You asked for a description of (1) the default provisions of PA 98-28 and the last version of sHB 5428 of the 2002 regular session, (2) major differences in the New England and California wholesale markets in the wake of electric industry restructuring, including rules governing their respective independent system operators (ISOs), and (3) locational pricing and uplift.

SUMMARY

PA 98-28 requires electric utilities to provide default service, starting January 1, 2004, for customers who are not served by a competitive supplier. (A similar requirement, called standard offer service, applies before this date. ) sHB 5428 would have established separate pricing requirements for default service for (1) low-income and other residential customers who are protected from having their power shut during the winter (hardship customers), (2) other small customers, and (3) large customers (those with a demand meter and demand over 350 kilowatts). It would have required the utilities to procure power for the first two classes in a way that mitigated price volatility.

While there are significant similarities in the restructuring legislation passed in the New England states and in California, there were fundamental differences in the wholesale markets in the late 1990s. California was facing rapid growth in electric demand while supply was growing far more slowly. The California Public Utilities Commission, unlike its New England counterparts, initially barred utilities from entering into long-term contracts, which placed additional pressure on the volatile spot market in the state. Unlike ISO-New England, the California ISO did not require generators to bid in their supply on this market, which enhanced their market power.

Parts of New England, including southwestern Connecticut, are subject to transmission constraints. As a result, ISO-New England has to run less efficient plants within these areas rather than importing less expensive power from other areas. Historically, the resulting uplift costs (the difference between the price paid to the plant owners in the affected area and the winning bid submitted in the regional price-setting system) were spread across New England. Under recently adopted rules, the costs of congestion in Connecticut will instead be borne by Connecticut ratepayers. ISO-New England anticipates that this will encourage energy conservation as well as the development of new power plants and transmission lines in congested areas. ISO-New England anticipates that rule change and the growing congestion in southwestern Connecticut will result in uplift costs increasing substantially in the next few years.

DEFAULT PROVISIONS

PA 98-28

PA 98-28 requires the state's two electric utilities to provide default service for any customer who does not or cannot arrange for or maintain service from a supplier. Each utility must obtain power for default service through a competitive bidding process. A generation affiliate of a utility (e. g. , Select Energy) can provide the power, so long as it is the winning bidder and licensed by the Department of Public Utility Control (DPUC) as a supplier.

Default Service Provisions of sHB 5428

sHB 5428, which was favorably reported by the Energy and Technology Committee but not enacted this session, would have made many changes to PA 98-28, notably with regard to default service. For purposes of this memo, the final version of sHB 5428 refers to LCO 5549 as amended by LCO 5580.

Pricing. Under the bill, low-income and hardship residential customers pay the wholesale market cost of the power procured by the utility, plus its administrative costs. Other small customers pay the

wholesale cost, plus a market development assessment. DPUC can modify the rates for these two classes periodically, but not more than once per quarter. Large customers pay the full cost of providing power on a monthly basis, plus the market development assessment.

For all three classes, the utilities are entitled to recover their actual net costs of procuring the power, so long as they mitigate the costs they incur when a customer leaves default service. For the latter two classes, the market development assessment is the approximate cost of a supplier entering the market and its customer acquisition costs, and the utility's administrative costs, capped at . 2 cents per kwh. The administrative costs include a reasonable management fee for the utility, which is subject to an existing earnings sharing mechanism. The part of the earnings that is allocated to customers under this mechanism must be used to fund capital improvements to enhance reliability. The overall assessment cannot exceed . 95 cents per kilowatt-hour (kwh) for any customer. The assessment for all customers cannot average more than . 8 cents per kwh at any time. The ratio between the assessment for residential and industrial customers is subject to an existing law regarding this ratio for overall rates.

The market development assessments must go into separate accounts at each of the utilities. The first $ 7. 5 million in assessments each year must go to the Clean Energy Fund that Connecticut Innovations, Inc. uses to promote renewable energy technologies. At least two-thirds of the rest must go to reduce stranded costs (DPUC-approved costs, whose continued recovery was jeopardized with the onset of competition in the electric industry), and the remainder to a program that provides incentives to residential customers to choose suppliers.

Procurement. The bill requires the utilities to develop a procurement plan, which is subject to DPUC approval, for default service to small customers. The plan must be designed to mitigate the price volatility of default service. It must provide for the acquisition of a portfolio of fixed term contracts that overlap in time. The portfolio must be designed to produce just, reasonable, and reasonably stable rates, while still reflecting underlying wholesale prices over time. The portfolio must be assembled so as to invite competition, guard against favoritism, and secure a reliable electricity supply. It also must avoid unusual, anomalous, or excessive prices. The portfolio must be assembled through an open, competitive bidding process. If a generation affiliate of the utility submits a bid, it must do so one business day before other bidders.

DPUC, in consultation with the Office of Consumer Counsel, must retain a consultant with expertise in energy procurement. The consultant must oversee the utilities' procurement process. The utility and the consultant must review the bids and make a joint recommendation to DPUC on the preferred bidders. DPUC has five days from the submission of the recommendation to reject the bids and rebid the service.

WHOLESALE MARKETS AND RULES

Wholesale markets and the rules governing them differed substantially in California and New England in the years after restructuring legislation was introduced in both areas. Due to economic and population growth, electric demand in California grew substantially in the late 1990s (12% between 1996 and 1999), while demand growth in New England was modest. Conversely, new power plants were constructed at a faster pace in New England than California. As a result, restructuring took place in a tight California wholesale market, while New England generally had a substantial reserve margin. As a result, wholesalers were able to exercise market power (charge prices above their costs of production) to a far greater extent in California than New England. California governor Grey Davis, among others, has also argued that some wholesalers engaged in illegal marketing practices.

In addition, there were substantial differences in the way that restructuring legislation was implemented. The California Public Utilities Commission initially precluded utilities from entering into long term contracts to serve those customers who had not chosen a competitive supplier. As a result, approximately 90% of the power sold in California was purchased on the spot market, which is subject to significant price volatility. In contrast, 80% of the power sold in New England resulted from bilateral contracts, which reduced customers' exposure to price volatility. For example, in Connecticut, utilities purchased power for their standard offer customers under fixed price contracts that run until December 31, 2003.

California also suffered from the fact that caps on wholesale prices in the state, established by the Federal Energy Regulatory Commission (FERC), were lower than those that applied in neighboring states. This encouraged California wholesalers to sell their power out of state. In some cases, the wholesalers were able to sell the exported power back to California, under emergency provisions, at prices that exceeded the caps. In contrast, the caps in New England were similar to those that applied in adjoining regions, which discouraged such practices.

Additionally, ISO-New England has a rule that requires generators to bid in their power in the wholesale market, although it does not regulate the prices of the bids. The California ISO did not have a similar rule, which allowed generators to withhold their power in order to maximize their revenues. Finally, while both ISO-New England and the California ISO were new organizations, ISO-New England was able to benefit from the experience of the New England Power Pool, which had operated the regional power grid for more than 30 years.

OLR memo 2001-R-0081 presents additional information regarding the relevance of the California restructuring experience to Connecticut.

LOCATIONAL PRICING AND UPLIFT

ISO-New England is responsible for dispatching power plants within New England, i. e. , determining which plants run at any given time. It does this on a least cost basis, based on bids submitted on the previous day. The bidding process works on a regional basis since power from Connecticut plants routinely flows to other states, and vice versa. However, parts of New England, including southwest Connecticut, are subject to transmission constraints that limit the ability to ship in electricity. A December 2001 study by FERC, discussed in OLR report 2002-R-0017, identifies southwest Connecticut as one of the 16 most constrained areas in the continental United States. This constraint exacerbates the shortage of supply relative to demand in southwestern Connecticut.

As a result of this constraint and a similar situation in the Boston area, ISO-New England must dispatch plants that are located in such areas during periods of peak demand, even though they are more expensive than the plants that submitted the winning bid. The owners of these plants are paid for their costs plus a margin. Historically, the resulting uplift cost was spread among all New England consumers. In recent years, the share of uplift costs borne by Connecticut consumers ranged from $ 30 to $ 150 million per year, depending on demand and the availability of supply.

ISO-New England is changing its pricing rules to implement the FERC-approved standard market design. Under these rules, which will go into effect at the end of this year, wholesale electric prices will be set separately for eight zones in New England, based on the supply and demand in each zone. The price of energy will reflect, in addition to the underlying cost of the energy as reflected in the bids, the added cost of congestion and losses caused by taking power off the grid in a particular location. The rationale for this change is that it will provide better price signals, encouraging the development of new plants and transmission lines in congested areas and encouraging consumers in these areas to conserve electricity.

Under the new rules, Connecticut will be one of the eight zones. As a result of the rule change and increasing congestion, ISO-New England anticipates that the annual uplift costs borne by Connecticut consumers will rise to $ 150 to $ 300 million during the period 2003 to 2006. ISO-New England's Website (http: //www. iso-ne. com) has a page that provides additional information on locational pricing.

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