Letters to the Editor
October 2004
To the Editor:
Curt Hébert's article in the August issue ("Profit Without Costs," p. 40) argues that assigning all costs associated with transmission upgrades to competitive generators will result in the fairest method of cost allocation in the Entergy service territories. Despite its in-depth treatment of this issue, the article fails to make the case that such assignment is the best way to manage transmission upgrade costs.
This is particularly true in a region where a single dominant generation and transmission owner will be making the critical decisions about who will benefit from transmission upgrades. The article makes no mention of the difficulties associated with assigning costs and benefits for new transmission. Clearly, this activity must be undertaken by an independent third party, such as an RTO, and not by an entity with a vested interest in the outcome.
Even the title of the article, "Profit Without Costs," is misleading. In the Entergy region, the reality for competitive generators is "costs without profits." Competitive generators have invested approximately $200 million for transmission upgrades to ensure deliverability of their electricity to the Entergy multi-state region. Not only did those costs entail no profits, but they came with precious few revenue streams from energy, capacity, or ancillary services.
Without access to wholesale customers, generators are often limited to recovering marginal energy costs, with little opportunity to recover capital or earn a return on the investment. The cost-without-profit syndrome is principally due to Entergy's generation dispatch protocol, which generally ensures that older, less efficient, more costly plants get dispatched ahead of new, more efficient, cleaner, and less-costly plants.
The fatal flaw with Entergy's approach to funding transmission upgrades is that it assumes that electricity from competitive generation built in one utility's service territory will be shipped to another part of the country, leaving the host utility's customers with only costs of the infrastructure and none of the benefits of lower-cost generation. In the real life world of the Eastern Interconnection, the vast majority of any power plant's output stays relatively close to home-that is, within the region (e.g., Entergy or SERC). Even with limited access to customers by merchant generators, it is clear that prices in Entergy's service territories declined as new generation came on line between 2000 and 2002. One study documented a 41 percent decrease in wholesale prices.
What is needed is real participant funding of transmission upgrades, whereby costs are shared between all beneficiaries-suppliers, utilities, and end-use customers-as determined by an independent, impartial entity.
Lynne H. Church, President
Electric Power Supply Association
To the Editor:
Your recent article, ("Nodal-Zonal Debate Re-Emerges in New England," Fortnightly's SPARK,
August 2004) concerns the nodal-zonal pricing debate and outlines some of the challenges associated with implementing pricing methodologies that reflect the differences in power costs by location. The article focuses on the debate as it has unfolded in New England. However, New England's experience is by no means unique. For example, while many control areas have implemented full nodal pricing of supply-including New England-no control area has yet implemented full nodal pricing of load. Zonal pricing of load is the method that is generally used. The rules concerning locational pricing of load in New England are generally consistent with those of other control areas such as PJM and NYISO. With the implementation of Special Case Nodal Pricing in New England, the policy of allowing certain loads to be priced at a specific
node will be consistent with that of PJM (see Occidental Power Services, Inc. v. PJM Interconnection, L.L.C., Docket No. EL03-42-001).
The challenges for implementation of full nodal pricing for load are clear; it is both a costly undertaking and requires transmission and distribution companies, as well as customers, to bear additional responsibilities and costs without a guaranteed benefit from the expenditures. Moving from average zonal pricing to nodal pricing raises concerns because such a switch creates a divide between those who benefit and those who do not; the load at nodes with lower-than-average prices would readily benefit from nodal pricing, while the remaining loads would not. While this might be economically efficient, it is not an easy debate to settle, especially to those at higher-cost nodes.
What may be unique to New England is the lack of substantial energy price separation among the region's zones to date. If the level and pattern of energy prices among nodes within a currently defined load zone were similar, as our studies have shown, the additional transparency provided by nodal pricing likely would not produce an increase in economic, price-responsive loads compared to zonal pricing. Certainly, incurring the expense and effort involved in publishing, tracking, and settling loads among more than 600 separate pricing nodes as opposed to eight zones
would be questionable under such circumstances.
In order to advance the goals of price transparency and market-based demand response, ISO New England proposed to implement Special Case Nodal Pricing (SCNP), which would permit larger loads (those that are 5 MW and larger) to be settled on a nodal basis. An overwhelming majority of the New England's market participants, including the NEPOOL Industrial Customer Coalition cited in your article, found SCNP to be a reasonable alternative to full nodal pricing of load.
In the future, energy prices may exhibit greater price separation as loads grow, as resources are added to or are retired from the system, or as the transmission infrastructure is modified. Such changes may eventuate the need for more granular pricing by location. In addition, the introduction of new markets could create the need for more geographically specific pricing. Even though energy prices might be similar among nodes and zones, the introduction of a locational capacity market, as an example, could require a change in the configuration of load zones to give capacity resources the incentive to locate in the areas that most need them. ISO New England has agreed to conduct periodic studies to determine if and when load zones ought to be reconfigured as system or market conditions change over time.
Your article raises an excellent perspective-one that ISO New England shares-that full participation of load in the wholesale market is preferable to non-market programs designed to encourage greater price-responsive loads. However, the implementation of a perfect set of wholesale market rules would not necessarily lead to efficient levels of demand response because wholesale price signals may not be reflected in the retail prices paid by the vast majority of retail customers. While retail customers ultimately provide demand-response resources to the market, the prices paid by retail customers are governed by state policy, not by wholesale market policies. State policies tend to require the provision of Standard Offer energy products with prices that do not change as power costs change. SCNP is a step in the right direction, but it would only enable larger retail customers to be integrated into the wholesale market at this time.
Given these challenges, to encourage smaller customers to become more price-responsive, ISO New England must implement special programs to elicit this response. The need for such programs should subside as wholesale and retail markets are better coordinated and as more experience is gained with SCNP and other market-based options that would allow smaller loads to more fully participate in the market.
I appreciate your consideration of the various challenges associated with nodal pricing for load. It is certainly a matter to which ISO New England and other ISOs and RTOs are paying attention and developing workable solutions to address. We look forward to future coverage from your publication that follows this debate as it unfolds across the nation.
Gordon van Welie
President and CEO, ISO New England
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Utilities Fortnightly & Spark
