his summary is based on a compilation performed by
Community, Trade and Economic Development (CTED) Energy Policy staff in connection with
its participation in the Comprehensive Review of the Northwest Energy System. In fall
hearings before the Housing Committee on Energy and Utilities, the Committee heard
testimony from five utilities that were offering or planning to offer retail choice or
market-based prices to its customers. This report builds on the information presented at
that hearing and adds some additional information based on telephone conversations with
eleven utilities throughout the state.
TED first decided to undertake a compilation of
market-based rate programs when it became apparent through news reports and other
information that the number of utilities across the state that were offering market-based
rates was growing from a small handful to a discernible ground swell. While a few
utilities began experimenting with market-based rates in late 1995 or early 1996, the pace
has picked up during the Fall of 1996 after publicly owned utilities finalized
negotiations with Bonneville Power Administration (Bonneville) for diversification of
power supplies.
CTED targeted programs falling into one of three categories, defined as follows:
For simplicity, we generally refer to all of these programs as market-based rate programs except where it is necessary to draw distinctions. Excluded from the list are utilities that reduced their rates to particular classes based on new cost-of-service studies or considerations of competitiveness. While the latter group of utilities may have taken advantage of market access to reduce rates to their customers, they did not base their rates directly on market prices, and have not unbundled the energy portion of their rates from the distribution function.
The compilation is not based on a comprehensive survey of Washington utilities, but rather on press reports, testimony at legislative hearings, rate filings with the Utilities and Transportation Commission, and individual reports. Therefore, it is possible, indeed likely, that the compilation is not complete. The approach we took was in two phases. We first reviewed regional press reports dating back one year (i.e., to October 1995) concerning utility market-based rate, retail access, or quasi-wholesale access efforts. These included trade press reports (i.e., Clearing Up), local press, regulatory proceedings, and the testimony of several utilities at a recent hearing before the House Energy and Utilities Committee.
CTED Energy Policy Staff followed up each such report with a phone call to the utility. There was a telephone or personal conversation with all eleven utilities that were reported as negotiating, considering, or implementing market-based rates or retail access. While no utility specifically asked to keep the results of the conversations confidential, we made an internal decision to summarize the results of the conversations in order to avoid singling out particular utilities or customers for attention. However, since the reports of market-based rates all originated in the press, they can be easily verified through the same means CTED used.
For each utility offering market-based rates, we asked a number of questions. These included:
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f the eleven utilities we contacted, 10
confirmed that they were offering market-based rates, quasi-wholesale access, or direct
access. The 11th utility did not meet the definitions set out above.
Six of the utilities offering market-based rates congregate in the I-5 corridor, with the remaining four spread throughout the state. Two are privately owned utilities, and eight publicly owned. Size and resource mix were not clear identifying factors. However, the presence of large industrial load was clearly common to all 10.
All eight of the publicly owned utilities were taking advantage of the diversification opportunities provided by Bonneville in its recent round of power sales contract negotiations to make market-based rates available. That is, utilities who chose to diversify 10 percent, 15 percent, or more of their load by purchasing from providers other than Bonneville chose to use those options to gain access to the market directly on behalf of their eligible customers. This fact becomes important when we consider the likelihood of expanding retail access to other end use customer classes.
All 10 utilities currently offer market-based rates only to large industrial customers. Five of these offered rates based on a minimum size, which ranged from .75 average megawatts (aMW) load to 10 aMW. The other five negotiated rates with individual large customers. The total eligible load among the 10 utilities is about 1,005 aMW. Of these, a small amount (24 aMW) represent direct access eligibility; approximately 20 aMW of load is eligible for quasi-wholesale transactions; and the remainder is "virtual" direct access.
Two utilities are actively considering expanding eligibility to other classes early in 1997. If this occurs, total eligible load will grow about 1,080 aMW, for a total of 2,165. [Note 1] Of this figure, about 380 aMW would be virtual direct access and about 800 aMW would be direct access.
Customers with at least 610 aMW of load were actually taking advantage of market-based rates as of the time of the telephone contacts (early to late October 1996). It is likely that the number has grown since then. The total number of customers who have signed on is about 30. Thus, the average size of the subscribing customer is approximately 20 aMW.
Of the 10 utilities with programs, seven base the energy component of the price on actual contracts negotiated with other utilities, brokers, or marketers. These contracts could be negotiated by the end use customer, by the utility, or jointly. The other three utilities base the energy component of the rate on an index -- either California-Oregon Border (COB), or the Dow Jones mid-Columbia index.
All 10 utilities charge an access fee, distribution fee, or the like to cover distribution costs. Here we found a very large disparity among the utilities in how they calculated and priced this service. The range of access fees is from 2 mills (two tenths of a cent) to over 22 mills. The disparity was generally, but not exclusively, related to the types of services included in the access fee. Because of the disparity, and its implications, we will discuss this aspect of the rate in some details.
The most "bare bones" access fee simply charges for the actual wire's maintenance cost to serve the individual eligible customer. Since many of these customers own their own facilities and are in close proximity to Bonneville transmission, the resulting access fee is small indeed, on the range of 2 mills.
In the next range of access fee prices are utilities that average the cost of access over eligible customers, regardless of their actual proximity to transmission. Utilities using this method generally charge approximately four mills, but the charges range as high as 12 mills.
The next grouping involved utilities that include components of fixed cost in the access fee. These could include administration and general expenses, dues, power management, etc.
In addition to including non-power related fixed costs in the access fee, one utility is recovering some or all stranded power costs in the fee.
Finally, two utilities explicitly recover some demand side management (DSM) program costs, renewables, and low-income support costs in the access fee. But one of these is recovering only debt costs associated with existing DSM installations, not the cost of running any ongoing or new programs. Only one of the 10 utilities charges an access fee that explicitly covers DSM and low-income support, based on an estimate of future utility commitment to these programs.
Three utilities used "top down" approach for calculating the access fee. That is, they removed the energy component of an existing tariff and used the remaining portion of the rate as a reasonable proxy for the utility's core distribution services. Under this approach, the resulting access fee represents the average historic cost of providing all but commodity services. Thus, it likely includes components of all the applicable costs and services described in the previous paragraphs, at historic levels. One should not conclude, however, that this means DSM, renewables, and low-income support are at historic levels for these utilities. Publicly owned utilities historically paid for most DSM and renewables via their Bonneville rates. Since Bonneville's funding has dropped significantly, utilities that are charging only their own historic levels have not picked up any regional responsibility for continued DSM and renewable support.
Finally, taxes are not included in any utility's access fee, but are added onto the rate as a separate charge.
The table below summarizes the types of costs that are included in the access fee, and how many utilities include these costs. [Note 2]
Costs and Services Covered by Access Fee |
Number of Utilities |
| "Top down" — all historic services at historic levels | 3 |
| Wires and facilities Per customer |
|
| Administrative and general | 6 |
| Stranded cost | 1 |
| Demand side, renewables, low-income Historic levels |
|
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ore work and research needs to be done before
drawing many firm conclusions from this compilation. As noted, it is not comprehensive,
nor statistically significant. Other utilities will no doubt use the examples of these
pioneers in designing their own programs. However, the compilation does allow us to make
some observations that could be useful to the Legislature as it considers the impacts of
retail access on Washington citizens, the economy, and the environment.
First, retail competition is alive and well in Washington State. A recommendation to "prepare for retail competition" sometime around the turn of century ignores the fact that it has already occurred here.
Second, utilities are exercising imaginative and innovative efforts to tailor their service to the needs of their customers. CTED believes that the ability of customers to get exactly the type of service they want, negotiate the amount of price risk they want to assume, and undertake some of the power acquisition responsibilities on their own is where the true benefits of retail competition are strongest. Utilities and end users alike will benefit from the experimentation and variety of approaches employed in these early efforts.
Third, the extent to which significant retail competition will be meaningful for commercial and residential classes is unclear, without clarification of Bonneville's ability to recover stranded costs. Under the just-completed power sales contract renegotiations, Bonneville only allowed a portion of load to diversify without paying an exit fee. Once those diversification benefits are passed along to end use customers in one class, there is a limited amount left for other classes. Some of the utilities included in the compilation passed along 100 percent of diversification benefits to industrial load. Others have retained a portion for their remaining classes.
Fourth, the results of the compilation suggest that funding for public purposes such as conservation, renewables, or low-income support is jeopardized under market-based price programs. Only one utility of the 10 we interviewed has made a commitment to funding public-purpose budgets via an access fee that applies to customers with market-based rates. Nearly half of the utilities fund no public purposes at all through access fees, and five continue funding at historic levels. [Note 3] This implies that funding levels will either fall significantly short of the amount needed to support cost-effective programs identified in the Draft Northwest Power Plan, or remaining classes will pick up a disproportionate burden.
Fifth, and finally, the vast disparity among access fees charged by utilities is
potentially alarming. The disparity is due largely, but not exclusively, to the types of
services and costs included in the access fee. To the extent that some of these costs are
fixed, and are not recovered by one class of customers, the disparity between industrial
rates and other class rates will increase. When the disparity is wider for some utilities
than for others, there is a potential for instability and customer dissatisfaction. 
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Note 1. These estimates are based on reported 1994 load for these two utilities. The actual eligible load may vary.
Note 2. For the purposes of this chart, one utility was considered two distinct programs. The first, available only to large industrial classes, charges only a wire and facilities charge. The other, available to all other classes, uses a "top down" approach.
Note 3. The total here is eleven because one utility treats residential and commercial customers differently from industrial customers and therefore was counted as two programs in this tally.
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The print version of the 1997 Biennial Energy Report is available free of charge. To order, contact Julie Palakovich at (360) 956-2098, or send e-mail to wepg@ep.cted.wa.gov.