99070

Prepared by the North Dakota Legislative Council staff for the Electric Utilities Committee July 1997

ELECTRIC INDUSTRY RESTRUCTURING STUDY - BACKGROUND MEMORANDUM

House Bill No. 1237 (1997), a copy of which is attached as Appendix "A", establishes an electric industry competition committee to study the impact of competition on the generation, transmission, and distribution of electric energy within this state. Section 1 of the bill states that the Legislative Assembly finds that the economy of North Dakota depends on the availability of reliable, low-cost electric energy and that there is a national trend toward competition in the generation, transmission, and distribution of electric energy and that the Legislative Assembly acknowledges that this competition has both potential benefits and adverse impacts on the state's electric suppliers as well as on their shareholders and customers and the citizens of this state.

Section 2 of the bill outlines the composition of the committee and directs the committee to study the impact of competition on the generation, transmission, and distribution of electric energy within this state and on the state's electric suppliers. As used in the bill, electric suppliers include public utilities, rural electric cooperatives, municipal electric utilities, and power marketers.

Section 3 of the bill outlines the study areas that the committee is to address in carrying out its statutory responsibilities. This section provides that the committee is to study the state's electric industry competition and electric suppliers and financial issues; legal issues; social issues; issues related to system planning, operation, and reliability; and identify and review potential market structures. Also, although many states are studying the restructuring of their electric industry, the bill requires the committee to review two areas unique to North Dakota that other states may not have addressed: (1) to what extent power produced by the Garrison Dam should be taxed by the state, and (2) the source and cost of power supply to the state's Indian reservations.

Proponents of the study testified at the standing committee hearings on the bill that the electric industry is changing rapidly and that if competition is to be introduced into North Dakota it should be done in a fair and equitable manner. Nationally, builders of new technology generating plants, the natural gas industry, and states with high electric rates or excess generating capacity are promoting electric industry restructuring. In summary, arguments put forward for restructuring or implementing competition in the electric industry include greater customer choice, the possibility that open competition may lower costs, generating efficiency may be encouraged through competition, and capital is allocated by the market-place. However, risks and challenges of retail competition include maintaining reliability of supply, determining pricing outcomes in which some customers may benefit at the expense of others, and allocating stranded costs.

TRADITIONAL RATIONALE FOR REGULATION

Under the current industry structure, electricity is provided to retail customers by utilities that have geographic monopolies on the provision on electric services within their service territories. Customers with a utilities service territory must purchase all of their electric services from that utility. These services include generation, transmission, distribution, customer service, meter reading, demand-side management, and aggregation and ancillary services.

Generally, three major types of electric utilities exist. These are investor-owned utilities, municipal and other government-owned utilities, and rural electric cooperatives. States regulate investor-owned utilities regarding their profits, operating practices, and pricing to end-use retail customers, while the Federal Energy Regulatory Commission (FERC) governs the pricing of wholesale bulk power sales and transmission services. Although House Bill No. 1237 directs the committee to study the impact of competition on the generation, transmission, and distribution of electric energy, nationwide the restructuring debate is over whether and how to separate the generation of electricity from other electric services in order to allow retail customers to shop for the electricity supplier of their choice.

In North Dakota, regulation of electric utilities engaged in the generation and distribution of light, heat, or power is performed by the state's Public Service Commission. North Dakota Century Code (NDCC) Section 49-02-03 grants to the Public Service Commission the power to supervise and establish rates. This section provides:

The commission shall supervise the rates of all public utilities. It shall have the power, after notice and hearing, to originate, establish, modify, adjust, promulgate, and enforce tariffs, rates, joint rates, and charges of all public utilities. Whenever the commission, after hearing, shall find any existing rates, tariffs, joint rates, or schedules unjust, unreasonable, insufficient, unjustly discriminatory, or otherwise in violation of any of the provisions of this title, the commission by order shall fix reasonable rates, joint rates, charges, or schedules to be followed in the future in lieu of those found to be unjust, unreasonable, insufficient, unjustly discriminatory, or otherwise in violation of any provision of law.

Concerning electric utility franchises, NDCC Section 49-03-01 provides that an electric public utility must obtain a certificate of public convenience and necessity from the Public Service Commission before constructing, operating, or extending a plant or system. Similarly, the state's Territorial Integrity Act, codified as Sections 49-03-01.1 through 49-03-01.5, requires an electric public utility to obtain a certificate of public convenience and necessity before constructing, operating, or extending a public utility plant or system beyond or outside of the corporate limits of any municipality. However, Section 49-03-01.3 exempts electric public utilities from the requirement that they obtain a certificate of public convenience and necessity for an extension of electric distribution lines within the corporate limits of a municipality in which it has lawfully commenced operations provided that the extension does not interfere with existing services provided by rural electric cooperatives or another electric public utility within the municipality and that any duplication of services is not deemed unreasonable by the Public Service Commission.

As described briefly above, traditionally, an electricity customer must purchase all of its electric services from the utility serving that customer's service territory, including the three primary services--generation, transmission, and distribution. Generation refers to the actual creation of electricity, which may be generated using a number of methods and fuel such as nuclear, coal, oil, natural gas, hydro, or wind. Transmission refers to the delivery of electricity over distances at high voltage from a generation facility through a transmission network usually to one or more distribution substations, where the electricity is stepped down for distribution to residential, commercial, and industrial customers. For the retail customer, the costs for these functions are bundled into retail rates, along with the cost of distribution. Distribution involves the retail sale of electricity directly to consumers.

Other functions traditionally provided by vertically integrated utilities include customer service, billing, meter reading, demand-side management, research and development, and aggregation and ancillary services. Aggregation is the development and management of both a power portfolio, combining power from a variety of sources in order to match the demand for power with adequate power supply and a portfolio of customers with combined demands in order to economically serve those customers. Ancillary services are those services necessary to effect a transfer of electricity between a seller and a buyer and to coordinate generation, transmission, and distribution functions to maintain power quality and system stability.

Again, under the current industry structure, the utility serving a service territory provides all of these services and functions, selling them as a single bundle. Nationwide, the restructuring debate centers on whether or how the generation function should be separated from the bundle, allowing retail customers to choose their electricity supplier. If generation is unbundled from transmission and distribution, under this scenario, these services may remain regulated functions.

REGULATORY COMPACT

The provision of electric service has traditionally been considered to exhibit the characteristics of a natural monopoly. According to economic theory, a natural monopoly exists in a market if one service provider in the market can serve customers more efficiently than many competing service providers. A common explanation for electricity provision as a natural monopoly is that allowing competitors to string duplicate transmission and distribution lines and construct excess generation capacity would waste resources and increase electric rates for customers. Generally, the characteristics of a natural monopoly include a high upfront capital investment in technology; limited storability of a provided service or goods; limited transportability, requiring operations near the end users; and cost advantages of large and integrated systems as a result of better utilization of existing capacity or economies of scale and scope.

In markets exhibiting the characteristics of natural monopoly, government intervention in the form of regulation over a single firm is considered necessary to provide the market discipline competition cannot provide. In exchange for this monopoly, each utility is required to serve all customers within its service territory and to provide quality service at just and reasonable rates. The utility is permitted to recover reasonable and prudent expenses associated with its provision of service plus a reasonable rate of return on its investment made to serve customers. This exchange is known as the regulatory compact.

Under the regulatory compact, the traditional method of rate determination has been cost-based, cost of service, or rate of return regulation. This type of regulation is designed to ensure that utilities offer their services at prices that are based on the cost of the services, rather than on the value customers place on those services. In traditional rate of return regulation, the regulating entity determines the revenue requirement, the reasonable and prudent cost of providing utility service, allocates the requirement among customer classes, and translates the allocated revenue requirement into rates.

Traditional rate of return regulation has been criticized for allowing a utility and its shareholders to pass on all of the utility's costs and risks to ratepayers and because the utility faces minimal risks, the utility has little or no incentive to increase its operating efficiency or to minimize its expenses. One critic has stated that cost-based regulation fails to penalize inefficient producers or reward efficient ones.

As an alternative to traditional rate of return regulation, some commentors have advocated and some states have implemented various forms of incentive regulation, including flexible regulation, targeted incentives plans, external performance indexing, price and revenue caps, and performance-based regulation. However, these forms of incentive-based regulation also have their critics and performance-based regulation opponents have argued that this type of regulation may result in the selection of inappropriate performance benchmarks; the temptation to incorporate too many, or contradictory, societal or regulatory goals, into the performance-based regulation plan; unreasonable returns to shareholders; or exacerbate the information asymmetry between utilities and regulators.

FEDERAL ACTIONS TO PROMOTE COMPETITION

In 1978, Congress enacted the Public Utility Regulatory Policy Act (PURPA). The goals of PURPA were to make the United States self-sufficient in energy, increase energy efficiency, and encourage the use of renewable alternative fuels. The legislation intended to achieve these goals by abandoning the use of natural gas to make electricity, mandating conservation of oil, and encouraging industry to cogenerate electricity using waste heat. The Public Utility Regulatory Policy Act required utilities to purchase bulk power produced from cogeneration facilities to ensure that it was financially attractive. However, states were allowed to determine the avoided costs and quantity of such power. Some states capped the price at the utility's avoided costs (the amount of money that an electric utility would need to spend for the next increment of electric generation that it instead buys from a cogenerator) and limited the obligation to purchase to the capacity of the utility. Other states allowed prices above the utility's avoided costs and ordered purchases of additional generation whether needed or not.

In 1992, Congress enacted the Energy Policy Act (EPAct) to encourage the development of a competitive, national, wholesale electricity market with open access to transmission facilities owned by utilities to both new wholesale buyers and new generators of power. In addition, EPAct reduced the regulatory requirements for new nonutility generators and independent power producers. The Federal Energy Regulatory Commission initiated rulemaking to encourage competition for generation at the wholesale level by assuring that bulk power could be transmitted on existing lines at cost-based prices. Under this legislation and rulemaking, generators of electricity, whether utilities or private producers, could market power from underutilized facilities across state lines to other utilities.

Finally, FERC has taken a number of steps to encourage competition in the wholesale market. These actions include authorizing market-based rates, issuing Section 211 wheeling orders, ordering open access transmission tariffs, and issuing the open access transmission rule (FERC Order No. 888). Market-based rates are those set by willing buyers and sellers of power. This method may be used instead of the more traditional method of ratesetting by regulators pursuant to administrative hearings, with rates based on the costs on producing the power. On April 24, 1996, FERC issued Orders 888 and 889 that essentially require all utilities which own, control, or operate transmission lines to file nondiscriminatory open access transmission tariffs that offer competitors transmission service comparable to the service which the utility provides itself. In addition, FERC Order 888 recognizes the right of utilities to recover legitimate, prudent, and verifiable costs stranded by opening up the wholesale electricity market, i.e., stranded costs. Finally, FERC Order 888 requires public utilities to functionally unbundle their power and services for wholesale power transactions by requiring the internal separation of transmission from generation marketing services.

Four comprehensive utility restructuring bills have been introduced in the 105th Congress to expand on the initiatives contained in EPAct and to build on the Federal Energy Regulatory Commission's actions. In general, these comprehensive approaches to utility restructuring have three components--provisions for retail competition, commonly called retail wheeling, which would permit retail customers to choose from whom they obtain their electricity supply; provisions reforming Section 210 of PURPA, which provides cogenerators and small power producers a guaranteed market for their power; and provisions reforming PUHCA, the Public Utility Holding Company Act of 1935, which regulates various financial transactions of large holding companies having an interest in a public utility company. A summary of the major provisions of these bills, prepared by the Congressional Research Service, is attached as Appendix "B".

ELECTRIC INDUSTRY RESTRUCTURING INITIATIVES IN OTHER STATES

California

In 1996, the California Legislature enacted a major restructuring bill that calls for customer choice no later than January 1, 1998, creates an independent system operator (ISO), a power exchange, and funds stranded cost recovery through bonds. Provisions of the California legislation include:

• Customer choice commencing no later than January 1, 1998. The California Public Utilities Commission will establish a phasein schedule that is equitable for all customer classes and that must be completed for all customer by January 1, 2002.
• An immediate rate reduction, through use of a bond financing mechanism, of not less than 10 percent for residential and small commercial customers. Additionally, rate savings for these customer classes are expected to be no less than 20 percent by April 1, 2002. Up to $10 billion in rate reduction bonds will be issued in order to achieve the immediate rate reduction and will spread recovery of a portion of competition transition charge (CTC) for these customers over 10 years.
• A limited transition period, ending December 31, 2001, during which utilities have an opportunity to recover stranded investment through a non-bypassable CTC levied on the usage of electric power. Recovery is limited to certain categories and types of costs and to only that portion that can be recovered under a rate freeze during the transition period.
• A "firewall" to shield residential and small commercial customers from paying for any CTC exemptions granted to industrial users for economic development or retention purposes.
• An ISO and a power exchange subject to the jurisdiction of a five-member oversight board appointed by the Governor and the Legislature. Publicly owned utilities and investor-owned utilities are required to give control of their transmission facilities to the ISO.
• A requirement that utilities continue funding energy conservation and low-income assistance programs through 2001 and that ratepayers pay for that portion recoverable under the rate freeze. Assistance programs must be funded at levels not less than those authorized for 1996. Funding for energy efficiency and conservation must at least equal $228 million per year through 2001; during the same period, $62.5 million must be provided for research, development, and demonstration projects to advance science or technology that would not otherwise be adequately provided for in a competitive market. The amount of $540 million is provided for renewable resource technologies in this time period.
• A requirement that all electric sellers, marketers, and aggregators register with the California Public Utilities Commission and provide consumers with adequate and reliable information regarding supplier options. Contract recision provisions and "anti-slamming" or "grid-napping" protections are also included in the legislation.

Maine

Legislation enacted by the Maine Legislature during the 1997 legislative session established retail competition for the purchase and sale of electricity beginning March 1, 2000. The legislation permits electric utilities a reasonable opportunity to recover verifiable and unmitigable stranded costs and also establishes a standard-offer service for customers who do not seek or take power in the competitive marketplace. The law sets a 33 percent market-share cap for Central Maine Power Company and Bangor Hydro-Electric Company and preserves low-income assistance programs funded through transmission and distribution rates. It establishes a 30 percent renewal-resource portfolio requirement for competitive electricity providers and a program for renewable research development funded through voluntary contributions. Finally, it requires the Maine Public Utilities Commission to develop a consumer education program.

Montana

During the 1997 legislative session, the Montana Legislature enacted Senate Bill No. 390, the Montana Electric Utility Industry Restructuring and Consumer Choice Act. This Act established restructuring requirements for Montana's electric utilities industry. Pilot programs will be conducted beginning July 1, 1998, and a report on those programs is due by July 1, 2000. All utility customers must have a choice in their electricity supplier before July 1, 2002. All utilities must submit transmission plans; certain stranded costs laid out in transition plans will be reviewed and will be paid for by transition bonds. Beginning January 1, 1999, 2.4 percent of each utility's annual retail sales revenue in Montana for the calendar year ending December 31, 1995, is established as the annual funding level for universal system benefits programs. Unless otherwise modified, this funding level remains in effect until July 1, 2003. The recovery for these programs is authorized through a universal systems benefits charge assessed at each customer meter. One feature of the bill that is relevant to electric industry restructuring in North Dakota is how the bill deals with rural electric cooperatives. Section 20 of the bill provides that rural electric cooperatives have the choice of opting in or out of offering their customers choice. If a cooperative opts in, it must certify to the Montana Public Service Commission that it has adopted a transition plan consistent with the provisions of the Act, but essentially the same as the plans of investor-owned utilities. If a cooperative opts out, the cooperative is precluded from accessing the distribution system, and thus customers, of other utilities that have opened their system up without a preexisting contract. A cooperative must participate in the universal systems benefits program whether it opts in or out. A copy of the Montana Electric Utility Industry Restructuring and Customer Choice Act is attached as Appendix "C", and a copy of a summary of the Act prepared by the Montana Department of Environmental Quality is attached as Appendix "D".

Oklahoma

Senate Bill No. 500, signed by the Governor of Oklahoma on April 25, 1997, creates the Electric Restructuring Act of 1997 and states electric utility industry restructuring goals for that state. The Act establishes customer choice by July 1, 2002. Before that date a series of studies will be conducted on various aspects of restructuring. These studies include:

• Formation of an independent system operator (ISO) for Oklahoma or the region that must have begun by July 1, 1997, and report by February 1, 1998.
• A study of technical issues such as reliability, safety, transmission, etc., that must begin by January 1, 1998, and report findings by December 31, 1998.
• A study of financial issues such as rates, charges, and electric service provider financial obligations. This study must commence on January 1, 1999, and report findings by December 31, 1999.
• A study of consumer issues that must begin by July 1, 1999, and report findings by August 31, 2000.

In addition, the Oklahoma Tax Commission will conduct a study to assess the effect of restructuring on state, county, and local tax revenue and examine the feasibility of establishing a consumption-based tax to provide at least the existing level of revenues. This study must have started by July 1, 1997, and must provide findings by December 31, 1998. The commission is prohibited from adopting any rules or issuing orders without prior authorization from the Oklahoma Legislature or the Joint Electric Utility Task Force.

New Hampshire

The relevant provisions of the New Hampshire restructuring legislation are:

• The New Hampshire Public Utilities Commission must have issued a final restructuring order by June 30, 1997. Utilities must offer retail access by January 1, 1998. The New Hampshire Public Utilities Commission may delay this date by up to six months without legislative approval.
• Generation must at least be functionally separated from transmission and distribution functions. The Public Utilities Commission may require that distribution and electricity supply services be provided by separate utility affiliates. However, utilities may own small scale generation facilities as a means of minimizing transmission and distribution costs. While divestiture is not required, utilities must mitigate their stranded costs, with the sale of surplus assets identified as one form of mitigation.
• In the implementation of full-fledged retail competition, utilities are allowed recovery of net, nonmitigable environmental costs and costs of legally mandated purchased power contracts. They are allowed to seek recovery of generation-related assets.
• The Act allows the Public Utilities Commission to establish a stranded cost recovery charge, with the burden of proof for recovery on the utility. It also allows the Public Utilities Commission to establish interim charges effective for two years from the date that utilities file plans to comply with the Act. The Act states that entry and exit fees are not preferred recovery mechanisms.

Pennsylvania

House Bill No. 1509, enacted by the Pennsylvania General Assembly in 1996, addressed electric industry restructuring in Pennsylvania. The major provisions are:

• By January 1, 1999, utilities must offer retail access to one-third of their peak load for each customer class; two-thirds by January 1, 2000; and all by January 1, 2001. Utilities must provide this opportunity on a first-come, first-served basis except as directed by the Pennsylvania Public Utilities Commission. The Pennsylvania Public Utilities Commission may delay implementation of the initial phase by up to one year.
• The Act requires unbundling of the generation, transmission, and distribution functions. Generation will be deregulated while transmission and distribution will continue to be regulated as natural monopolies. Divestiture is permitted but not required.
• Utilities are statutorily entitled to recover their nuclear decommissioning costs; contracts for power purchased from nonutility generators, and prudently incurred costs associated with buydowns and buyouts of these contracts; and regulatory assets. The Pennsylvania Public Utilities Commission may allow recovery of generation-related costs in addition to those listed above. Utilities must mitigate costs to the extent practicable through such measures as accelerated depreciation and minimize rates while maintaining safe and efficient operations.
• The Act establishes a competitive transition charge (CTC) applied to any customer using the transmission or distribution system. The CTC may not shift costs between or within customer classes. Customers that install onsite generation and significantly reduce their purchases through transmission and distribution systems must pay a fully allocated CTC.
• The Act establishes a cap on total rates for utility company customers for the shorter of 4.5 years or until the utility finishes collecting its stranded costs through transition charges and all customers can choose suppliers. The generation component of rates plus transition charges may not exceed current Public Utilities Commission-approved generation costs for the shorter of nine years or until the utility finishes collecting its stranded costs through transition charges and all customers can choose suppliers. Limited exceptions to these caps exist, for example, if they preclude a utility from earning its Public Utilities Commission-authorized rate of return on its investment.
• Concerning securitization, under the Act, the Public Utilities Commission may issue a qualified rate order to allow issuance of transition bonds. Bonds may have a maturity of up to 10 years. Proceeds of the bonds must be used to reduce stranded costs and other transition costs. Competitive transition charge must be reduced to the extent stranded costs have been refinanced. Savings and interest costs must be passed on directly to customers through rate reductions.
• Concerning taxation, the Act requires continuation of gross receipts and other state utility taxes with a formula to maintain revenue neutrality through 2003. The gross receipts tax applies to nonutility electric suppliers.

Rhode Island

The 1996 Rhode Island electric restructuring initiative, codified as Rhode Island General Laws § 39-1-27 et seq., provides:

• As of July 1, 1997, utilities must offer retail access to all new commercial and industrial customers, all existing manufacturing customers with average annual demand of 1,500 kilowatts or more, and all accounts of the state government, subject to an overall cap of 10 percent of the utility's total sales.
• As of January 1, 1998, utilities must offer retail access to all existing manufacturing customers with average annual demand of 200 kilowatts or more and all accounts of municipal governments. Utilities are not required to provide retail access to customers accounting for more than 20 percent of their total sales under this and the preceding provision.
• As of July 1, 1998, utilities must offer retail access to all of their remaining customers. This deadline is moved up if retail access is available to 40 percent or more of total sales in New England. The Rhode Island Public Utilities Commission may delay this deadline by up to six months to permit extension of retail access on reasonable terms.
• The Act requires unbundling of generation, transmission, and distribution functions. Generation will be deregulated, while transmission and distribution will continue to be regulated by the federal Energy Regulatory Commission and Rhode Island Public Utilities Commission, respectively. Any utility recovering a stranded cost through the transition charge must determine the market value of its fossil fuel and hydrogenerating assets by the sale or spinoff of these facilities. The market value is then deducted from the utility's stranded costs. Utilities must also attempt to sell their portion of their purchase power contracts that exceed market rates to reduce their stranded costs.
• Under the Act, stranded costs include nuclear decommissioning costs and nuclear operation and maintenance costs that would continue if the plant were shut down; above-market costs of purchase power contracts and the reasonable costs of buying out or buying down these contracts; regulatory assets; and the net unrecovered capital costs of all of the generating plants owned by the utility or its wholesale power distributor as of December 31, 1995, whether or not plants are operating.
• The Act establishes a transition charge applied to any customer using the transmission or distribution system. A nonutility electric supplier may pay part or all of its customer's transition charges. The charge is set at 2.8 cents per kilowatt hour for the period between July 1, 1997, and December 31, 2000. The charge is subject to adjustment to account for the disposition, pursuant to the Act, of nonnuclear generating assets by wholesale power suppliers. From January 1, 2001, the Public Utilities Commission sets the charge. After January 1, 2010, there is no allowance for costs associated with regulatory assets and unamortized capital investments in generating plants.
• Rate increases generally must hold to the rate of inflation from January 1, 1997, through December 31, 1998. These increases do not apply to low-income customers. Utilities must file performance-based rate plans with the Public Utilities Commission.
• The Act establishes a commission that was required to submit a plan to the General Assembly by January 1, 1997, on assessing and taxing utilities and nonregulated power producers.

POSSIBLE STUDY APPROACH

In carrying out its statutory responsibilities under House Bill No. 1237, the committee will need to address a number of complex issues in addition to those enumerated in House Bill No. 1237. These include market structure; competitive parity; utility taxation; stranded costs, which may be defined as prudent costs incurred by a utility which may not be recoverable under market-based retail competition; universal service; integrated resource planning; stranded benefits, which may be defined as benefits associated with regulated retail electric service that may be at risk under open market retail competition; unbundling; merchant plants; antitrust issues; pilot programs; cost-shifting; safety and reliability; and environmental issues. The committee will also wish to monitor federal electric industry restructuring initiatives and follow electric industry restructuring developments in other states. In conducting this study, the committee could solicit testimony from a number of sources. These include the Public Service Commission and its staff, representatives of the state's investor owned utilities, representatives of the state's generation and transmission cooperatives, representatives of the state's distribution cooperatives, the North Dakota Association of Rural Electric Cooperatives, power marketers, and large commercial and industrial power users.

ATTACH:4

« Back

Top