Flow-based pricing ends

subsidies inherent in grid-wide,

postage-stamp rates.

I

n Order 888, the Federal Energy Regulatory Commission suggested 11 principles for forming an independent system operator, or ISO. In its third principle, the FERC offered this guidance on transmission pricing:

An ISO should provide open access to the transmission system and all services under its control at non-pancaked rates pursuant to a single, unbundled, grid-wide tariff that applies to all eligible users in a non-discriminatory manner. %n1%n

Several of the ISOs now under consideration across the nation face tough decisions on transmission pricing. %n2%n The most obvious literal interpretation of the FERC's third principle would be to set the price for ISO transmission by rolling embedded costs into a single, grid-wide, postage-stamp rate. Under this method, revenue requirements for bulk transmission facilities turned over to the ISO would be tallied. This aggregate ISO revenue requirement, divided by the total load (determined using the 12-month, coincident-peak method), would yield a postage-stamp rate for all transactions.

In theory, this simple approach to pricing would put power producers on equal ground in the competition to serve load. However, this proposal creates many issues for transmission owners, state and federal regulators, and transmission customers.

Several basic problems emerge under the single, grid-wide, postage-stamp rate suggested by the FERC:

• Recovering costs (the traditional "revenue requirement");

• Dealing with "rate shock" for eligible customers;

• Determining whether eligible bundled customers choosing to remain bundled take service at ISO rates;

• Compensating transmission owners equitably based on actual flows; and

• Addressing inconsistencies with the proposed capacity reservation tariff, or CRT.

Recovering Costs

Stakeholders agree that transmission owners should be able to maintain revenue requirements after turning over control of

transmission systems to an ISO. But there's a problem in that: System owners will likely see a significant reduction in what once were nonfirm revenues for point-to-point transmission between neighbor utilities. This reduction arises from the elimination of rate pancaking (em the practice of billing a separate charge for each power movement by a separate company along the hypothetical "contract path."

When utilities become part of an ISO, it becomes difficult to make transmission owners whole from a revenue perspective. Why? Because transmission revenues disappear for certain transactions. When two former control areas are combined under the ISO, these "intra-ISO" or "drive-within" transactions are now covered by network service under an access charge. To mitigate this shortfall (em potentially a substantial amount of money (em the ISO could charge a transmission rate above its aggregate revenue requirement. This strategy would fund a "reserve account," which could be used to compensate transmission owners for the shortfall.

Nevertheless, the FERC would likely frown upon transmission rates not based upon cost, as it did last November when it rejected the 10-percent "adder" for importing resources outside of the zones proposed in the recent filing for the Pennsylvania-New Jersey-Maryland Interconnection. %n3%n Under the option described above for mitigating the shortfall in cost-based transmission revenues, the contemplated reserve account would reflect an estimate in the decreased level of the nonfirm, point-to-point revenues. Again, this concept could prove a difficult sell to the FERC, and to customers, as the reserve would not qualify as cost-based.

In any event, ISO rate making should be performed on a levelized, gross-plant basis, since ISO network access marks a new service with wide-reaching regional opportunities for transmission customers. Forcing the pricing for this novel service on a net-plant basis would be inappropriate. It also would send improper price signals to the market.

Dealing with Rate Shock

There's an obvious drawback in setting up an average price (em it is rarely correct. To illustrate, the Table represents hypothetical data for three transmission owners who have turned over control to an ISO, and shows whether an eligible customer would decide to take transmission service at the ISO rate.

In the example, the ISO sets a grid-wide, postage-stamp rate for transmission service at $1.50 per kilowatt per month. If a bundled customer in Company A already pays $1.00 per kW/month as the transmission portion of its bundled rate, and never elects to take service from the ISO, then the transmission owner may reluctantly seek regulatory relief if it's forced to pay the ISO rate, since that rate will be higher than what it currently is paying.

In this case, if we assume that Company A does pay the higher ISO rate, then its stockholders will likely absorb the difference. That potential outcome will put Company A in a difficult predicament, given the rate-freeze environment that exists today.

Given this specter of cost shifting, Company A instead would be wise to stay out of the ISO, despite the benefits. On the other hand, bundled customers within Company C paying $2.00 per kW/ month probably would seek rate reductions even if the customer chooses not to unbundle and take service from the ISO. %n4%n This issue is a difficult one to deal with. It cannot be readily resolved, given the fact that several of the ISO's now contemplated will cross multiple state boundaries. Winning a consensus on rate relief from the public service commissions in all the various states would prove difficult, if not impossible. However, this entire issue of rate shock hinges on yet another vary important and fundamental question: Does a bundled customer who becomes eligible for ISO service, but who elects to stay bundled, ever take service from the ISO?

Saying "No" to the ISO?

This question is pivotal: If a transmission customer continues to take bundled after becoming eligible, does the customer's load come under ISO rates? In my opinion, the answer is an emphatic "no."

The reason is simple. Given the rate-making implications, there's no way to force a customer to pay the ISO rate (em especially if the rate exceeds the transmission component of the bundled rate.

"Customer choice" is inevitable, but until state commissions provide rate relief and force everyone to unbundle, the problem will remain. If a transmission customer elects to says "no" to the ISO transmission rate, it may still receive ISO service from the point of view of operational control, but it won't be paying the ISO's higher, grid-wide postage-stamp rate. Instead, it will be paying a bundled rate with a rolled-in transmission component.

"Drive-thru" vs.

"Drive-within"

In the case of so-called "drive-thru" or "drive-out" transmission service, which serves load that lies outside the ISO, the problem is not one of pricing (em the grid-wide, postage-stamp rate is fine (em but one of allocation.

For these out-of-area power movements, does it make sense to allocate revenues based on revenue requirements, or by share of load? For these transactions, wouldn't it be more equitable to recognize actual power flows by compensating those transmission owners whose systems are actually affected by the transaction? It would seem contractually logical that the owner of the transmission system at the point the transaction exits the ISO area receive a primary allocation of revenue from scheduled ISO drive-thru or drive-out deals. These revenues should not be allocated to those transmission owners located in a remote area of the ISO whose system is unaffected by the transaction.

However, for revenues generated from intra-ISO transmission, or from "drive-in" transactions, all owners should be made as whole as possible. That means an allocation based on load ratio or revenue requirement for "drive-within" or drive-in deals. But for drive-thru or drive-out transactions, dollar allocations should be flow-based. This distinction recognizes electrical reality.

The GAAP's Flow-based Pricing

Several utilities are now participating in an experiment under The General Agreement on Parallel Paths (GAAP). %n5%n

This flow-based pricing and allocation mechanism marks an important step toward promoting competition in the electric industry. Flow-based pricing would send proper price signals to the market. It would compensate transmission owners equitably for use of their assets.

Under the GAAP method, for each transaction involving at least one GAAP participant, a unique pricing path or "prime path" is set. The pricing path is determined by analyzing transmitting systems between buyer and seller to determine that single series path that carries the largest part of the transaction. The transmission revenues derived from the prime path are distributed to systems that provide transmission on multiple parallel paths. %n6%n

The FERC's CRT Plan

Notwithstanding recent signals from the FERC hinting a postponement on its proposed Capacity Reservation Tariff, or "CRT," one can still detect a contradiction between the Commission's professed goal of open access and its apparent unwillingness to embrace innovative flow-based proposals for transmission pricing.

Order 888 encouraged ISOs, but handed the industry a "straight jacket" in Principle No. 3. The Notice of Proposed Rulemaking for the CRT %n7%n arrived the same day and seemingly opened the door to innovative, flow-based tariff designs.

These two premises (em an ISO postage-stamp rate and the CRT flow-based pricing (em contradict one another. This contradiction must be resolved if industry restructuring is to proceed fairly. Postage-stamp rates will only maintain an outdated tradition.

The recent commission ruling on the PJM proposal, however, did refer to the potential use of "rates based on electrical characteristics and power flows instead of corporate boundaries." %n8%n The position taken by the FERC on any future proposals for innovative tariff designs will send the industry an important message: Move away from traditional postage-stamp transmission pricing based on the contract path, and toward innovative, flow-based regional pricing.

The Solution: Zonal Pricing

Here's a solution: Begin with ISO pricing on a cost-based, gross-plant, zonal approach, and then move toward a single, grid-wide, flow-based tariff after a majority of the load in the ISO is eligible and after the respective state PUCs have granted the appropriate regulatory relief.

This approach skirts rate-recovery issues and provides for comparability. Neighboring entities, such as bundled retail customers and unbundled wholesale customers, theoretically are paying the same for transmission service under a zoned approach. Rate shock and state regulatory implications are mitigated.

The time needed for this transition is anyone's guess, but given bureaucratic realities and the history of other deregulated industries, the job could easily take 8 to 10 years to complete. By then, however, technological improvements will favor flow-based pricing; postage-stamp rates will have become obsolete.

The "zonal concept" recognizes actual use of the transmission system in the vicinity of the served load and compensates the facility owner on a cost basis (em not by averaging the costs incurred across a region the size of Texas, or larger. Postage-stamp proponents would argue that this idea violates the comparability premise of Order 888. "Transmission customers should pay the same rate for the same service," they might say.

But cost "inequities" are common these days. Differential pricing has come to be accepted across the country. Does everyone flying to the same location on a given airline pay the same fare? Is the cost of a hotel room in Madison, Wis., the same as the exact room at the same hotel chain in downtown Boston?

Electric transmission systems were built to serve nearby loads. Those customers should continue to pay transmission rates for the system to which they are directly connected. Perhaps the portion of what are truly "bulk" transmission systems (230 kilovolts and higher) designed to move power over great distances could be socialized for the common good.

Clearing the Pitfalls

Speaking last fall in Santa Fe, at the Fourth DOE-NARUC Electricity Forum, Charles Falcone, senior vice president for system power markets at American Electric Power Service Corp., praised postage-stamp pricing for an ISO:

"Competition is best achieved if all capital transmission costs are recovered through an embedded-cost, postage-stamp rate throughout the ISO. This result is fair to the owners of the transmission who are assured of a return on their investment. A single rate is appropriate, since all users are entitled to the same service regardless of their location." %n9%n

There obviously several pitfalls inherent in postage-stamp pricing for the multi-state ISO. It is the elimination of pancaking that promotes robust competition among generators, not the continued reliance on the past traditions of postage-stamp rates and contract path conventions.

A zonal-pricing approach for the ISO would not compromise comparability standards, and yet would recover costs fairly and avoid substantial cost shifting. t

Mark J. Volpe is rates administration analyst in the Federal Regulation and Pricing Department at Centerior Energy.

Transmission Rate Comparison

SO vs. Old Bundled Rate

Revenue Decision

Load Requirement Transmission Rate to Buy at

Company (MWs) ($million) ($/kW-month) ISO Rate

ISO Rate

Rolled-in (Grid-wide,

Rate postage-stamp)

A 3000 36 1.00 1.50 No

B 2000 30 1.50 1.50 Maybe

C 4000 96 2.00 1.50 Yes

Totals 9000 162 1.50 (em

1Promoting Wholesale Competition Through Open Access Non- Discriminatory Trans. Servs. by Pub. Utils.; Recovery of Stranded Costs by Pub. Utils. and Transmitting Utils., FERC Order No. 888, April 24, 1996, 61 Fed.Reg. 21,540 (May 10, 1996), FERC Stats. & Regs. ¶31,036 (1996) (Open Access Rule).

2Currently there are eight ISOs under consideration across the country. These include New York, New England, the MAAC region, the Midwest (ECAR and MAIN), California, Texas, The Pacific Northwest and Wisconsin.

3Atlantic City Elec. Co., et al., Dkt. Nos. ER96-2516-000 et al., Nov. 13, 1996, 77 FERC ¶61,148, at p. 61,577, slip opin. at p. 42 (PJM ISO Guidance Order).

4"Cost Recovery Issues for Electrical Utilities in this Transitional Era," by Michael E. Small, Wright & Talisman, P.C., August 29, 1996, p. 12. (Prepared for the Edison Electric Institute.),

5"Centerior, 3 Utilities Form Regional System," The Cleveland Plain Dealer, June 20, 1996, Business Section, p. 1. Besides Centerior Energy, other participants in the GAAP alliance include Ohio Edison Co., Allegheny Power Co., and Virginia Power Co.

6"A General Agreement on Parallel Paths," June 1996, p. 14. (Report Prepared by The GAAP Committee.)

7Capacity Reservation Open-Access Transmission Tariff, IV FERC Stats. & Regs. ¶32,519 (1996) (CRT NOPR).

8PJM ISO Guidance Order, slip opin. at p.44.

9"Efficient Transmission Pricing for the Midwest ISO," by Charles A. Falcone, Oct. 22, 1996, p. 4.

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