Perspective

Emotions have run high in the SMD/RTO debate. It's time for cooler heads to prevail.

During my father's long career as practicing attorney and state senator from Kentucky, he has been on both sides of issues involving the federal government. He always said that when opposing the federal government, they should be referred to as the "gov'ment." This reference evokes everyone's visceral distaste for taxes, "pointy head bureaucrats," gasoline additives, etc. But when you are on the side of the federal government, the reference should change to "the United States of America" (said slowly and reverently). This will surely swell the chests of your audience with pride.

The point is, these references are all about emotion. I submit that this emotion is at work as regulators and industry collectively wrestle with the difficult issue of electric industry restructuring. Otherwise, much of what is being said about restructuring and regional transmission organizations (RTOs) would be difficult to understand.

I will not discuss the details of the proposed standard market design but will instead look at some of the concerns raised by the proposed movement to RTOs as the vehicle to ensure non-discriminatory open access and thereby enable competitive wholesale markets.

The Anti-RTO Argument

A catalogue of the concerns being raised in the debate, particularly as they relate to formation of RTOs, would look something like the following:

Membership in an RTO leads to loss of state jurisdiction over siting of generation and transmission.

Establishment of an RTO leads to higher prices through the introduction of congestion pricing.

Establishment of an RTO results in the movement of low-cost generation away from traditional ratepayers to be sold at higher prices.

Establishment of an RTO may cause reliance on a centralized spot market that will result in California-style price movement and results.

Needless to say, these concerns have not been part of the PJM experience.¹ To be sure, the manner in which the states interact with the utilities on issues such as planning has changed as PJM has centralized the development of planning options for states to consider. Some other things have changed as well, including the need to consider what tools utilities and load servers use to manage congestion costs. These costs have always existed but were hidden through socialization and averaging over time. However, the last six years that represent the life of the modern PJM market do not bear out these above-listed concerns.

Transmission and Generation Siting

The experience of PJM is very clear: The RTO supports state authority for siting over transmission or generation facilities. In the PJM area, states continue to wield the power to authorize transmission and generation siting. However, PJM has provided a participatory process by which state regulators interact and view electric facility upgrades and builds in the more meaningful regional context. In one particular case, a state in the PJM area used this process to highlight transmission problems associated with its ratepayers that needed to be addressed.

Upgrades to the grid (most require permitting by states) occur one of two ways: 1) as a result of requirements identified through the PJM planning process to accommodate interconnection by new generation; and 2) as a result of baseline reliability needs identified through the planning process run by PJM in coordination with transmission owners and state agencies.

Naturally, all generation requesting an interconnection must pay for a safe interconnection to the substation level. However, as a consequence of PJM's interconnection process, some generators have an obligation to pay for network upgrades. That obligation arises if the interconnection studies performed by PJM determine the addition of the generation at the specified location would cause violations of planning criteria beyond the point of interconnection, and if the generator wishes to ensure deliverability in order to be counted as installed capacity resources.² The resulting upgrades to the transmission system are then performed either by the transmission owner in the area or by the generator itself, but always in accordance with state siting and permitting requirements.

Upgrades that occur as a consequence of the PJM planning process are the result of studies performed jointly by PJM staff and transmission owners. The results are then vetted with the broad PJM membership and submitted to the appropriate state agencies for their review. Once a plan has been approved by the PJM board of managers, the transmission owners involved in the facilities upgrades are committed to performing the upgrades, subject to state siting requirements. However, instead of relying on information supplied by the transmission owner and performed in a single utility context, the state authorities now are the beneficiaries of a plan that was independently developed with input from multiple parties and done as part of a multi-system or regional context and coordinated by an RTO that is financially indifferent to the results.

This process, though relatively new, already has yielded results, as the PJM board has approved more than $700 million in transmission upgrades. Of this, more than $500 million will be paid directly by generators for interconnection, and all of it will be done with state approvals, but without adding to the transmission cost rate base. This process, in fact, is probably the first real use of the "participant funding" approach to transmission upgrades. RTOs, Congestion, and Prices.

A casual observer might be led to believe that congestion is a new phenomenon created by restructured wholesale markets and RTOs. However, as most people know, congestion has been around almost as long as there have been transmission systems. In a vertically integrated monopoly, this congestion is managed by increasing or decreasing the output of certain power plants (redispatch) by running less costly units and turning down more costly units. The costs are then averaged and spread, or socialized, across the entire class of retail customers, and borne by them through base rates or through fuel adjustment clause charges.

The locational marginal price, or LMP system is, in many respects, similar to traditional methods of measuring congestion as it results from a security constrained economic dispatch; the same pricing system that results from the same dispatch done for the past 30 years. A single, vertically integrated utility would make adjustments to ensure that the transmission system is not overburdened and would achieve relief of congestion through redispatch. The PJM process takes a similar approach but has the added benefit of including generation assets from a broader regional area to solve the bottlenecks.

What is different, however, is the way in which congestion costs are allocated. Congestion charges are directly assigned to those who cause or require power from areas that result in congestion. These prices, which are the heart of LMP, do three things: 1) reveal the true value of power in a certain area in a transparent manner; 2) incent investment in higher-priced areas; and 3) provide market participants with information to manage their costs appropriately.

These costs are currently the subject of tremendous political controversy, but there are several facts that have been missing from the discussion. Many who raise this issue cite congestion cost numbers of a seemingly alarming amount. It is important to distinguish the gross congestion number that is often cited from the net congestion costs after the use of protective or hedging tools such as firm transmission rights (FTRs). In PJM, approximately 80 percent of all load is hedged or served locally. Those that are hedged receive revenues from FTRs that eliminate or offset the vast majority of congestion costs. Those entities that still experience congestion costs because there are not enough feasible FTRs to cover all loads have the opportunity to contract with generation within their area to provide price certainty.

While this latter approach may not provide the lowest prices in the entire RTO area, the combination of FTRs, properly used, along with contracts for nearby generation, produces a financial outcome that is predictable and has marginal net congestion charges.³ For the whole PJM area, while gross congestion has increased over time, the net costs to load have been approximately 1 percent, or about $115 million in 2002 in a 65,000 MW system.

Loss of Lower-Cost Generation

While much of PJM now incorporates retail access areas, this is not the case throughout the entire area. Consequently, PJM has emphasized to companies that contemplate adding their systems to PJM that there is no need to change traditional supply arrangements and pricing of the contract to load as a consequence of participation in the PJM market.

At the outset, it is important for regulators to know the costs in an area over time, and how they relate to costs in adjoining areas, before it can be determined that ratepayers are truly experiencing low costs expressed in their rates. Various cost-benefit or cost production models have revealed that some parts of the country where low-cost power was thought to exist often do, in fact, have significant opportunities to import less expensive power during peak periods.⁴ Nevertheless, there is no reason states with bundled rates cannot continue to require utilities in their jurisdictions to keep prices at a certain fixed level.

As state regulators have historic cost data on their utilities, a fixed rate based on information of the generation in traditional utility rate base, subject to occasional prudence reviews, can be used to ensure utilities are meeting the state ratepayer or customers' needs in a manner consistent with those costs. Thus the utility can meet the needs of the load either through its traditional resources or through a combination of bilateral contracts and its own resources-but it must justify its actions on demand to the state regulators. Since PJM is a wholesale market, there is nothing in our tariff, agreements, or procedures that precludes this state control over retail pricing.⁵

RTOs Mean Centralized Markets

Since the difficulties experienced in the California market of 2000-2001, centralized, or spot, markets have been viewed with much suspicion. The experience in PJM indicates that spot markets, properly defined and used, can greatly benefit competition and assist state regulators. The key is to provide flexible, transparent access to all options to procure power: spot markets, self-supply, bilateral contracts, etc.

PJM does operate an organized spot market;⁶ however, this market represents a fraction of the total energy market in PJM. Bidding into this market, which is essentially meant as a balancing market for energy, is entirely voluntary. Historically, PJM's voluntary spot market has involved approximately 10 to 15 percent of energy consumed, the rest occurring either through self-supply or bilateral transactions. Indeed, the PJM West pricing point has been the most liquid bilateral trading hub for power in the United States almost since its inception in 1998. As a consequence, average wholesale prices in PJM have been remarkably stable considering weather and changes in demand.

In fact, the establishment of the PJM voluntary spot market is viewed by many as making bilateral transactions more feasible. Suppose a marketer or an affiliate of a utility from another area is interested in selling to a large customer in an area dominated by a vertically integrated utility. At the time of delivery this new supplier finds itself short through the tripping of a unit, etc. The new supplier now has an option for procuring replacement power rather than merely being a price taker from the vertically integrated utility in the area. Such optionality reduces risks associated with selling and having to rely on a monopoly provider. Consequently, not only is the spot market voluntary, it has served to make the bilateral market more robust.

Additionally, the existence of a robust, yet voluntary, spot market can help states that choose to bid out provider of last resort responsibilities, as the state of New Jersey has discovered. The transparent prices in this case have facilitated an auction process that not only has provided real alternatives to traditional utilities in serving customers but has netted the state considerable revenue. And there are other benefits as well from spot markets that help states. The use of the spot market and prices bid into it are key components to manage congestion in a transparent fashion while encouraging suppliers to make generation as available as possible. Several positive benefits have occurred since the beginning of PJM's market in April of 1998 that are directly related to this price transparency. Generator availability has increased significantly, as seen in Figure 1. This data suggests that the economic incentives that are obvious in an open market have increased the availability of generation.

The spot market also has assisted PJM in attracting investment by signaling through open prices where power is most valued. Also, generators are sited appropriately to avoid high costs for transmission construction required for reliability and deliverability.

While spot prices are not, by themselves, an adequate basis for large capital investments such as power plants, they are a key component along with the forward market represented in bilateral contracts. Figure 2 is a fairly dramatic demonstration of the success of the PJM market in attracting new investment.

As can be seen, despite having increased load in 2002, the point at which peak load meets the supply curve is significantly lower than in 2001.⁷ This is almost entirely accomplished through increased supply entering the market, and it represents decisions made by market participants on investments in the PJM area based on previous experience with prices both in the bilateral and spot markets. Taken from a public policy perspective, however, it would seem to represent a significant validation of a well-established wholesale market delivering pricing benefits for customers in a reliable fashion.

So what would my father say about the acrimonious debate we find ourselves in regarding electricity policy? Despite being a Republican, he often liked to quote Lyndon Johnson when beginning a conversation on a controversial subject: "Come, let us reason together." While state regulators and others who have concerns about the development of competitive wholesale markets need to have their issues addressed, it is important that such concerns be based on accurate assumptions. If we can set aside emotion and deal with the facts available, the ensuing national debate can yield a policy whereby states' prerogatives are protected while developing RTOs that work in cooperation with states to ensure competitive wholesale markets.

I believe PJM's experience of the last six years would be useful in such a discussion. Let us reason together.

The PJM region includes all or parts of Delaware, the District of Columbia, Maryland, New Jersey, Pennsylvania, Virginia and West Virginia, representing a load of approximately 65,000 MW.

"Installed Capacity" or ICAP is a resource that may be used by load-serving entities to meet reliability obligations relative to their load. Generators receive a payment for being ICAP resources and adhering to the rules applied to such resources.

FTRs have been allocated to those who request them. We have had members who entered the PJM market "naked" or without requesting FTRs, but the vast majority have used them to offset nearly all costs. PJM also has had members who have designated FTRs from specific resources to load and then procured energy from other areas to load which effectively negates the value of the FTRs. PJM views this as unfortunate but can not make market decisions for market participants.

See SEARUC study, prepared by Charles River Associates, January 2003.

PJM does, however, try to facilitate demand response where appropriate.

Definition of "spot" market depends on one's perspective, but for PJM, this is the day-ahead and real-time market.

Making comparisons between years is often difficult given the variability of critical factors such as weather. However, the dramatic change represented in Figure 2 provides some evidence as to the success PJM has had in attracting investment as the weather of the summer 2002 peak season was considerably more severe than in the Summer of 2001.

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