You asked for (1) an analysis of Oregon's electric restructuring law, particularly with regard to the issue of customer choice and (2) a brief summary of the Federal Energy Regulatory Commission's (FERC) actions on standard market design and a discussion of their implications for Connecticut.

SUMMARY

Oregon's electric restructuring law differs from the laws in Connecticut and other states that have adopted deregulation in that it allows only non-residential customers to choose a supplier. At the same time, the Oregon utilities must offer residential and small commercial customers a choice of supply options at rates that are regulated by the Public Utility Commission (PUC). Oregon also allows all customers to buy power from their utilities at rates that vary with price changes in the wholesale market. Many of the law's other provisions are similar to Connecticut's law.

In September 2002, FERC approved an order establishing a standard market design for New England. The order covers many aspects of the design and operation of the regional wholesale electric market. Of particular relevance to Connecticut is a provision that would alter the way that costs arising from congestion on the transmission system are allocated. Currently, congestion costs, regardless of where they occur, are spread among all New England ratepayers. Under the order, the costs would be borne by ratepayers in the particular zone where they occur. (There are currently eight zones in New England, one of which is Connecticut. ) This change is scheduled go into effect in spring 2003.

FERC has also proposed adopting a regulation establishing a nationwide standard market design. While the proposed regulation is similar to the New England order, there are several substantive differences. Additionally, the proposed rule deals with several issues not addressed in the order. These include planning for transmission facilities, the integration of conservation in the wholesale market, and a requirement that utilities and other entities that buy power on the wholesale market ensure that they have adequate resources to meet their projected peak demand.

While the changes contained in FERC's order and its proposed regulation may increase the efficiency of the wholesale electric market, they have the potential of imposing substantial costs on Connecticut ratepayers in the near term. The Independent System Operator-New England (ISO-New England), the non-profit organization that administer the regional wholesale market has forecast that these changes could increase the cost of electricity to Connecticut consumers by $ 125 million or more per year until supply limitations in southwestern Connecticut are resolved. While Connecticut's Department of Public Utility Control (DPUC) has generally supported standard market design, it has asserted that the implementation timetable in the order is too short. DPUC asserts that the order has the potential of creating a "perfect storm" or a "mini California. " It has requested that FERC reconsider or rehear parts of the order and delay the implementation of several of its provisions. DPUC has raised similar concerns with regard to the proposed nationwide regulation.

OREGON'S ELECTRIC RESTRUCTURING LAW

Choice

As described in OLR memo 2002-R-0694, Oregon passed its original deregulation legislation (1999 Or. Laws ch. 865) in 1999 and amended it in 2001. The legislation differs from that passed in Connecticut and other states in that it only allows non-residential customers to choose their supplier. It allows residential and small commercial customers to choose several types of service provided by their incumbent utility and regulated by the Oregon PUC. These customers can choose services in which (1) prices fluctuate with changes in the wholesale energy market or (2) prices reflect significant new renewable resources. The legislation required the PUC to regulate these options to ensure that the rates under each option reflect the utilities' costs and risks. If a customer does not choose one of these options, he continues to be charged fixed rates that reflect the utility's costs of service. The PUC must report to the legislature by January 1, 2003 on whether it believes residential customers should be allowed to choose their supplier.

Non-residential customers have been able to choose their supplier since March 1, 2002. Utilities must also provide a cost-of-service option for these customers. The PUC may waive this requirement for large commercial and industrial customers after July 1, 2003 if it finds that a competitive market exists for them. Specifically, the PUC must find, after public hearing and a comment period, that large customers could:

1. buy adequate and reliable supplies of electricity at prices that are just and reasonable and not unduly volatile, and

2. obtain multiple offers of electricity supply within a reasonable period of time.

The legislation allows the PUC to prohibit or limit small commercial customers who had chosen a supplier from returning to the cost-of-service rate.

Other Provisions

Many of the other provisions in Oregon's law are similar to those in Connecticut's law. These include provisions that:

1. require utilities to unbundle (separate) their generation, transmission, and distribution components;

2. require the PUC to establish a code of conduct, regulating interactions between part of the utility that provides generation services and the rest of the company;

3. allow utilities to seek recovery of their stranded costs which were previously included in rates but whose continued recovery was threatened by the start of competition in the utility industry, with the approved amounts recovered by a separate transition charge on customers' bills;

4. seek to mitigate the exercise of market power by utilities, suppliers, and other market participants; and

5. ban shifting costs among customer classes.

There are several major differences between the two laws. Connecticut effectively required utilities to auction off their generation assets (they would have faced the loss of several billion dollars if they had not done so). Oregon instead authorizes the PUC to establish incentives for the utilities to divest themselves of their generation assets. Unlike Connecticut, Oregon does not allow utilities to securitize their stranded costs, i. e. , issue bonds backed by the transition charge.

While both states impose charges on electric bills to encourage energy conservation and renewable energy and to pay for certain public policies, Oregon's charge only applies to large customers who are able to choose their supplier. In Connecticut, all of the charges apply to all customer classes. Oregon also differs from Connecticut in that it requires that 10% of the charge go to school districts for energy conservation programs. Unlike Connecticut, Oregon's law provides a credit against the charge for large customers that invest in energy conservation or renewable energy at their own facilities. Connecticut's systems benefit charge is used to fund a broader range of public policies and programs than Oregon's public purpose expenditure charge.

Some of the differences in the laws reflect differences in the electricity markets in the two states. Several of the provisions in the Oregon law become effective only upon a finding by the PUC that they would not jeopardize the state's access, under federal law, to inexpensive power from the Bonneville Power Authority, (a federal power authority that serves the Pacific Northwest; there is no comparable body in New England). Oregon's law also contains more extensive provisions regarding municipal utilities and other public power entities, which serve 25% of the state's residents, compared to approximately 4% in Connecticut.

Current Status

The PUC has developed the following options for residential and small commercial customers in addition to traditional service with rates based on the utility's cost of service: time of use, seasonal (for PacifiCorp customers only), 100% renewable, fixed amount renewable (e. g. , 50 kilowatt-hours per month), and fish habitat protection. The PUC developed these options and chose to offer them to small commercial customers after consulting with an advisory group. The group, which was established by the original legislation, included environmental, municipal, business, and senior citizen groups, as well as the state's two major utilities. The 100% renewable option has an added cost of $ 7 to $ 8 per household per month. Under the fixed renewable option, customers can purchase wind power in 100-kilowatt-hour blocks for an additional $ 2. 95 to $ 3. 50 per month. The fish habitat option costs an additional $ 9 to $ 11 per household per month. Approximately 29,000 customers (2% of those eligible) are currently enrolled in these options.

There are currently six suppliers certified and six aggregators registered to serve non-residential customers, with another four supplier applications pending. As August 1, 2002, no customer had chosen a supplier. However, customers representing 9% of the load served by Portland General Electric, the state's largest utility, have chosen to take variable rate service from it. Under this option, the customer's rates vary over time, reflecting changes in the wholesale market. This option was developed by the utilities and approved by the PUC independently of the legislation. Under this option, the customer can choose to have its rates change on a monthly or quarterly basis. The customer cannot return to traditional service for a period of 12 months. Although the state's other large utility (PacifiCorp) also offers this option, very few of its customers have chosen it. Further information on the choices made by Oregon consumers is available on the PUC's Website, http: //www. puc. state. or. us/erestruc/statrpt/2002/0802rpt. pdf.

STANDARD MARKET DESIGN

New England Order

In September 2002, FERC issued an order (100 FERC 61,287 (2002)) regarding standard market design in response to a joint filing made by ISO-New England and the New England Power Pool, which includes utilities and other participants in the regional wholesale market. The order makes several changes in the way that prices are set on the wholesale electric market. In several cases, it requires that costs that are now spread among all New England ratepayers be borne by smaller groups, e. g. , Connecticut ratepayers.

Locational Marginal Pricing. Historically, the wholesale price of electricity, as set by the regional day ahead and spot markets, has been uniform across New England. (Utilities and generators also routinely enter into bilateral contracts outside of these markets. ). However, the market for electricity is tighter in some parts of New England, notably southwestern Connecticut, than in others. According to FERC, the uniform price has not provided an adequate incentive for suppliers to locate new plants in tight markets or customers in these areas to conserve electricity.

FERC's order calls for the wholesale price of electricity to be set for discrete areas in New England, starting in the spring of 2003, using a technique called locational marginal pricing. The price paid for electricity will depend on the transmission node (site on the transmission line) where the generator is located. Generators will submit bids to ISO-New England, and the price will be set by the last unit of supply needed to meet demand in a specific area at a given time. As a result, generators located at nodes where supply is relatively tight will be paid more than those in areas where supply is plentiful.

Initially, the price that utilities and other entities that purchase electricity will pay will be determined by zone, which is larger than a node. Connecticut is one of eight zones in New England, so the wholesale price will initially be uniform across the state. (The wholesale price in Connecticut will be the average of prices paid to generators in the state. ) However, the order requires that ISO-New England move to charging for electricity on nodal basis. ISO-New England anticipates that this provision will be implemented in approximately 18 months.

Other Provisions. Transmission system constraints limit the ability to move electricity into some parts of New England, including southwestern Connecticut. As a result, older, less efficient power plants in these areas must run more often than they would in the absence of the transmission constraints in order to maintain the system's reliability. Historically, ratepayers across New England bore the added costs of running these plants. Under the order, these costs will be borne by customers in the affected zone.

In addition, all New England ratepayers historically have borne the costs of major improvements to the transmission system, under the theory that they reduced the costs of congestion and limited the likelihood of market power. (Market power can exist if there are few suppliers in a particular market or if transmission constraints limit the ability to import power to a specific area. The exercise of market power is not necessarily illegal, but can result in consumers paying higher prices than they would in a more competitive market. ) In the proceedings, the Maine PUC requested FERC to ensure that the costs of improvements no longer be spread among all New England ratepayers. FERC agreed, and ordered ISO-New England to develop a mechanism where the customers who benefit from the improvement pay for it. In cases where the parties cannot agree on who benefits, ISO-New England must provide an objective mechanism to allocate the cost among those customers who caused the congestion.

In the wake of alleged manipulations of the wholesale market in California, FERC has been particularly concerned about the exercise of market power. Under FERC's order, it will monitor the entire New England market to determine whether generators have exercised market power in a way that injures consumers. In areas where there are persistent constraints on transmission, it will be able to mitigate such behavior by several means before it occurs.

Proposed Nationwide Regulation

In July 2002, FERC proposed a regulation on standard market design and related issues, which if adopted would apply nationwide. FERC's goals in proposing this regulation are to ensure sufficient electric utility infrastructure, provide uniform and balanced market rules, and to protect customers through oversight of the wholesale electric market. While the proposed regulation is similar to the New England standard market design order, the proposed regulation is substantially broader in scope. If adopted, the proposed regulation would supersede conflicting provisions in the New England order.

Under the proposed regulation, bilateral contracts between generators and utilities would provide the foundation of the wholesale market. Existing contracts would be translated into tradable financial rights for use of the transmission system. The bilateral contract market would be supplemented by spot markets for electrical energy and for related services. As in the New England decision, FERC would monitor the market for the exercise of market power, and would be able to mitigate such market power. For example FERC could limit the amount generators could bid to supply power if it found that they were withholding available supply to raise prices.

As in the New England decision, the proposed regulation would seek to address congestion in the transmission system through the use of locational marginal pricing. An Independent Transmission Provider would be responsible for operating the transmission system. The provider could be a non-profit regional transmission organization or a for-profit transmission company, As discussed in OLR report 2002-R-0816, ISO-New England and its New York counterpart have proposed forming a regional transmission organization.

The proposed regulation would require utilities and other purchasers of wholesale power to ensure that they have adequate resources to meet their future demand. The resources could be supply or programs to reduce electric demand during periods of peak consumption (demand response). The purchasers would have to have a 12% more in resources over forecast peak demand (regions could impose higher reserve requirements). The regional transmission organization would be responsible for forecasting demand.

The proposal would also modify the way that transmission system expansions are funded. As a general rule, FERC proposes that those who benefit from a transmission or generation facility should pay for it. In the case of transmission lines of 138 kilovolts or more, the presumption would be that they serve the entire region and their costs should be allocated accordingly. The proposed regulation would also establish a regional planning process for new transmission, in which the Independent Transmission Provider would evaluate alternative supply and demand side proposals to address congestion.

FERC has a Web page dedicated to its proposed regulation, http: //www. ferc. gov/electric/rto/Mrkt-Strct-comments/smd. htm. Please note that the regulation is several hundred pages long, and addresses many issues not discussed in this report.

Implications for Connecticut

Standard market design may stimulate market solutions to the current shortcomings of New England's wholesale electric markets. In particular, it may provide market signals to encourage the allocation of resources to locate supply, conservation, and transmission where they are most needed. Standardization of market rules across the country could result in larger, more efficient markets. But, DPUC and others have asserted that the implementation of standard market design, particularly on the schedule contained in the FERC order and the proposed regulation, could impose substantial costs on Connecticut.

New England Order. DPUC has asked that FERC modify its order to phase in the implementation of standard market design. In particular, it has asked that the implementation of locational marginal pricing be phased in to give the state enough time to improve its transmission system, which it estimates will take three to five years. DPUC cites an ISO-New England estimate that locational marginal pricing will increase electric rates by $ 125 to $ 375 million per year, given the existing transmission constraints. Alternatively, DPUC suggests that if the locational marginal pricing provision is implemented starting next year, the effective date of other provisions affecting rates in Connecticut, such as payments for must-run power plants, be delayed.

DPUC asserts that the order's provision allocating the cost of the must-run plants to the specific regions in which they are located would be unfair, arbitrary and capricious and would impose unjust and unreasonable rates on Connecticut consumers. It claims that this provision will not encourage transmission improvements, which have already been proposed, and will not provide justifiable benefits to anyone. It also argues that it would premature to change the rules in New England, while FERC is developing nationwide rules. DPUC recommends that the costs of operating must-run plants continue to spread among all New England ratepayers for the next five years.

DPUC argues that the order's provision that would require that the cost of transmission system improvements be borne by the ratepayers who benefit would result in unjust and unreasonable rates. It estimates the cost of improving the system in southwestern Connecticut at $ 300 to $ 700 million. It recommends that the cost of lines designed to carry 345 kilovolts or more (such as Connecticut Light & Power's proposed Bethel-Norwalk line), or that improve reliability and relieve congestion, continue to be spread among all New England ratepayers. In their reply comments, the Maine PUC and other parties to the proceeding have strenuously objected to this proposal.

DPUC asserts that if FERC does not provide a transition period before implementing the "localization" of the above costs, Connecticut could face a "perfect storm" or risk becoming a "mini-California. " DPUC also notes that the proposal to create a northeastern regional transmission organization could cost the New England states (principally Connecticut, Massachusetts, and Vermont) an additional $ 62 million annually. DPUC has requested that FERC rehear or clarify its order on the issues discussed above. DPUC also asks FERC to strengthen the order's market power monitoring and mitigation provisions.

Proposed Nationwide Regulation. DPUC has raised similar concerns with regard to the proposed regulation's provisions on marginal locational pricing and the allocation of the costs of transmission system expansion. DPUC argues that the costs of such expansions cannot be readily divided between those that improve reliability versus those that simply provide economic benefits. It believes that market participants and state regulators will endlessly litigate over who should pay for such expansions. It proposes that FERC maintain the current rule, under which all New England ratepayers pay for expansions of lines with a capacity of 115 kilovolts or more.

Alternatively, it asks that, if FERC does adopt a "beneficiary pays" approach, that any project that meets this criterion pending before state siting authorities be treated under the current rule.

DPUC also has serious concerns regarding the market power mitigation provisions of the proposed regulation. It believes that the wholesale market is very vulnerable to the exercise of market power, even in areas that are not subject to transmission constraints. It argues that FERC should be able to mitigate abuses of market power in all areas.

It also argues that FERC should be allowed to (1) impose mitigation measures after market power has been exercised, in addition to the preventative measures proposed in the regulation and (2) impose additional mitigation measures, including refunds by offending market participants and fines.

DPUC has requested that FERC not give final approval to the regulations until it addresses these concerns. FERC has received detailed comments from dozens of parties, and it is not clear when the final regulation will be adopted.

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