, as in a buyers market, WOLF produces a low price. When global demand exceeds supply, as in the sellers market during the week of June 22, WOLF produces a high price.
WOLF prices vary with the load on the system, as is implied by the use of "load following" as part of the name. As the load goes up, the WOLF price goes up. As the load goes down, the WOLF price goes down. Utility engineers have long modeled generation as negative load, such as in the mathematics associated with loss of load probability. Accordingly, WOLF also handles generation and loads simultaneously by measuring the imbalance between the two.
The Midwest market is different. The Midwest market is the result of bilateral contracts. Under such bilateralism, the right price for delivery is the price that the buyer and the seller have accepted, however high or low.
Sometimes bilateral agreements cannot be reached, but electricity will flow anyway because of the laws of physics. I propose WOLF pricing for these situations. When there is no contract and no scheduled amounts, the WOLF formula price would apply to the entire metered flow. There would be no scheduled offset to the metered amount. In regard to the defaults that allegedly occurred during the week of June 22, WOLF would provide a mechanism to assess liquidated damages. The liquidated damages would be assessed on the difference between scheduled and actual flows.
I support the concept that prices can get very high and very low. I believe in letting the market work. So the price levels that occurred in the Midwest during the week of June 22 do not upset me. I see larger problems in the structure of the current bilateral market. A bilateral market is too granular. This granularity contributes to the market instability when a generator trips or when a marketer defaults.
Granularity affects electricity sales in several ways, each of which must be addressed to improve the operation of the bulk power market.
• Unit commitments. Bilateral sales take time to arrange and usually are for round amounts, such as 50 MW, 100 MW or 500 MW. The appropriate amount may be 59 MW, but the rush to get deals done doesn't allow such precision, creating granularity in the transaction. This is similar to the granularity in utility long-range planning: Do we build a power line that can carry 600 MW? Do we build a 600-MW power plant?
• Hourly transactions. Many power requirements can be for intra-hour periods, such as 14 minutes, and some power requirements can even be measured in seconds or cycles. However, market transactions are typically consummated for a full hour or for a block of hours, such as 16 on-peak hours each weekday. This granularity is again the result of the rush to get deals done.
• Prices. The reported prices are curiously round, whole numbers, sometimes thousands of dollars per MWh. The prices are not precise numbers quoted in dollars and cents. The Securities and Exchange Commission investigated brokers for the large granularity of the spread between quoted bid and ask prices for shares of stock. And that granularity was only a quarter of a dollar per share. In the Midwest in June, we had prices with a granularity of $100 or even $1,000 per MWh.
WOLF pricing of unscheduled flows of electricity was designed to handle each of these granularity issues.
Unscheduled flows of electricity are a frequent occurrence among inter-connected utilities. Unscheduled flows can also be an issue within a utility's system, such as for transactions with transmission-dependent wholesale and retail customers, both for purchases from such customers and for sales to such customers. An unscheduled flow is the difference between the metered amount and any bilateral deal that has been previously negotiated. That difference can be a sale in either direction, such as a sale in addition to the bilateral deal or compensation for underdelivery. The meter determines how much electricity is bought or sold:
• If the meter can be read in MWhs, the sale is granular in MWhs. If the meter can be read in kilowatt-hours, the sale can be granular in kWhs. There is no need to transact in round MWhs to close the deal. The meter sets the precision.
• If the meter provides data in five-minute intervals, each five-minute interval will constitute a different sale period. If the meter provides data in two-second intervals, each two-second interval will constitute a different sale period. Metering technology does not limit the pricing period to clock hours.
WOLF determines the price for such unscheduled amounts. The scheduled amount that went through the meter is priced pursuant to the agreement that determined the scheduled amount.
WOLF prices are set pursuant to a formula that uses system imbalance measurements as the independent variable. As system frequency goes down and as Area Control Error becomes negative, the formula sends the price up. Conversely, as system frequency goes up and as Area Control Error becomes positive, the formula sends the price down. A similar function is used for the geographical dispersion of prices. The WOLF functional form has been proposed as a continuous variable. Granularity enters into WOLF only in regard to the precision with which frequency, ACE, and transmission-line loadings are measured. Prices will jump from one discrete price to another, but only as a measurement of system imbalance jumps from one discrete level to another.
I am not saying that prices around $4,000/MWh are inappropriate. Only that the specific prices might be inappropriate because of their granularity. The appropriate price might have been $4,298.56/MWh. Also, the need might not have been for 500 MW for a full hour. Instead the need might have been an average of 548 MW for 28 minutes. And the appropriate price for that delivery might have had a weighted average price of $8,404.37/MWh. But considering that the specific prices were determined by arms- length bargaining between willing buyers and willing sellers, deference should be given to that process.
Futures Contracts, Options and
WOLF pricing of unscheduled, moment-to-moment flows of electricity will solidify the concept that bilateral contracts are futures contracts. Force majeure clauses will even turn some bilateral contracts into options. For instance, the North American Electric Reliability Council has a program for transmission line loading relief that can abrogate bilateral schedules. Such abrogation can relieve a party of the obligation to deliver, turning the bilateral contract into an option similar to a "put." Conversely, abrogation also can relieve a party of the obligation to receive, turning the bilateral contract into an option similar to a "call." These issues are likely to be addressed in FERC Docket No. EL98-52-000, North American Electric Reliability Council, which is an inquiry into TLR.
The high prices of the week of June 22 also call back to question the issue of stranded costs. Under a competitive market, only the market price can be recovered in rates charged to consumers, since competitive forces would otherwise allow customers to go elsewhere for electricity. The excess of the embedded cost over this market price is considered to be stranded. But when market prices zoom by $4,000/MWh for two days, the annual average market price increases by $14.61/MWh. This increase in the annual average market price can lift the average market price to be above embedded cost. In that situation, stranded costs are now windfall profits, at least if market participants have structured their deals appropriately.
Mark Lively is an independent consulting engineer in Gaithersburg, Md. His work has taken him to 48 states and the countries of Australia, Canada, England, Kazakstan, Latvia, South Africa, and Turkmenistan.
1 See Bruce W. Radford, "The Heat's On," Public Utilities Fortnightly, July 15, 1998, p. 6. FERC has several dockets open on the high prices that occurred during the week of June 22, including The Cincinnati Gas & Electric Co., et alia, Docket No. EL98-53 and Steel Dynamics Inc. v. American Electric Power Service Corp., et alia, Docket No. EL98-54.
2 See Mark Lively, "Tie Riding Freeloaders - The True Impediment to Transmission Access," Public Utilities Fortnightly, Dec. 21, 1989; "WOLF Pricing," Public Utilities Fortnightly, Oct. 1, 1994.
3 "Tie-Riding Freeloaders" posited prices of $20/MWh and $800/MWh, producing an implicit price ratio of 40. The prices were constrained because I used tabular presentations, showing only two specific prices. In contrast, for "WOLF Pricing" I used graphical presentations, showing prices that varied continuously, with no upper limit and a lower limit that approached $0.00/MWH. Suffice it to say that the implicit price ratios for those graphs were much higher than 40.
4 Two seconds as a billing period? Ask any control area operator the frequency with which its SCADA system polls the meters on its interties to determine inadvertent interchange and ACE. Ask any control area operator the frequency with which it sends signals to generators to respond to power imbalances. What is the response time for FACTS devices?
5 Time granularity is important for recognizing the use of capacity. Consider a problem that occurred at the beginning of an hour but that got resolved 10 minutes later. Usage during those first few minutes of the hour should incur capacity charges. Reversing the flow during the last 50 minutes should not remove any obligation to pay such capacity charges. See "Capacity Missing From The Futures Market," The Electricity Journal, accepted 1998 May for future publication.
6 The scheduled amount can be shown to be a hedge or a futures transaction, with many of the characteristics of an insurance policy. See Mark Lively, "Electric Transmission Pricing: Are Long-Term Contracts Really Futures Contracts?" Public Utilities Fortnightly, Oct. 15, 1994.
7 Though the textual discussion is limited to frequency and ACE, WOLF has been proposed to include the various integrals of these quantities, such as time error and cumulative inadvertent interchange. Further, WOLF prices would also be spatially differentiated. See for example "Paying for Private Power - Some Alternatives to Public Funding," International Power Generation Conference, San Diego, Calif., Oct. 6-10, 1991.
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