Costs Associated with Running RTO Markets

by Diane Moody, APPA

The original goal in establishing Regional Transmission Organizations (RTOs) was to bring cost savings to consumers by providing adequate, reliable and reasonably priced transmission service. Important RTO functions included the provision of non-discriminatory transmission service, the elimination of transmission rate pancaking and a means for joint planning and construction of transmission facilities.

Now, however, RTOs have grown in complexity and assumed additional functions. As a result, the cost of administering RTOs has risen and at the same time, utilities have experienced additional costs to participate in RTO markets. Whether the benefits of RTO markets are large enough to offset all additional costs remains an open question.

A recent report by the consulting and engineering firm GDS Associates summarizes the trends in RTO operational and administrative costs for the time period 2001 to 2005 and the charges RTOs assess to recover their costs. The study covers the SPP, CAISO, ISO-NE, MISO, NYISO and PJM.

In 2005, participants in these markets were billed more than $1 billion for RTO operational and administrative costs.

Day-1 RTOs administer open access transmission tariffs, perform reliability functions and transmission planning, and manage transmission through traditional methods, such as redispatch and transmission loading relief. They may also administer a real-time or balancing energy market. SPP is currently the only Day-1 RTO.

SPP’s costs were $48 million in 2005, the first full year it operated as an RTO. That’s about $0.24 per MWH, slightly above the 2004 FERC study staff estimate of $0.16 to $0.22 per MWH for a typical Day-1 RTO.

Day-2 RTOs perform the same functions as Day-1 RTOs but also run market operations for day-ahead and real-time energy, and for transmission congestion. In addition, many Day-2 RTOs operate ancillary services markets and capacity markets.

The study found a wide range in costs for the five FERC-jurisdictional Day-2 RTOs it covered, reflecting in part the different sizes of the RTOs. At MISO, for example, total operational and administrative 2005 costs were $273 million, while at ISO-NE the total was $124 million. MISO’s 2005 MWH load was four to five times as great as ISO-NE’s. However, comparisons on a cost per MWH basis indicate that there may be economies related to size. In 2005, the cost per MWH for the two smallest RTOs, ISO-NE and NYISO, was more than twice as high as the cost for the two largest RTOs, MISO and PJM.

Over the study’s 2001-2005 time period, total costs increased by 98 percent for ISO-NE, 66 percent for NYISO, 94 percent for PJM, and 228 percent for MISO (2002-2005 time period), while costs for CAISO declined. On a dollar-per-MWH basis, costs increased for ISO-NE, MISO and NYISO, and fell for PJM and CAISO. The decline in PJM’s cost per MWH in part reflects the large increase in PJM’s load, as the PJM footprint expanded over the five-year time period.

Cost categories

The GDS report also classified RTO costs into operational and administrative categories. Operational costs include load dispatching, operation and maintenance supervision and engineering, and maintenance of plant. Major administrative costs include rents, depreciation, regulatory costs, consulting fees and administrative salaries. Across all RTOs, administrative costs averaged about 75 percent of total costs, but there is significant variation between RTOs. Administrative costs ranged from 63 percent of the total for CAISO to 99 percent of the total for MISO. (See Table 1.)

A closer look at one type of RTO cost highlights how inconsistent reporting makes it difficult to compare costs between RTOs.

Table 1. Summary of Total Operational and Administrative RTO Costs in 2005 Click here to enlarge image

FERC’s Uniform System of Accounts designates accounts 901 through 910 for costs related to customer services. Two of the RTOs, NYISO and ISO-NE, use Account 905, Miscellaneous Customer Accounts Expense, and Account 910, Miscellaneous Customer Service and Information Expense, for the bulk of their customer-related costs. Two others, CAISO and PJM, use Account 903, Customer Records and Collection Expense, and Account 908, Customer Assistance Expense, for most of their customer-related costs. Thus no useful comparisons can be made between types of customer expenses, and since MISO reports only minimal amounts in any of these accounts, lumping all of the customer-related accounts together does not help.

This lack of consistency was identified by FERC staff in their 2004 study, “Staff Report on Cost Ranges for the Development and Operation of a Day-One Regional Transmission Organization.” RTOs report financial data to FERC using the Uniform System of Accounts but this accounting system was designed for traditional utilities so it’s not always suitable for reporting RTO functions. FERC addressed this issue in Order No. 668, “Accounting and Financial Reporting for Public Utilities Including RTOs,” implementing more consistent reporting beginning with 2006 data that will be filed in the spring of 2007. These new rules should make for more meaningful comparisons between RTOs, but as the example of customer-related expenses shows, only if RTOs interpret the new cost categories in a uniform manner.

Recovery of RTO costs

RTOs recoup their costs from market participants, which include all of the utilities serving end-use customers in each of the RTO regions. These cost recovery mechanisms, which are set forth in their tariffs, can be complicated, and each RTO uses a different set of rates and formulas, but in general, the mechanisms contain several different components designed to charge costs on various bases-per MWH, per megawatt or as a fixed monthly charge, for example. The rates for each component are also subject to periodic adjustments and typically include a mechanism to true-up costs that have been over- or under-estimated.

In addition, the various cost recovery components apply to different categories of market participants. For example, both MISO and PJM collect costs associated with running their financial transmission rights markets from all holders of financial transmission rights. The NYISO cost recovery system, on the other hand, is much less detailed. Most costs are lumped together, with 80 percent of budgeted costs assessed to market participants that withdraw power from the system and 20 percent assessed to participants that inject power into the system.

The tariffs governing RTO operations are huge, and the sections related to cost recovery can be extremely detailed and complex. CAISO’s Appendix F, which governs RTO rates, is 500 pages long. This complexity means market participants have little ability to track the overall accuracy of RTO cost recovery assignments.

Costs incurred by utilities to participate in RTOs

The GDS report summarized costs incurred by RTOs themselves, but did not consider a second category of costs that have arisen from the onset of RTO markets: increased administrative costs at utilities resulting from their participation in these markets. Typical new costs incurred by utilities participating in these markets include the purchase of software to “shadow” and process RTO settlements and the hiring of staff to deal with RTO settlement statements.

Billings can be revised numerous times. In MISO, for example, day-ahead and real-time market charges are settled a minimum of seven times. Utilities receive a preliminary statement seven days after the transaction date, an invoice on Day 14, and further settlement statements on Day 55, Day 105, Day 252, Day 399 and Day 546.

Other collateral expenses that have increased because of participation in RTO markets include consultant fees and legal bills, as utilities turn to outside expertise to implement software systems, provide advice on power supply procurement and design risk management plans. This last issue is crucial, as utilities in RTO markets have been exposed to much greater price volatility. Thus utility managers must develop effective strategies to minimize power supply risk, including estimating the future behavior of natural gas prices and the need to mitigate transmission congestion.

Legal and regulatory workload has increased, as utilities need to protect their interests in FERC proceedings involving wholesale power supply and the implementation of RTO markets. Just keeping track of these regulatory proceedings as well as changes in RTO market rules and tariff provisions takes up significant internal staff time and requires more consulting hours. Active participation in regulatory proceedings or RTO meetings is an even greater investment, and often includes travel time and expenses.

The higher costs are especially problematic when a utility perceives that it is actually worse off under the RTO regime, as is the case with the municipal utility in Chambersburg, Pa. Chambersburg has spent almost $1 million in legal fees over the last few years to track changes occurring in PJM. Despite these efforts, the utility was surprised in the spring of 2006 when PJM dramatically reduced the utility’s allotment of financial transmission rights. According to Chambersburg’s electric superintendent, the utility is spending hundreds of thousands of dollars to defend its right to continue its historical use of transmission facilities.

While there has been no comprehensive accounting of how utility costs have changed as the result of participation in RTO markets, anecdotal evidence indicates they have risen. The end-use customer must ultimately pay these higher costs and the recovery of RTO costs, so it is important that RTO markets provide benefits large enough to offset all costs. Many studies have attempted to quantify benefits from RTO markets, but major methodological flaws make their conclusions questionable. Further research on both the costs and benefits of RTO markets is very much needed.

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