After Congress enacted the Clean Air Act Amendments of 1990, the electric utility industry focused considerable attention on what seemed the key provisions of the acid rain program: e.g., emission allowance trading. In contrast, the highly technical, seemingly innocuous continuous emission monitoring (CEM) provision received scant attention (em only a few engineers took notice. We now know that emission trading and other supposed key provisions had only a modest impact on utilities. CEM, however, demanded a surprisingly large effort from utilities, involving considerable cost and compliance risk plus required reporting of sensitive data.
Now comes the Federal Energy Regulatory Commission (FERC) with its massive "Giga-NOPR" for electric utility competition. Issued March 29, 1995, the Giga-NOPR has caused quite a stir (em and rightly so. The FERC proposes that utilities make their wholesale transmission facilities as convenient for outside parties (including competitors) to use as they are for the utilities themselves. Effectively, a utility must either spin off its transmission/operations departments into an unaffiliated entity or, at least, substantially isolate these departments.
The FERC also tentatively ruled in favor of utilities with uneconomic generating assets. Customers terminating wholesale service (thereby stranding some utility assets) would be forced to pay "exit fees." Yet, these exit fees would be limited by the number of years the utility had a "reasonable expectation" of retaining those customers. The fees would also be limited by the utility's potential to mitigate stranded assets. Another noteworthy proposal in the Giga-NOPR attempts to define what lies within the FERC's jurisdiction and what falls to the state public utility commissions (PUCs). Many are wondering what the PUCs will do now that the FERC has set up its own model for the transition to competition.
Oh yes, there is also the little-noticed Request for Comments on Real-time Information Networks, or RINs. Only 19 pages, this FERC proposal pales in comparison to the lengthy NOPRs on transmission access and stranded costs. The RINs document is quickly put aside by many because it doesn't address the major issues of the transition to competition. Instead, it presents a rather technical discussion of what transmission data must soon be reported, how frequently, and in what computer format. However, the electric utility industry must not make the CEM mistake a second time. Just because the RINs idea seems technical and less exciting doesn't mean it won't prove to be one of the FERC's most important proposals.
What Are RINs?
The FERC proposes that all utilities with transmission facilities devise a RIN to provide any outside party as much real-time information on transmission and operations as the owner utilities have and is necessary for convenient use of the facilities for wholesale power trades. Thus, in theory, a RIN might disclose a large amount of the information now collected and displayed in utility system control centers.
The Request for Comments lists seven categories of data to include in RINs:
1) Availability of firm and nonfirm transmission and ancillary services and associated prices.
2) Projected hourly transfer capacities with connected utility transmission systems.
3) Hourly firm and nonfirm power scheduled for connections with other utility transmission systems.
4) Ongoing or anticipated transmission and plant outages that impact transmission availability.
5) Up-to-date load-flow modeling.
6) Transaction-specific information on all utility and nonutility requests for transmission services (to help identify any discrimination in favor of the owner utility).
7) Transmission capacity available for resale as well as inquiries from prospective buyers.
Significant Costs
It is impossible to project at this point what RINs will cost utilities to develop, implement, and maintain. However, RINs will be expensive because of the magnitude of the data they must broadcast, the frequency of updating data, and the required two-way connectivity (between the transmission/ operations departments and potential transmission users). There is also the expense involved in creating the necessary other members of the RINs family that the FERC fails to mention.
Utilities will have to develop, implement, and maintain "RIN-feeders" (em software to convert data from their system control center computers to their RINs. Since system control center data formats vary considerably from one utility to another, RIN-feeder development will be costly. Every utility and nonutility transmission user will also need a "RIN-reader" to connect to all the RINs in a region, correlate a massive amount of real-time data, and support wholesale trade decisionmaking. In addition, utilities will need to develop software to price and account for real-time transmission and ancillary services. Such ancillary services (reactive power/ voltage control, loss compensation, scheduling/dispatching, load following, system protection, and energy imbalance) have rarely been sold commercially. The necessary software, therefore, doesn't yet exist.
Was There a Better Way?
The FERC decided against forcing utilities to spin off their transmission/operations departments into unaffiliated entities. It proposes only that utilities substantially isolate these departments. Enforcing compliance would not be cost-effective, however, which is where RINs come in.
RINs function much like the electronic bulletin boards the FERC requires for interstate gas pipeline companies. Electronic connection to a RIN provides a utility's wholesale power traders and outside parties with the same transmission availability and cost information, at the same time. This requirement renders a FERC enforcement program unnecessary (except to ensure that RINs comply with FERC standards).
RINs would have been unnecessary had the FERC decided it could and would force utilities to spin off their transmission/operations departments. Independent coordination companies would have the requisite incentives to treat all their customers (that is, users of transmission facilities and ancillary services) equally well (em without statutory "discrimination." Customers would not need detailed real-time information. Customers would request service, and the coordination company would either figure out how to meet the demand (at an appropriate price) or decline with regret.
Ironically, if an electric utility were to spin off transmission and operations, it would appear that the FERC should not require the resulting coordination company to develop and maintain a RIN. This possibility would give utilities a strong incentive to select the spin-off option.
Vertical Disintegration
Assuming the FERC's final order follows its Giga-NOPR, utility transmission and operations may appear unrecognizable in a couple of years. Today's operators of utility transmission facilities and system control centers will find themselves in spun-off coordination companies (or isolated business units), where they may be joined by the transmission planning department as well. They will price their services (for asset use and labor), invoice customers, and maintain accounts like an independent business (em which is what they will be. They will display no special loyalty or connection to their former employer utility, just as today's Baby Bells enjoy no special relationship with AT&T.
Utilities will be left with their generating plants, plant operations, title to the transmission facilities (with limited property rights), distribution facilities and operations, and the business of wholesale and retail marketing. The disintegration of the vertically integrated electric utility will have begun. t
Steven A. Mitnick is a vice president of Hagler Bailly, based in Arlington, VA. He leads the firm's electric utility consulting practice in North America.
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