Shopping credits, capacity rules and other mistakes from California and PJM.

With retail electric markets opening rapidly, why are so many getting off to a slow start? Why do suppliers abandon some markets and consumers decline to participate in others? The answer may lie in a series of disconnections between wholesale trading patterns and retail opportunities.

Utilities, marketers, suppliers and electric customers have joined with state public utility commissions to invest thousands of hours and millions of dollars to set up these new markets in a way that will help consumers and regional economies. Their goals are laudable. Yet they have paid little, if any, attention to the intricate interfaces between the retail and wholesale markets for electricity. This omission has slowed or crippled development of even potentially robust retail markets.

One need not look far to find causes for these disconnections. In large part they stem from conflicts between state and federal rules at the PUCs and the Federal Energy Regulatory Commission. In general, there appears to be a lack of appreciation for how wholesale rules can affect the success of retail competition. Meanwhile, regulators get distracted by seemingly more pressing issues, such as stranded costs, reliability and customer protection. And within some regional markets, organized by an independent system operator, or ISO, it appears that some members really would prefer to slow down competition.

Overall, we can identify five disconnections between wholesale and retail electric markets, suggesting the need for five corresponding solutions:

1. Boost Shopping Credits. Consumers won't see savings and suppliers won't see profits unless shopping credits exceed the bundled cost of generation, fully loaded for such items as line losses, capacity charges, risk management and costs for customer acquisition and handling. Include stranded-cost true-up for customers taking standard offer.

2. Tailor Credits to Load Patterns. Add demand component to mirror wholesale capacity costs, ensure no bias between customers with high and low load factors. Consider a seasonal or time-differentiated shopping credit.

3. Eliminate Capacity Obligations. Power pool requirements for installed capacity are outdated. They serve no purpose under retail competition.

4. End Locational Marginal Pricing. Separate prices at each bus or node add too much fine tuning and discriminate against suppliers in allocating fixed transmission rights (FTRs). The regulated regime worked fine without LMP; so can retail competition. But if LMP is retained, then allocate FTRs by load, not supplier.

5. Let Disco Arrange Transmission. Give suppliers the option of purchasing transmission or relying on the regulated wires utility to provide such service, to avoid an unfair shift of risk to competitive suppliers.

Regardless of the reason, these disconnections must be bridged. If retail electric competition is to flourish, then retailers, wholesalers and regulators alike must identify and solve these market disconnections. The job may mean more work up front, but should yield commensurate benefits to all involved. Consider, for example, the problems that have occurred in two market regions, California and PJM Interconnection.

Learning from California

The first year of retail competition in California revealed several disconnections between wholesale market rules set by the independent system operator and retail rules set by the state Public Utilities Commission. They concerned shopping credits, procurement of reserve power, ancillary services and congestion management. Some reforms now are in place - only time will tell if they will mitigate past distortions.

The most overwhelming disconnection that occurred in California involved the retail shopping credit, known as the "PX credit," designed to reimburse direct access customers by backing out the market price of wholesale power as determined on the California Power Exchange. During the first year of competition, the PX credit was set consistently below the all-in wholesale cost of retail electricity. This disconnection continues to cripple the residential and small commercial markets for competitive retail electricity. It must be corrected by unbundling the retail tariffs so that the retail credit provides customers with an opportunity to save when they shop.

During the peak demand periods of summer 1998, exorbitant price spikes occurred, with capacity selling in excess of $5,000 per megawatt per day. Among the disconnections that contributed to these retail price spikes were two rules in the wholesale market concerning operating reserves and ancillary services.

First, the ISO set a limit of 25 percent on the portion of operating reserves supplied by out-of-state imports. The rule required the ISO to secure too much capacity from within the system, thus raising prices for this ancillary service. Since then, the ISO has changed its protocols and systems and now allows up to 50 percent of operating reserves to be imported.

Second, cost-based caps imposed on the price of ancillary services (including capacity) encouraged owners to withhold capacity from the market. Capacity holders claimed that operating constraints made plants more expensive to operate than could be offset by the cost-based cap revenues. Some blamed the caps, while others claimed that utilities were exercising market power under the protection of antiquated reliability must-run ISO rules. In late October 1998, the FERC issued an order lifting all cost-based caps.

The removal of cost-based caps and the easing of import restrictions has helped avoid price spikes during the summer of 1999, at least through early August. Nevertheless, other issues still must be addressed.

First, the California ISO needs to reassess the need for its congestion management system (CONG) with more than 3,000 buses. The CONG is extremely cumbersome and costly. It adds unnecessary risk to providing competitive retail service. Marketers have proposed a "simplified transmission congestion management system" based on 10 to 15 zones. This simplified system could be run in lieu of the CONG, except where certain types of congestion are indicated.

Second, the California ISO could implement a 1997 FERC order requiring that utilities make available at market-determined rates fixed transmission rights not under contract. This enhancement to wholesale procedures effectively would make more generation resources available for the supply of competitive retail load.

Third, the ISO could recognize more of the potential for customer-specific load control. The technology is in place, in whole or in part, to allow for site-specific load control and for those customers to receive cost savings. Until now, the ISO has only been willing to consider load shedding from the largest load sources, depriving many smaller customers of cost savings and requiring suppliers to purchase unnecessary generation resources.

Learning from PJM

As wholesale and retail competition heats up throughout the mid-Atlantic region, PJM has assumed the task of providing for a reliable system "in a manner consistent with the development of a robust competitive marketplace." So far, the results are mixed. On the good side, the system has remained reliable. On the down side, the market has not lived up to its potential. Two of the factors that have retarded this development are the installed capacity requirement and implementation of locational marginal pricing.

Installed capacity, or ICAP, is rooted in the days when being an electric company meant building generation, transmission and distribution systems for a captive group of customers. Don't have enough generation? Just pay your fellow pool member to use his extra, or so the reasoning went.

This approach has little relevance in a deregulated market, however, as marketers search the country to bring their customers the greatest savings. In an effort to make a more vibrant installed capacity market, a series of monthly auctions was held and a daily clearing market instituted. These markets have done much to lessen the burden of installed capacity, but they have not resolved the overarching issue: Installed capacity is no longer needed. More recently, PJM has formed a committee to explore alternatives to an installed capacity obligation.

LMP was introduced in PJM on April 1, 1998. Immediately, there was a sharp curtailment in wholesale transactions, with volumes dropping from 20,000 megawatt-hours to less then 5,000 MWh. The change initially had minimal effect on electric generation suppliers (EGSs), as they were not required to provide transmission service under the Pennsylvania pilot program.

However, as of January 1999, EGSs were required to provide transmission service and were exposed to the price fluctuations associated with congestion. Fixed transmission rights are the main instrument used to protect companies from the price fluctuations associated with congestion. Unfortunately for new EGSs, by the time they arrived on the scene, incumbent utilities already had been given the ability to select the FTRs for free. That virtually eliminated the opportunity for an EGS to protect itself from the congestion risk of LMP. The disconnects in the wholesale and the retail market still can be seen clearly in the lackluster interest in New York Mercantile Exchange futures contracts and the lack of choice for many customers in Pennsylvania.

The market responded by adjusting the way LMP was implemented in Pennsylvania and elsewhere in PJM. For instance, there was a consolidation around the one price seen at the Western Hub. Likewise, in the retail market, the 1,600-plus bus prices have been aggregated into several zonal prices that are more manageable from a risk-management perspective.

These modifications within PJM, namely the pooling of buses and the elimination of ICAP, bode well for all parties doing business in the region. In particular, customers will benefit from lower prices that follow from vibrant competition.

Solving the Market Mismatch

How does the California and PJM experience translate into policy action to jump-start competition? Here are some solutions. Some of these solutions will require extra attention by state PUCs, while some will require FERC action. Others will force the ISOs to do more to assure that competition will flourish. None should require any fundamental jurisdictional change. Yet each of these solutions will require policymakers to become more cognizant that what they do affects the viability of markets.

1. Boost Shopping Credits.

If the wholesale cost of electricity, fully loaded for line losses, capacity charges, risk management and customer acquisition and handling charges, is greater than the retail shopping credit set by state commissions, there cannot be savings nor profits. A broad-based commodity market for electricity cannot be sustained under these conditions. This situation crippled the residential market for electricity in California, delayed the retail markets in Massachusetts and Rhode Island and even hampered some markets in Pennsylvania.

The credit provided by state regulators to the consumer under the generation portion of the retail tariff must be sufficiently greater than the total cost of buying wholesale power and delivering it to a specific customer or there will be no competition. Yes, competition is about more than price and short-term savings. But without the ability to deliver savings immediately, there is little reason for the market to get started.

When setting shopping credits in retail tariffs, state regulators should err toward setting the credits higher than absolutely necessary. If saving opportunities are too small, even a small unexpected increase in the wholesale cost can kill the retail market.

Some so-called economic theorists claim that there should be no premium above current costs to encourage customers to shop for electricity. These same theorists seem willing to provide for full recovery of stranded costs and disregard the real-world friction costs of getting people to change their purchasing habits. This adherence to so-called economic purity only delays competition and its benefits while creating deregulated monopolies.

Not only is it proper and necessary to set retail credits sufficiently above the delivered wholesale cost, but it also is possible. The Pennsylvania Public Utility Commission, in the face of enormous stranded-cost claims and without passing on to customers the savings of securitization in many cases, constructed tariffs where the shopping credits produced double-digit percentage savings on total bills.

When establishing shopping credits above the wholesale cost, state regulators also must establish a true-up mechanism that adjusts stranded costs when customers do not switch. Failure to do so will produce unintended windfall profits for utilities when customers stay with the utility, and therefore encourage the creation of impediments to competition. It always is preferable to eliminate the incentive for bad behavior than to try to cure bad behavior after it has occurred.

2. Tailor Credits to Load Patterns.

Not only is the absolute difference between the wholesale cost and the retail credit important, but so are the structures of their underlying components. One comparison that must be made is between the wholesale cost of capacity and the demand component in the retail credit. For example, if the wholesale capacity charge produces a smaller dollar amount than the retail demand charge, customers with poor load factors will tend to save relatively more than customers with high load factors. This disconnection can skew market acceptance to low-load-factor customers, contrary to general expectations about the electric market.

Across the country, each retail market is setting different rules for shopping credits, also known as back-out rates or standard offers. In some states, the credits are purely energy-based; other areas have energy and demand charges restricted to a single billing period or seasonal ratchets. In general, states simply are extracting a piece of the existing retail tariff and dedicating it to generation charges in an effort to avoid inter- and intra-class revenue shifts.

At the same time, the structure of the wholesale markets is being ignored. With two systems operating asynchronously, it is more difficult to identify what savings can be offered to individual customers. That increases the transaction costs of obtaining a retail customer. It also can cause de facto discrimination of benefits among customers shopping for electricity.

States need to invest more heavily in the development of a shopping credit with a design congruent to the wholesale market's. Some type of time-differentiated shopping credit, even based on agreed-upon load profiles for smaller customers, may be a good answer. Such a credit would encourage construction of wholesale transactions that could be compared with relative ease.

3. Eliminate Capacity Obligations.

In some markets, such as PJM, suppliers are required to purchase capacity in addition to firm energy. However, capacity markets are often liquid.

A great deal of uncertainty and risk can arise in a market where there is an explicit capacity obligation in the wholesale rules without a liquid market for capacity. Even in markets with excess installed capacity, retail suppliers fear the uncertainty of anomalous price spikes caused by high weather-driven demand, unplanned unit outages and/or capacity hoarding by incumbent utilities. A one-week spike in capacity prices can increase the average annual cost of electricity by a couple of mills per kilowatt-hour. This increase is significant in a market where margins are often a mill or less.

In addition, with capacity pricing uncertainty come market power, capacity availability and gaming. As markets open, suppliers often find that they can buy all the energy they want but none of the capacity they need. Without proper safeguards, incumbents can create shortages by selling capacity outside of the ISO. This wholesale behavior by holders of capacity can bring retail markets to a screeching halt.

The simplest solution is to eliminate the requirement for capacity purchase and require only that firm energy be purchased. Separate capacity obligations do not exist in many regions, with no adverse impact on reliability.

If, for some reason, that is not possible, there are several second-best solutions including requiring that a utility's installed capacity follows the customer when the customer switches suppliers; requiring that utilities divest their capacity (and generation), thereby creating a more liquid market; and/or requiring that there be an auction of all capacity both on a day-ahead and a long-term basis.

4. End Locational Marginal Pricing.

Locational marginal pricing marks another wholesale element that has added risk to the business of providing retail supply.

LMP is a method of setting prices for congestion in transmission service, based on how transmission constraints affect the relative price of energy available at different points on the grid. LMP, strangely, is being introduced to wholesale markets where postage stamp rates existed prior to retail competition. To date, it seems only to have introduced unnecessary uncertainty and costs to competitive retail pricing - another way that wholesale rules are slowing competition.

Moreover, LMP has introduced a second distortion, linked to the system used to hedge LMP congestion prices.

Transmission rights (sometimes called fixed transmission rights) allow suppliers of energy to deliver electricity from point of generation to point of use. These rights help a supplier avoid the uncertainty associated with prices charged for line congestion under LMP. In some places (e.g., PJM), FTRs were granted unilaterally by the ISO to incumbent owners of generation and load (i.e., incumbent utilities) at no cost. These incumbents, then, were freed of the risks associated with LMP and/or other potential transmission constraints. The result is that utilities have no LMP risk, while competitive suppliers incur the risk and costs. This wholesale market policy has slowed retail competition.

In reality, LMP is simply an effort to overly fine-tune the pricing of transmission service. LMP was not used prior to retail competition. Elimination of this policy allows for a better connection between the wholesale and retail markets, as the risk of serving particular customers is not increased unnecessarily. This step should make FTRs relatively unimportant, as it will be necessary only to get power onto the grid.

On the other hand, if LMP is not eliminated, system-wide shares of transmission rights should follow the load regardless of the supplier, rather than being summarily assigned to a supplier (particularly the incumbent utility). That would protect customers who shop for electricity from losing a benefit they had prior to competition.

5. Let the Disco Arrange for Transportation.

Historically, the local electric company took on the obligation of providing intra-regional transmission services. The rates were and continued to be regulated by the FERC. Throughout the debate on electric competition and deregulation, all agreed that transmission and distribution services are natural monopolies (i.e., there is no reason to have two sets of wires going down a street) and that these services would remain regulated.

But in some cases, utilities and/or ISOs have decided to shift responsibility for transmission service to the competitive supplier, a seemingly neutral move that nevertheless affects retail markets.

First, the utilities have shifted the cash flow and collection costs of transmission services from the utility to the competitive supplier. Second, the credits that utilities grant for transmission service and the wholesale-regulated price are not always equal. The FERC rate usually is a pure demand charge, while the regulated retail rate usually has an energy component. If the total cost recovery under the two regulated paradigms were equal, then this shift in responsibility for transmission service would penalize customers with lower load factors.

There is no reason to have intra-regional transmission service delivered by anyone other than the local distribution utility. Although state commissions may want to keep the option open to the supplier to purchase its own transmission service, it should be at the supplier's option. Utilities should be required to provide this service, as well as billing and collection of associated revenues. That eliminates the transfer of unrelated business risks from the utility to the supplier and eliminates complexities where subtle savings and losses are associated with these transactions because of the mismatch between the wholesale and retail tariff. It also keeps this service where customers expect it to be.

David Magnus Boonin is president of the Philadelphia consulting firm that bears his name. The firm focuses on strategic decisions and implementation protocols in deregulated energy markets. Until recently, Boonin was an executive vice president for NewEnergy Inc., then known as New Energy Ventures. He is former chief economist for the Pennsylvania Public Utility Commission.

Stephen R. Fernands, author of the PJM section of this article, is president of Customized Energy Solutions and provides economic analysis for utilities, marketers and end-users entering deregulated markets. He also is a consultant to NewEnergy Inc.

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