Motivation

The current debate regarding unbundling of electricity costs and setting competitive transition costs and market indexes going on in several states will have a significant impact on electric power costs for electric power consumers in those states. But the economic consequences will be much broader; they will affect much more than just electricity costs. Yet few state citizens are aware of, let alone participate in, the debates. Not that most of us could figure it out; even the experts can’t.

The debate is about the complicated and difficult to understand process by which electric power costs are "unbundled," or separated between delivery costs and generation costs when markets are deregulated. Delivery costs are those charged by local utilities for use of the transformers and wires that get electricity from power plants to business or home. The state public utility commissions fully regulate delivery costs, even under deregulation. Supply costs are charged by power suppliers for building and operating power plants to generate the electricity (in some cases, supply costs include some fees paid for use of high voltage transmissions lines). In a deregulated market, those costs should be driven by competition. But, in most electricity markets in the US that are transitioning to deregulation, they are still driven largely by decisions made among legislators and regulators with substantial input from local utilities and other interested parties. Competition among suppliers exists; but it is still highly regulated.

Overwhelmingly, the most significant factor affecting the development of a robust competitive market for all customers is the manner in which total electric costs are "unbundled." This is supported by research^[1], and experience^[2], and analysis of numerous competitive electric markets in the US. Of course, in the long term, supply and demand will be the factors determining supply costs. But if unbundling initially results in unrealistically low supply costs, competition may never develop and competitive supply costs may never be low enough to create competition. And, if market supply costs ever manage to decrease sufficiently, consumers will still end up paying higher total costs than appropriate due to unrealistically high delivery costs.

And the debate often misses the most significant value of effective deregulation and robust competitive markets. Everyone focuses on residential customers’ costs, which at best might be reduced by an average of a hundred dollars per year—a small part of the average residents total budget. What they miss are the substantial benefits to all Illinois citizens of lowering energy costs for the businesses in the state. Those benefits, as shown in a study of deregulation in Pennsylvania, include improved productivity, increased competitiveness of state businesses and employers, increased business development in the state, greater business retention, improved job creation, and reduced costs of goods and services. According to the study, the estimated benefits of effective deregulation in Pennsylvania include more than $4 billion in savings and 40,000 new jobs^[3].

Most markets in the US are not yet very robust. Typically, there are only 2-4 competitive suppliers in most territories; Texas is the exception with 6-7. The most active state was Pennsylvania in the early days (1999 and early 2000) of deregulation there. Now it is Texas. Yet significant activity and switching to competitive suppliers is occurring in numerous states, albeit somewhat sporadically.

The first figure shows the official legislative status of deregulation in the US^[4]. The actuality of competitive activity, shown in the second figure, is quite different but significant^[5].

Figure Deregulated Markets (EIA/DOE)

Figure Active Markets (EnergyWindow Focus!)

Thousands of businesses have saved millions of dollars in deregulated energy markets, including California. Even in California, 15% of the business customers, representing 30% of the load, switched suppliers in order to save money in the first 1-2 year following deregulation. They also isolated themselves, until the California assembly and public utility commission "reregulated" the industry, from the risk of high and volatile power costs. More than 30% of the business customers, representing over 40% of the total load, switched in Pennsylvania in the first year following deregulation. The companies with energy consuming operations in that state, as well as the state’s citizens, have realized billions of dollars of benefits from the successful deregulation experiment there, according to an econometric study commissioned by the state department of revenue.

Most people are aware of the disastrous results of California’s approach to deregulation. Pennsylvania has been a different story. "Pennsylvania is the national model for competition done right. Customers have saved over $4 billion in electricity costs. More than 40,000 jobs are expected to be created by Electric Choice by 2005; nearly 120,000 Pennsylvanians have chosen green power, more than any other state. Every Pennsylvanian has the option to buy renewable power. We are the East Coast leader for wind power. Up to 1 million Pennsylvanians have cumulatively shopped for power. Despite the turmoil of the last year, more than 550,000 people are currently shopping [for electricity]. Next month, nearly 500,000 residential customers in the Pittsburgh Region will see their rates go down by 16 percent -- thanks to competition."^[6]

So effective deregulation can be achieved and competitive markets developed. The benefits are significant; they accrue most via savings of business; but they benefit all citizens of the state. But the development of competitive markets and the resulting benefits are substantially affected by the approach to deregulation. The most important factor is the manner in which costs are unbundled.

The following subsections 1) show differences in electricity cost unbundling, 2) provide market activity as indicated by switching rates, and 3) suggest relationships between the two in three state that deregulated electric markets early.

Based on information on public utility commission web pages in late 1999 and 2000, Laurenc Kirchner,^[7] a graduate student at the University of Colorado, estimated the fraction of total energy costs that supply (transmission and generation in this case) represented in three states, California, New Jersey, and Pennsylvania, at the time of unbundling and deregulation. The supply fraction of total energy costs is difficult to estimate precisely because the fraction varies as a function of time, service territory, service classification, load characteristics, and other factors. Nevertheless, the fractions below are an indication of the relative fraction of total cost represented by supply. The information in the first table is from Kirchner’s work.

The switching rates shown in the following tables are drawn from Kirchner’s work and data provided by Tom Michelson,^[9] of the consulting firm Exelergy.

Notes: NJ commercial and industrial data are not separated. Rates vary widely within a state among service territories. For example, total switching rates among PA territories for June 2001 vary from 0.2 to 17%; for New Jersey from 0.5 to 6.3%. California commercial data are for small and medium class customers.

Although it is a bit dangerous to try to see relationships with small numbers of data points, competitive market activity appears to be dependent on the fraction of total electricity costs represented by unbundled supply costs. The figure was developed for commercial customers; the relationships and differences, particularly between California and New Jersey are less apparent for other classes of customers. The differences between Pennsylvania and the other two states are large.

The higher market activity in Pennsylvania, which had higher supply cost fractions, seems somewhat intuitive since lower supply costs make it more difficult for competitive suppliers to enter the market and compete. Kirchner also observed that lower supply fractions decrease the motivation of consumers to pursue lower supply costs since they are less able to affect overall costs (i.e., decreasing supply cost by 10% when supply costs only represent 20% of total costs means total cost only decrease 2%, small benefit, particularly for residential customers whose annual bills might only average $600-900).

One might expect the relationship between supply costs and market activity to be non-linear. That is, activity might increase to significant levels only when default service rates reach some threshold value and competitive supplier offerings can be lower than comparison costs (default, standard, price to beat, regulated tariffs).

The results of unrealistically low default supply service costs can be even more catastrophic for the local utility that must supply service at these rates. PG&E declared bankruptcy and SCE almost had to in California because they were required to supply default service at rates substantively below the market rates at which they had to acquire power. Interestingly, San Diego Gas & Electric escaped the fate of the other two large investor-owned utilities in California only because they were able to pay off their stranded costs quickly, move out of a transition market (with CTCs) to a fully competitive market, and begin charging competitive supply costs to their customers, who suffered less than customers of the other two major California investor-owned utilities.

While quantitative data are not provided for Massachusetts, the state offers another example of the impact of bundling. Legislators passed laws requiring deregulation in 1998. But when costs where unbundled, the standard offer tariff rate was set lower than wholesale costs. Two results were minimal market activity and distress for local utilities, which eventually were required to provide default service at a rate lower than their costs. Two actions by legislators and the Massachusetts Department of Transportation and Energy (DTE) mitigated the impact of this in the longer term. They allowed the local utilities to go out for competitive bids for suppliers to provide default service (at higher rates but supported by a competitive process) for those customers who leave regulated service and return or who are new customers. Second, they began periodically increasing standard offer (for those who remained on regulated service) service rates. Finally, in late 2001 and early 2002, rates have increased to the point where competition is beginning to develop.

Peculiarities of how costs are unbundled by rate class yield dramatically different results, not only from state to state, but even from services territory to service territory within a state and among different customer service classifications. In Maryland, the approach proposed by Baltimore Gas & Electric and accepted by the Public Service Commission (PSC) has been the subject of significant legal opposition. And, as the March 2002 PSC report shows, it has resulted in very little competitive activity in the form of customers switching to competitive suppliers. On the other hand, the approach taken in Potomac Electric Power territory has resulted in 20% of business customers, 65% as measured by load in kilowatts, switching; substantial results for just two years of competition. Presumably, most other factors would tend to be similar for these two Maryland distribution companies with contiguous service territories.

Comparing commercial and industrial rates between the two utilities’ tariffs is difficult and dependent on service class, load, demand, and load profiles. But comparison of residential rates is relatively straightforward. Pepco’s residential supply (generation plus transmission) costs are 66% of the total. BGE’s residential supply rate is 58%. This situation supports the argument that the approach to unbundling can be a very, if not the most, significant factor affecting development of competitive electricity markets. But, it also suggests, as do the data for CA, PA, and NJ, that market activity remains low until a threshold default service rate is reached and that, thereafter, small differences in unbundling fraction can result in significant activity increases.

In December 1997, HB 362, "The Electric Service Customer Choice and Rate Relief Act of 1997," was enacted in Illinois. It called for all electricity consumers—businesses and residents—to be able to chooser electric power suppliers. In July 1999, SB 24 was enacted to amend the original restructuring law. The amendment moved up the transition to customer choice. As a result of the laws, by May of this year, all customers, business and residential were able to choose electricity suppliers, at least according to the law. Delivery continues to be provided by the local utility company and to be fully regulated by the ICC^[11].

The law provided for three options for electricity customers. 1) They could remain on the (default) regulated tariff bundled rate, which was set to afford residential customers some savings. 2) They could obtain electricity supply from an alternative retail electric supplier (ARES). Or 3) they could elect to be supplied by either their local distribution company or an ARES at a rate set according to a market index (the so-called Power Purchase Option, PPO). Options 1 and 3 were provided as means of affording customers some benefits of the development of competitive markets but also protection from rising market prices should rates rise.

Originally, a neutral party (the neutral fact finder, NFF, an accounting firm selected by the ICC) set the PPO market index—the first of three attempts at establishing an effective approach. But in April 2001, after hearing from interested parties, the ICC allowed the local distribution companies to set the index according to a complicated process based on historical spot and forward prices—the second attempt. Recently, the same parties again debated the process after unusually low market conditions during the 20-day period in February and March used to set the index resulted in the formula producing results that will surely shutdown Illinois’s nascent competitive markets. Unfortunately, the formula was allowed to stand—the third attempt.

The laws and subsequent ICC rulings have tied the method of setting the PPO market index to the way in which delivery costs are determined. The formula is pretty simple:

where:

Viewed a bit differently the formula has some interesting implications:

The formula, along with a complicated calculation of wholesale market prices during a 20-day period in February and March, is used to set the CTC and M. Regardless which option customers choose (regulated tariff, PPO, or competitive supplier), they pay the local utility the sum of (DS + CTC + M). The bundled rate, BR, was fixed, for ComEd for example, in 1996. Therefore, if market prices go down due to increased competition (at the wholesale level), the CTC and how much customers pay for delivery services go up. And the lower MV makes it more difficult for competitive suppliers at the retail level to beat the PPO. The argument for the CTC has been that some of the Illinois utilities invested in generating plants, which would not have been deemed good economic investments, had markets been deregulated. But from the consumers point of view this argument doesn’t seem logical at all.

From the market’s perspective, it matters little whether these charges are called competitive transition charges (CTCs) or what the reasons for them are; the net effect is to increase (regulated) distribution/delivery costs and, if the basis for unbundling is constant total costs, to lower default supply service costs. Obviously, the impact will be even greater if, as in the case of many states, the total overall costs negotiated between the public utility commission and local utilities are reduced as a part of deregulating.

During the debate in early 2001, the ICC "…Staff, Ameren, ComEd, and IP, believe[d] the record indicates the likelihood that the MVI tariffs proposed by Ameren, ComEd, and IP will increase, relative to the NFF, the MVs used in the computation of CTCs. Since an increase in MVs causes a decrease in CTCs, these parties contend that the proposed indices can be viewed as a net improvement over the NFF-based default mechanism from the perspective of customers that want to seek out unbundled alternatives to traditional utility service."^[13] In fact, the MVs decreased dramatically when calculated based on market prices in February and March of 2002, so much so that the CTC increased by factors of 4 to 14. The effect will be essentially to shutdown the developing competitive market for electricity in Illinois.

The following subsections provide some insights about unbundled costs, possible bases for establishing regulated delivery costs, and possible competitive approaches for establishing default service rates in Illinois. The issue of stranded costs is also reviewed.

Unbundled Costs

For comparison, the fraction of costs for two representative ComEd accounts in selected service classes are shown below. The graphs show the fraction of costs for delivery and supply for the previous (2000) and most recently proposed (2002) PPO rates. The chart percentages are not materially different if graphed for ComEd’s fully regulated Rate 6. Delivery costs include distribution costs, transmission service charges, and the CTC. Supply costs include only the respective Period A market value.

The first observation from the charts is that the most recently proposed rates dramatically change the relative portion of total costs (and the absolute value) that delivery costs represent. The cost to ComEd of providing those delivery services has not changed materially. The impact on business, and residential, electricity consumers that have committed to alternative supplier service agreements is a complete elimination, or in some cases reversal, of expected savings^[14]. The resulting inability to make reasonable predictions of regulated delivery and regulated (PPO) supply cost alternatives is a major deterrent to participation in competitive markets by both buyers and suppliers.

The difference between the 2000 and 2002 rates represents an increase in revenue of over $500 million per year to ComEd. This additional cash flow will result irrespective of whether ComEd provides any different services to consumers.

Regulated Delivery Costs

Presumably, delivery costs, which remain regulated, should be set using a process similar to that used by the ICC in setting total costs in the past, before deregulation. Two bases used for setting regulated rates are asset values and operating expenses. ComEd asset and operating expense fractions by service component are shown in the figures below^[15].

Operating expenses for supply include power production and power purchase costs; delivery expenses include distribution and transmission costs. Supply assets include generation and transmission; delivery includes transmission and distribution.

A comparison of either the asset or expense charts with any of the unbundled costs charts reveals a wide disparity between the cost basis and the rates charged for regulated delivery services. In the first place, no logic suggests that the determination of regulated delivery costs and semi-unregulated supply costs should be linked. Delivery service rates should be set using the customary approach for setting any regulated utility rates; and those rates should, as customary, be set for more than one year of several months in advance in order to provide reasonable predictability for market participants.

Supply Costs

Presumably, supply costs should be set by a competitive, market based process. In a fully competitive deregulated market, supply and demand and buyer and supplier interaction in free markets would determine supply service charges. In the current transition period, the PPO service charge is set using the methodology discussed previously. That current method of setting the regulated market (PPO) rate relies on the use of historical spot and forward prices during a very short 20-day period in February and March (for Period A charges) is extremely artificial and arbitrary. It doesn’t rely to any degree on the substantial ability of competitive suppliers to project forward market prices.

The challenge of setting forward prices using historical costs and some formulaic approach is impossible. One more logical approach, which has been taken in Maine and to some degree in Massachusetts, is to use a competitive bidding process to select the supplier of default service and to set the default service rate. This approach would rely on the expertise and knowledge of suppliers to project costs and on competition. The local utility company, e.g., ComEd, should be allowed to participate in the competition, provided regulators are convinced of the complete separation of its unregulated supply subsidiary. The rates should be set for more than one year in advance. If legislators and regulators must, during the transition period, they can set an overall rate cap based on prior regulated rates—with some additional so-called "head room"— to shield consumers from an immediate large rate increase shock. But, if the goal and plan is for ultimate full deregulation and a competitive market, setting a low cap prevents the development of a robust competitive market and simply defers the rate shock, inevitable if suppliers are not motivated to develop supply alternatives (generation and transmission assets and robust wholesale and retail markets).

Stranded Asset Costs

Of course, incumbent utilities argue during the negotiation leading up to deregulation that they need to be "made whole" and allowed to recoup costs incurred due to investments in generating assets made prior to competition because they are somehow uneconomic now whereas they weren’t then. The largest of these investments was in nuclear power plants, which during the 1980s and 1990s were in fact very expensive and unreliable. But all that has changed:

NUCLEAR PERFORMANCE BOOSTS EXELON'S 2000 EARNINGS

Most new generation facilities being developed use natural gas or, in a small number of cases, renewable resources. These are more expensive generating alternatives than either coal or nuclear plants. And nuclear plant total production costs have now slipped below fossil fuel costs.

This argument seems untenable. And, regardless, based on the evidence and experience, a competitive market will not develop if delivery costs are set unrealistically high and transition period regulated supply alternatives (regulated rates or the PPO) are set unrealistically low.

The Virginia restructuring legislation also provided for the SCC to establish rate caps both for bundled total rates and competitive generation service.

Very little competition occurred during Virginia’s pilot deregulation program; the "prices to compare" were too low to allow competitive suppliers to enter; as a consequence limited experience and insights were gained. The most recent prices to compare are substantially lower, particularly for Dominion Virginia Power. As a consequence, no competitive suppliers, with the exception possibly of one offering renewable power service to residents, are active or considering entering the Virginia market. The outcome is negligible in terms of benefit to consumers or satisfying the legislatures intention of deregulating electricity markets. In addition, consumers will suffer significant rate shock when the transition period ends and markets become more truly competitive in 2004.

The following subsections provide some insights about unbundled costs, possible bases for establishing regulated delivery costs, and possible competitive approaches for establishing default service rates in Virginia. The issue of stranded costs is also reviewed.

Unbundled Costs

For comparison, the fraction of costs for representative Dominion Virginia Power accounts in selected service classes is shown below. The graphs show the fraction of costs for delivery and supply for the "prices to compare" set in January 2002.^[20] Delivery costs include distribution costs and the CTC. Supply costs include generation and transmission costs.

Regulated Delivery Costs

Presumably, delivery costs, which remain regulated, should be set using a process similar to that used by the SCC in setting total costs in the past, before deregulation. Two bases used for setting regulated rates are asset values and operating expenses. Dominion Virginia Power asset and operating expense fractions by service component are shown in the figures below.^[21]

A comparison of either the asset or expense charts with any of the unbundled costs charts reveals a wide disparity between the cost basis and the rates charged for regulated delivery services. Delivery service rates should be set using the customary approach for setting any regulated utility rates driven by delivery asset value and operating expenses; and those rates should, as customary, be set for more than one year in advance in order to provide reasonable predictability for market participants.

Supply Costs

Presumably, supply costs should be set by a competitive, market based process. In a fully competitive deregulated market, supply and demand and buyer and supplier interaction in free markets would determine supply service charges. In the current transition period, the price to beat is set using a negotiation approach as discussed previously. That approach is artificial and arbitrary. It doesn’t rely to any degree on the substantial ability of suppliers to project forward market prices.

The challenge of setting forward prices using historical costs and some formulaic approach is large. Again, the more logical approach, taken in Maine and to some degree in Massachusetts, is to use a competitive bidding process to select the supplier of default service and to set the default service rate. This approach would rely on the expertise and knowledge of suppliers to project costs and on competition. The local utility company, e.g., Dominion Resources, should be allowed to participate in the competition, provided regulators are convinced of the complete independence and separation of its unregulated supply subsidiary. The rates should be set for more than one year in advance. If legislators and regulators must, during the transition period, they can set an overall rate cap based on prior regulated rates—with some additional so-called "head room" to shield consumers from an immediate large rate increase shock. But, if the goal and plan is for ultimate full deregulation and a competitive market, setting a low cap prevents the development of a robust competitive market and simply defers the rate shock, inevitable if suppliers are not motivated to develop supply alternatives (generation and transmission assets and robust wholesale and retail markets). Nothing in Virginia’s restructuring laws appears to prohibit this approach; indeed Section 56-585 of the Virginia Code explicitly refers to such a process.

Stranded Asset Costs

Of course, incumbent utilities argue during the negotiation leading up to deregulation that they need to be "made whole" and allowed to recoup costs incurred due to investments in generating assets made prior to competition because they are somehow uneconomic now whereas they weren’t then. The largest of these investments in nuclear power plants, which during the 1980s and 1990s were in fact very expensive and unreliable. But all that has changed:

NORTH ANNA LEADS, MOST U.S. UNITS GENERATE FOR LESS THAN 3 CENTS/KWH

Surry has generally performed within a few mills/kwh of North Anna and within the top 10 US nuclear plants.

Most new generation facilities being developed use natural gas or, in a small number of cases, renewable resources. These are more expensive generating alternatives than coal or nuclear plants. And nuclear plant total production costs have now slipped below fossil fuel costs.

This argument for the CTC seems untenable in Virginia, too. And, regardless, based on the evidence and experience, a competitive market will not develop if delivery costs are set unrealistically high and transition period regulated supply alternatives (the price to beat in Virginia) are set unrealistically low.

Based on the research, experience, and analysis, which the preceding discussion summarizes, in numerous competitive electricity markets, the following conclusions and recommendations are offered regarding the approach to deregulation and competitive market development in Illinois:

• Reduced business energy costs resulting from the development of robust competitive markets provide substantial benefit to all state constituents in the form of enhanced productivity, increased job creation and retention, and lower costs of services and products.

• The way in which electric supply costs are unbundled is the most important factor affecting the development of robust competitive markets.

• The approach to unbundling being taken in Illinois will shut down the nascent competitive market activity that has been developing and prevent the development of a competitive electric supply market in Illinois. The approach being taken in Virginia will shut down the very modest activity experienced in the pilot program and prevent the development of a competitive electric supply market in Virginia. It will ultimately result in a more significant shock to state electricity consumers, if and when markets are fully deregulated.

• Delivery service costs should be set using a conventional regulatory process driven by delivery asset values and expenses, during and following any transition period (if delivery services are to remain regulated).

• Competitive transition charges should be eliminated or rapidly phased out. The method of setting them should not be tied to default or market indexed prices. Arguments about stranded assets, which were put forward initially a number of years ago, seem untenable now.

• Competitive market processes, including, possibly, competitive bidding, should be used to set default supply service cost, during any transition period.

• State public utility commissions should reconsider allowing state utilities to separate legally their generation assets into separate subsidiaries in order to support competitive processes for determining default service providers and rates and to allow those subsidiaries to participate fairly in those competitive processes.

• Regulated delivery and regulated supply alternative rates should be relatively predictable and set as far in advance as possible (preferably multiple years) in order to enable market participants—buyers and suppliers—to make rational decisions and to eliminate a significant barrier to participation in the market.

Endnotes

[1] This discussion is based, in part, on graduate thesis research conducted at the University of Colorado by Laurenc Kirchner, “Study of Market Activity in the Electrical Energy Market in the U. S.,” April 2000, submitted for the degree of Master of Engineering Management at the University of Colorado, and supervised by the author.
[2] The author is the chief executive of EnergyWindow, a company that assists energy consumers in choosing suppliers in competitive energy markets by means of various services and products, including an online system for requesting and receiving bids. EnergyWindow has assisted clients with supply management and procurement in almost every deregulated electricity market in the US: CA, DC, DE, IL, MA, MI, MD, NJ, NY, OH, PA, and VA.
[3] “Pennsylvania is the national model for competition done right. Customers have saved over $4 billion in electricity costs. More than 40,000 jobs are expected to be created by Electric Choice by 2005; nearly 120,000 Pennsylvanians have chosen green power, more than any other state. Every Pennsylvanian has the option to buy renewable power. We are the East Coast leader for wind power. Up to 1 million Pennsylvanians have cumulatively shopped for power. Despite the turmoil of the last year, more than 550,000 people are currently shopping [for electricity]. Next month, nearly 500,000 residential customers in the Pittsburgh Region will see their rates go down by 16 percent -- thanks to competition.” Pennsylvania PUC Chairman Glen Thomas, “Lesson Learned from the Enron Experience: How Will It Affect Regulation?” NARUC Winter Meeting, Feb. 12, 2002; http://puc.paonline.com/press_releases/press_releases.asp).
[4] Source: Department of Energy Energy Information Administration; see http://www.eia.doe.gov/cneaf/electricity/chg_str/restructure.pdf.
[5] Source: The EnergyWindow Focus! competitive energy market information product.
[6] Source cited previously: Pennsylvania PUC Chairman Glen Thomas, “Lesson Learned from the Enron Experience: How Will It Affect Regulation?” NARUC Winter Meeting, Feb. 12, 2002; http://puc.paonline.com/press_releases/press_releases.asp.
[7] Kirchner’s thesis cited previously.
[8] These fractions were drawn from tables on public service commission web sites and were presumably intended to be representative. They are probably most representative of residential rates.
[9] From Tom Michelson of Exelergy, publisher of “Retail Energy Foresight,” in the June 2000, Feb/Mar 2001, or Aug/Sept 2001 issues or via direct communication in Dec 2001.
[10] Source: Electric Choice Monthly Enrollment Report at http://www.psc.state.md.us/psc/.
[11] See http://www.eia.doe.gov/cneaf/electricity/chg_str/restructure.pdf.
[12] See Rate CTC – Customer Transition Charge, filed April 11, 2002 with the Illinois State Commerce Commission, Docket No. 01-0423 Sheet 135-136; some simplifications have been made.
[13] See discussion in ICC Orders 00-0259/00-0395/00-0461 (Cons.) April 11, 2001.
[14] EnergyWindow, the company of which the author is president, has advised and assisted several commercial and industrial that have signed $million agreements in Illinois and now face substantial reduction or reversal of expected savings.
[15] Data from Electrical World, published by McGraw Hill 107th Edition, 1999.
[16] Nucleonics Week, published by McGraw Hill, February 1, 2001, page 2.
[17] See the Virginia SCC news release, “SCC ANNOUNCES AVERAGE "PRICE TO COMPARE" FOR VIRGINIANS INTERESTED IN SHOPPING FOR ELECTRICITY,” dated January 10, 2002, at http://www.state.va.us/scc/news/ptocomp.htm.
[18] Source: Department of Energy Energy Information Administration; see http://www.eia.doe.gov/cneaf/electricity/chg_str/restructure.pdf.
[19] Code of Virginia, § 56-582. Rate caps.
[20] From the Virginia SCC press release cited previously.
[21] From Electrical World, published by McGraw Hill 107th Edition, 1999.
[22] Nucleonics Week, published by McGraw-Hill, July 5, 2001, page 1.