ELECTRIC INDUSTRY COMPETITION COMMITTEE

The Electric Industry Competition Committee was created by House Bill No. 1237 (1997) to study the impact of competition on the generation, transmission, and distribution of electric energy within this state. The bill was codified as North Dakota Century Code (NDCC) Sections 54-35-18 through 54-35-18.3. Section 54-35-18 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 the Legislative Assembly acknowledges this competition has both potential benefits and adverse impacts on the state's electric suppliers as well as on their shareholders and customers and citizens of this state.

North Dakota Century Code Section 54-35-18.1 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 this state's electric suppliers. Electric suppliers include public utilities, rural electric cooperatives, municipal electric utilities, and power marketers.

North Dakota Century Code Section54-35-18.2 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, and issues related to system planning, operation, and reliability and is to identify and review potential market structures.

In addition to the committee's study of the impact of competition on the generation, transmission, and distribution of electric energy within this state, the Legislative Council directed the committee to review wind energy as a part of its study of electric industry competition and electric suppliers.

Committee members were Representatives Al Carlson (Chairman), Robert Huether, and MatthewM. Klein and Senators Duane Mutch, LarryJ. Robinson, and Herb Urlacher.

The committee submitted this report to the Legislative Council at the biennial meeting of the Council in November 2002. The Council accepted the report for submission to the 58th Legislative Assembly.

ELECTRIC INDUSTRY RESTRUCTURING
Background

House Bill No. 1237 (1997) reflected the Legislative Assembly's concern that the electric industry is changing rapidly and 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 were promoting electric industry restructuring. Arguments put forward for restructuring or implementing competition in the electric industry included greater customer choice, the possibility that open competition may lower costs, encourage generating efficiency, and allocate capital. However, risks and challenges of retail competition included maintaining reliability of supply, pricing outcomes in which some customers may benefit at the expense of others, and allocating stranded costs. The impetus for electric industry restructuring also came from large industrial and commercial energy users that were opposed to subsidizing residential electricity users. For example, some industrial users were paying 150 percent of the actual cost of providing energy to those users, while residential customers were paying only 60 to 70 percent of the actual cost of providing energy to them.

Traditional Rationale for Regulation

Under the current industry structure, electricity is provided to retail customers by utilities that have geographic monopolies on the provision of electric service within their service territories. Customers within a utility's service territory must purchase all 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--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 (1997) directed 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 the Public Service Commission regulates electric utilities engaged in the generation and distribution of light, heat, or power. North Dakota Century Code 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, 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 the corporate limits of any municipality. However, Section 49-03-01.3 exempts electric public utilities from the requirement to 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 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.

Traditionally, an electricity customer must purchase all 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. The utility serving a service territory provides these services and functions 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, these services may remain regulated functions.

The Regulatory Compact

The provision of electric service traditionally exhibits 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.

In markets exhibiting the characteristics of a 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 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 a 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 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.

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 incentive plans, external performance indexing, price and revenue caps, and performance-based regulation. However, these forms of incentive-based regulation also have their critics. Performance-based regulation opponents have argued that this type of regulation may result in the selection of inappropriate performance benchmarks; incorporation of too many, or contradictory, societal or regulatory goals into the performance-based regulation plan; unreasonable returns to shareholders; or exacerbation of the information asymmetry between utilities and regulators.

Federal Actions to Promote Competition

In 1978 Congress enacted the Public Utility Regulatory Policy Act. The goals of this Act were to make the United States self-sufficient in energy, increase energy efficiency, and encourage the use of renewable alternative fuels. The Act 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 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 (the amount of money an electric utility would need to spend for the next increment of electric generation that it instead buys from a cogenerator) and quantity of such power. Some states capped the price at the utility's avoided costs 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 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, the Act 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.

The Federal Energy Regulatory Commission has taken a number of steps to encourage competition in the wholesale market. These actions include authorizing market-based rates, issuing Section211 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 cost of producing power. On April24, 1996, the Federal Energy Regulatory Commission issued Order Nos. 888 and 889, which require all utilities that own, control, or operate transmission lines to file nondiscriminatory open-access transmission tariffs that offer competitors transmission service comparable to the service that the utility provides. In addition, FERC Order No. 888 recognizes the right of utilities to recover legitimate, prudent, and verifiable costs stranded by opening the wholesale electricity market, i.e., stranded costs. The order also requires public utilities to unbundle their power and services for wholesale power transactions by requiring the internal separation of transmission from generation marketing services.

Electric Industry Restructuring Initiatives in Other States

Arizona, Connecticut, Delaware, the District of Columbia, Illinois, Maine, Maryland, Massachusetts, Michigan, New Hampshire, New Jersey, New York, Ohio, Pennsylvania, Rhode Island, Texas, and Virginia have either enacted enabling legislation or issued a regulatory order to implement retail access. Retail access either is available to all or some customers or will soon be available in these states. Some states are running pilot programs, and they will begin to implement retail access in the near future. Arkansas, Montana, Nevada, New Mexico, Oklahoma, and Oregon have either enacted legislation or issued regulatory orders to delay implementing retail access. Although West Virginia has enacted legislation that approved that state's Public Service Commission's plan to restructure and implement retail access, the process is being delayed until a bill for tax reform is enacted. Alabama, Alaska, Colorado, Florida, Georgia, Hawaii, Idaho, Indiana, Iowa, Kansas, Kentucky, Louisiana, Minnesota, Mississippi, Missouri, Nebraska, North Carolina, North Dakota, SouthCarolina, South Dakota, Tennessee, Utah, Vermont, Washington, Wisconsin, and Wyoming have not enacted enabling legislation to restructure their electric power industries or implement retail access. California has suspended direct retail access.

Oregon, Nevada, Montana, New Mexico, Oklahoma, Arkansas, and West Virginia have recently pulled back from or postponed their original restructuring plans. The National Regulatory Research Institute has classified the status of electric deregulation in the United States into fourcategories, i.e., retail access proceeding, law passed but delayed or delay likely, studying restructuring, or no action likely. The institute has classified Arizona, Connecticut, Delaware, the District of Columbia, Illinois, Maine, Maryland, Massachusetts, Michigan, Montana, New Hampshire, New Jersey, New York, Ohio, Oregon, Pennsylvania, Rhode Island, and Texas as states where retail access is proceeding. Arkansas, California, Nevada, New Mexico, and Oklahoma are classified as states in which legislation has been enacted but in which it is delayed or likely to be delayed. Florida, Georgia, Kentucky, Louisiana, Minnesota, Mississippi, Missouri, Nebraska, North Dakota, Tennessee, Vermont, and Washington are classified as states studying electric industry restructuring. Alabama, Alaska, Colorado, Hawaii, Idaho, Indiana, Iowa, Kansas, North Carolina, South Carolina, South Dakota, Utah, Wisconsin, and Wyoming are classified as states in which electric industry restructuring is not likely.

California discontinued retail access indefinitely in October 2001. In the National Conference of State Legislatures' publication California's Power Crisis - What Happened? What Can We Learn? by MatthewH. Brown, the author discusses the electricity restructuring experience in California. The author identifies several major factors as contributing to California's problems and making risk management a crucial step for the power industry. These include:

• For a decade, no company--utility or nonutility--had made a major investment in a new power plant in California.
• For some years, no major investment was made in power plants in the geographical region surrounding California.
• The supply of power diminished in the Pacific Northwest, another area that traditionally had exported power to California.
• Demand for electricity increased somewhat in California and soared in the region surrounding California.
• Emissions trading markets in southern California saw a steep price increase.
• Natural gas prices skyrocketed in 2000.
• Customers have available only crude tools to help them manage their own demand and to respond to price increases in the wholesale power markets.
• Some analysts claim that generators may have charged unreasonably high prices at times of peak loads.

The report concludes by suggesting nine lessons from California's experience:

• Properly functioning retail markets require properly functioning wholesale markets.
• To function properly, wholesale markets need an active demand side, as well as supply side, competition.
• Wholesale markets need adequate generating capacity (supply) complemented by cost-effective end-use energy efficiency.
• Power markets can benefit from a diversity of fuel supplies for generation. Heavy reliance on a single fuel can push wholesale prices up quickly if the price of that fuel increases.
• Power suppliers must be able to manage their own--and their customers'--price risks.
• In states that have vibrant retail markets--or that currently are almost nonexistent--customers will have an opportunity to manage their own price and supply risks.
• Some kind of state oversight of power markets may be required to evaluate energy needs and the ability of the system to meet those needs.
• Some kind of regional oversight and collaboration in power markets also may be required.
• Capping or freezing rates offers important consumer protection in markets in which a commodity is competitively procured but also can affect how quickly a competitive market develops and, absent some flexibility, may affect the financial health of market participants.

Federal Restructuring Initiatives

Nine bills relating to electric industry restructuring were introduced during the 105th Congress. However, none became law. At least 14 bills relating to electric industry restructuring were introduced in the 106thCongress. However, some dealt with taxation and other issues and only related tangentially to electric industry restructuring. None became law. At least 48 bills relating directly or indirectly with the issue of restructuring the United States electric power industry have been introduced in the 107th Congress.

Testimony and Committee Activities
Restructuring

The committee received testimony that no additional states are likely to enact restructuring legislation, and a number of states that have enacted restructuring legislation have delayed implementation for a period of years or indefinitely. The committee received testimony that there is little reason to consider retail choice legislation in North Dakota and that the committee should focus its attention on other issues that have been identified by the study process.

The committee received testimony from a representative of the state's investor-owned utilities that interest nationally in deregulation is waning and deregulation of the electric industry is not imminent in North Dakota. A representative of Missouri River Energy Services testified there must be vigorous wholesale competition before retail competition can occur and until this occurs the committee should not study the issue of electric industry restructuring any further. In light of agreement between the state's investor-owned utilities, the North Dakota Association of Rural Electric Cooperatives, and representatives of the state's municipal electric utilities that other states are reassessing their restructuring initiatives and because of low-cost and reliable electric service in North Dakota there is no imminent need for restructuring in this state, the committee focused its attention on the taxation of electric utilities, regulation of cooperatives, monitoring the Lignite Vision 21 program, and reviewing the operation of the Territorial Integrity Act as well as conducting its wind energy study.

Taxation of Electric Utilities

Representatives of the North Dakota Association of Rural Electric Cooperatives testified that the association has promoted and continues to support a property tax replacement plan that is fair to utilities and ratepayers, is revenue-neutral, and is easy to administer. However, representatives of the state's investor-owned utilities testified that electric utility taxation issues have been successfully addressed by the Legislative Assembly and any taxation proposal that increases transmission taxes may jeopardize the Lignite Vision 21 program.

The committee began its review of the taxation of the electric utility industry in North Dakota by reviewing a bill draft that had been considered by the 1999-2000 interim Electric Industry Competition Committee but not recommended to the Legislative Council.

The bill draft would have applied the state's coal conversion tax to Montana-Dakota Utilities Company's Heskett Plant in Mandan; removed investor-owned utility property from central assessment under NDCC Chapter57-06; removed the gross receipts tax for rural electric cooperatives; imposed transmission and distribution line taxes in lieu of property taxes except that property taxes would still be imposed on land, office or administrative-type buildings, and buildings and structures not used primarily and directly in the delivery of electricity through transmission and distribution lines; subjected peaking plants of less than 80 megawatts to local property tax assessment or exempted them as property used primarily in the delivery of electricity through lines; increased the transmission line tax; imposed a distribution tax; excluded municipal electric utilities from coverage; and allocated transmission and distribution tax revenue with a continuing appropriation to political subdivisions.

The bill draft would have imposed an annual transmission line mile tax on transmission lines based on their nominal operating voltages on April 1 of each year. A tax of $200 would have been imposed on transmission lines that operate at a nominal operating alternating current voltage of less than 57 kilovolts; a tax of $300 would have been imposed on transmission lines that operate at a nominal operating alternating current voltage of 57 kilovolts or more, but less than 69 kilovolts; a tax of $400 would have been imposed on transmission lines that operate at a nominal operating alternating current voltage of 69 kilovolts or more, but less than 115kilovolts; a tax of $600 would have been imposed on transmission lines that operate at a nominal operating alternating current voltage of 115 kilovolts or more, but less than 230 kilovolts; a tax of $800 would have been imposed on transmission lines that operate at a nominal operating alternating current voltage of 230 kilovolts or more, but less than 345 kilovolts; a tax of $1,000 would have been imposed on transmission lines that operate at a nominal operating alternating current voltage of 345kilovolts or more, but less than 500 kilovolts; a tax of $1,200 would have been imposed on transmission lines that operate at a nominal operating direct current voltage of less than 400 kilovolts; a tax of $1,300 would be imposed on transmission lines that operate at a nominal operating alternating current voltage of 500kilovolts or more; and a tax of $1,500 would have been imposed on transmission lines that operate at a nominal operating direct current voltage of 400 kilovolts or more.

Concerning distribution taxes, distribution companies would have been subject to a distribution tax of 75.83cents per megawatt-hour for the retail sale of electricity to commercial or industrial consumers and a rate of $1.2638 per megawatt-hour for the retail sale of electricity to noncommercial or nonindustrial consumers. The bill draft included a continuing appropriation for allocation of electric transmission and distribution tax revenue to counties thus obviating the need for counties to approach the Legislative Assembly each session to appropriate the revenue from the electric transmission and distribution taxes to these political subdivisions. Revenue from the tax on transmission lines would have been allocated among counties based on the mileage of transmission lines and the rates of tax on those lines within each county. Revenue received by a county would have been allocated among taxing districts in the county based on the mileage of transmission lines and the rates of tax on those lines within each taxing district. Revenue from that portion of a transmission line located in more than one taxing district would have been allocated among those taxing districts in proportion to their respective current property tax mill rates that apply to the land on which the transmission line is located. Revenue from the distribution company tax would have been allocated to the county in which the retail sale to which the tax applied was made and allocated among taxing districts in the county in proportion to their respective property tax levies in dollars on property within the county in the previous taxable year. Cities that operate municipal electric utilities would have been excluded from allocations and computations under this provision.

After reviewing the proposal that had been developed by the 1999-2000 Electric Industry Competition Committee, the committee requested the electric industry taxation study working group to update the electric utility statistics that had been used to develop that proposal. Updated electric utility statistics contained information on generation, coal conversion taxes paid by plant and year, transmission taxes, electricity sales by utility, electric utility gross receipts taxes paid, electric utility city privilege taxes paid, public utility property taxes paid, electric utility real estate taxes paid, income taxes on electric operations paid, and payments in lieu of taxes paid by municipal power systems. The committee learned that the average for taxes paid during the period 1998 through 2000 was $29,229,446 per year which compares to approximately $28million per year in the three-year period immediately preceding 1998. After receiving this information, the committee invited representatives of the North Dakota Association of Rural Electric Cooperatives, the state's investor-owned utilities, the state's municipal electric utilities, and other interested persons to submit proposals relating to the taxation of electric utilities to the committee. The North Dakota Association of Rural Electric Cooperatives submitted a proposal that was considered by the committee.

This bill draft would have restructured taxation of the electric industry by eliminating property taxes centrally assessed under current law for the state's investor-owned utilities, eliminating the gross receipts tax as currently assessed for the state's rural electric cooperatives, and replacing those taxes by a tax on the transmission and distribution of electricity. The bill draft would have imposed an annual transmission line mile tax on transmission lines based on their nominal operating voltages on January1 of each year. A tax of $75 would have been imposed on transmission lines that operate at a nominal operating voltage of less than 50kilovolts; a tax of $150 would have been imposed on transmission lines that operate at a nominal operating voltage of 50kilovolts or more, but less than 100kilovolts; a tax of $300 would have been imposed on transmission lines that operate at a nominal operating voltage of 100kilovolts or more, but less than 200kilovolts; a tax of $450 would have been imposed on transmission lines that operate at a nominal operating voltage of 200kilovolts or more, but less than 300kilovolts; a tax of $600 would have been imposed on transmission lines that operate at a nominal operating voltage of 300kilovolts or more, but less than 400kilovolts; and a tax of $900 would have been imposed on transmission lines that operate at a nominal operating voltage of 400kilovolts or more.

A distribution company, defined as a company engaged in distribution of electricity for retail sale to consumers in this state through distribution lines and excluding municipal electric utilities, would have been subject to a distribution tax of 54cents per megawatt-hour for the retail sale of electricity delivered through a distribution line to a consumer and a tax at the rate of ninety-twohundredths of 1percent of the company's gross revenue from the retail sale of electricity delivered through a distribution line to a consumer. The distribution taxes would not apply to the sale of electricity to a coal conversion facility subject to taxation under NDCC Chapter 57-60. The revenue on transmission lines would be allocated among counties based on the mileages of transmission lines and the rates of tax on those lines within each county. The bill draft contained twoalternatives for distribution of the revenue from the distribution company tax. One alternative would have provided that revenue from the distribution company tax would be allocated to the county in which the retail sale to which the tax applied was made. The second alternative would have provided that revenue from the taxes paid by a distribution company would be allocated to each county in which that distribution company's distribution lines are located in the ratio in which the number of miles of its lines in each county bears to the total number of miles of lines of the distribution company in the state. The committee revised the bill draft to provide that the 54 cent per megawatt-hour for the retail sale of electricity tax be distributed to each county in which the distribution company's distribution lines are located in the ratio in which the number of miles of its lines in each county bears to the total number of miles of lines of the distribution company in this state and that the ninety-two hundredths of 1percent tax of the company's gross revenue from the retail sale of electricity be allocated to the county in which the retail sale to which the tax applied was made.

A representative of the state Tax Commissioner reported that preliminary calculations indicated the total proposed taxes would generate approximately $800,000 to $950,000 less per year than the amount levied on distribution and transmission companies in the years 1998 through 2000. The average electric utility taxes for the period 1998 through 2000 was $13,021,084, while the estimated total proposed tax based on estimated 2002 figures was $12,205,335. However, the 2002 figure was overestimated by the amount of tax on electricity sold to a coal conversion facility.

A representative of the North Dakota Association of Rural Electric Cooperatives testified that the proposal met the committee's parameters of revenue neutrality and minimization of tax shifts among taxpayers. The committee received testimony that under the proposal, without real estate tax replacement, distribution cooperatives would pay $332,065 less in taxes, generation and transmission cooperatives would pay $158,653 more in taxes, and investor-owned utilities would pay $130,641 more in taxes. Although the distribution cooperatives would pay less in taxes, Cass County Electric Cooperative and Mor-Gran-Sou Electric Cooperative would pay additional taxes. Among generation and transmission cooperatives, Basin Electric Power Cooperative and Great River Energy would pay more in taxes and among investor-owned utilities, Xcel Energy, Inc., and Otter Tail Power Company would pay less while Montana-Dakota Utilities Company would pay more.

Representatives of the state's investor-owned utilities opposed the proposal because although they pay from $2.4million to $2.5million in corporate income taxes annually, the proposal did not address corporate income taxes paid by investor-owned utilities. Representatives of the state's investor-owned utilities testified that a taxation system that neither advantages or disadvantages any electric provider and taxes them all equally regardless of how they are organized must consider the corporate income tax. Also, the transmission line mile tax segment of the proposal transfers tax obligations away from the electric cooperatives and shifts them to the state's investor-owned utilities and does nothing to encourage the construction of additional transmission facilities in the state. Also, the committee received testimony that for investor-owned combination utility companies, implementation of the proposal would present administrative burdens. Under current law Montana-Dakota Utilities Company and Xcel Energy, Inc., because they are combination utility companies providing both natural gas and electricity to their customers, are subject to advalorem taxes on all of their substations, pipelines, distribution lines, tools, trucks, equipment, and office buildings. The committee received testimony that the proposal would subject these companies to the burden of separating common property--property used for both electric and natural gas operations--and subject them to twodifferent tax systems, one for electric operations and one for natural gas operations.

A representative of the Lignite Energy Council testified that that organization is opposed to any increase in transmission taxes because any increase in the transmission tax adds cost to the expense of transporting electricity and thus adds cost to the Lignite Energy Council's primary product making it less competitive.

The committee reviewed a bill draft relating to establishing a property tax exemption for new electric transmission lines. The bill draft would have provided that a transmission line of 230kilovolts or larger, which is initially placed in service after December31, 2002, would be exempt from property taxes for the taxable year in which the line is initially put into service, and property taxes as otherwise determined by law on the transmission line would be reduced by 75percent for the second taxable year of operation of the transmission line, 50percent for the thirdtaxable year of operation of the transmission line, and 25percent for the fourthtaxable year of operation of the transmission line. The committee extended the transmission line property tax exemption to existing transmission lines of 230 kilovolts or more that are upgraded so that their carrying capacity is increased 50percent or more. This proposal was opposed by the Lignite Energy Council because although it would have provided an incentive to construct new transmission facilities, the bill draft would have raised the transmission line mile tax once the tax moratorium expired.

Representatives of Otter Tail Power Company testified that no transmission line owner should be placed at an advantage or disadvantage in the marketplace for new transmission services simply because of its form of ownership. Based on this premise, they proposed changing the taxation method on lines that are 230kilovolts or larger and built on or after January1, 2002. They testified that this proposal would not impact the revenue received on transmission lines currently in service; would provide additional revenue for the taxing jurisdictions in which investor-owned utilities built new transmission lines; would equalize new transmission costs for both electric cooperatives and investor-owned utilities; would reduce the transmission costs for exporting excess energy to other utilities, making the cost of this energy more competitive; and would support the Lignite Vision 21 program and the Lignite Energy Council's goal to generate more power from North Dakota lignite and export this power at the most competitive price. This proposal was received too late in the interim for the committee to consider it.

The committee received testimony from a representative of the Utility Shareholders of North Dakota urging the committee to recommend legislation to place all utility organizations on the same taxation footing by repealing all payments made in lieu of personal property taxes for electric cooperatives and placing all electric cooperative property, not included in specific generation or transmission tax codes, on centrally assessed advalorem tax rolls. The Utility Shareholders of North Dakota also opposed the proposal relating to the taxation of the generation, distribution, and transmission of electric power.

Regulation of Electric Cooperatives

A representative of the Utility Shareholders of North Dakota testified that as rural electric cooperatives continue to serve more and more customers inside city corporate limits, competing utility organizations serving those cities should be treated the same, with both rural electric cooperatives and shareholder-owned utility companies placed under the same regulatory body. All rural electric cooperatives that provide service within corporate city limits should be under the full jurisdiction of the Public Service Commission because taxpayer money is being used to build urban rural electric cooperative infrastructure and there is no third-party oversight of those cooperatives; taxpaying, shareholder-owned utility companies are ready, willing, and able to take on the burden of providing energy and services to new residents as cities expand and thus there is no need to involve taxpayer investments; lack of Public Service Commission overview gives cooperatives a competitive advantage over shareholder-owned and regulated utility companies; and without Public Service Commission oversight of cooperatives, many city consumers are being served by an unregulated monopoly unfairly competing with a regulated shareholder-owned utility company.

The president of the Public Service Commission testified that the commission's existing jurisdiction over electric cooperatives is limited and the commission does not have the same broad jurisdiction over cooperatives that it has over investor-owned electric utilities. The commission's jurisdiction over electric cooperatives includes safety, siting of energy conversion and transmission facilities, raising and lowering of electric supply lines, and the Territorial Integrity Act. North Dakota Administrative Code (NDAC) Section 69-09-02-35 requires the installation and maintenance of electric supply lines to comply with the national Electric Safety Code, NDCC Chapter49-22 requires anyone constructing electric power plants with 50megawatts or more of generating capacity or electric transmission lines in excess of 115kilovolts to first obtain a permit from the commission, NDAC Section 69-09-02-36 governs the raising and lowering of electric supply lines when necessary for moving buildings or other bulky objects, and the commission is charged with resolving territorial disputes between electric suppliers under NDCC Chapter 49-03. The commission does not have jurisdiction over rates, contracts, services rendered, adequacy, or sufficiency of facilities, or the rules of electric cooperatives. The president of the Public Service Commission testified that the fiscal impact on the commission of regulating electric cooperatives may be significant but could be reduced if provisions in any regulation-enabling legislation assumed the reasonableness of existing electric cooperative rates. However, if the statutory authorization to adopt existing rates was not included in the legislation, implementation would likely require expensive general rate cases to establish initial rates for each cooperative. The Public Service Commission reported that only Wyoming fully regulates electric cooperatives, that rate regulation in Iowa and Minnesota is voluntary, and cooperatives in Kansas may opt out of rate regulation if they have fewer than 15,000members. The states of Iowa, Kansas, Minnesota, Montana, Nebraska, North Dakota, South Dakota, and Wyoming have jurisdiction over territorial issues and all site cooperative facilities, but Montana has no further power to regulate electric cooperatives.

A representative of Missouri River Energy Services testified that the commission regulates investor-owned utilities because there is an inherent conflict between investor-owned utility shareholders and consumers, and regulatory bodies were created to oversee this conflict. No such conflict exists between municipal electric utilities and electric cooperatives and their consumers because they are not-for-profit consumer-owned entities that are self-regulated locally by the people they serve in their localities.

A representative of the North Dakota Association of Rural Electric Cooperatives testified that electric cooperatives are operated on a nonprofit basis for the benefit of their consumer-owners. Locally elected boards of directors adopt policies, set rates, and represent the interests of electric consumers. Because the directors are themselves cooperative members, they are in a unique position to understand the service needs of their neighbors. Because the electric cooperative is not in business to make a profit, the cooperative board sets rates to cover costs and provide operating capital. Any margin of income over expenses is returned to the members in the form of capital credits as the financial status of the cooperative allows. Under the cooperative business model, there is no incentive to set rates higher than absolutely necessary. The representative of the North Dakota Association of Rural Electric Cooperatives contrasted this model with investor-owned utilities which are for-profit businesses that attempt to achieve the best possible stock value and income for their shareholders. Without Public Service Commission rate review, the representative testified that an investor-owned utility with substantial monopoly power could set electric rates to generate excessive profits at the expense of electric ratepayers. Finally, the representative testified that if electric cooperatives were subject to regulation by the Public Service Commission, it would increase their cost of doing business, and the increased cost would have to be passed on to their members which would result in increased electricity rates for those members.

Conclusion

The committee makes no recommendation concerning its study of the impact of competition on the generation, transmission, and distribution of electric energy within this state.

LIGNITE VISION 21 PROGRAM

The committee received updates concerning the Lignite Vision 21 program. The Lignite Vision 21 program is a state and lignite-industry initiative to build one or more 500megawatt lignite-fired power plants in the state. The committee received testimony that this initiative is important because one 500megawatt power plant means threemillion more tons of lignite mined in the state, the creation of 1,300 more jobs, an addition of $140million in business volume, and an additional $6million in tax revenue to the state. To date, the Lignite Vision 21 program has provided over $1million for feasibility studies to address environmental, generation, and transmission issues. A representative of the Lignite Energy Council reported that Phase1 studies were completed on June30, 2000, and Phase2 studies were completed on July1, 2001. Phase3 studies are scheduled to be completed by June30, 2003. The Lignite Vision 21 program has provided up to $10million in grants for detailed feasibility and permitting assistance for each project and provided over $26million of state tax credits for each project. The representative of the Lignite Energy Council reported that a marketplace analysis shows that the Mid-Continent Area Power Pool projects a 5,000 megawatt generation deficit by 2006, 3,000 megawatts of which is in Minnesota alone.

A representative of the Lignite Energy Council reported that the Lignite Vision 21 program has received threeapplications--Great River Energy Company, a consortium composed of Montana-Dakota Utilities Company and Westmoreland Coal Company, and Great Northern Power Development. The committee learned that the Lignite Vision 21 program is facing twocritical challenges in building projects--environmental and transmission. The fourmajor environmental challenges are the prevention of significant deterioration, mercury emissions, visibility issues, and regional haze issues. Although significant, the representative of the Lignite Energy Council reported that the Lignite Vision 21 program can resolve the environmental issues, but transmission export constraints are the primary challenge to developing new lignite-fired electricity generation in North Dakota.

TERRITORIAL INTEGRITY ACT
Background

In conducting its study of the impact of competition on the generation, transmission, and distribution of electric energy within this state, the committee reviewed the history and operation of the Territorial Integrity Act. The Territorial Integrity Act was enacted by the Legislative Assembly in 1965 and is codified as NDCC Sections 49-03-01 through 49-03-01.5.

Although the legislative history of the Territorial Integrity Act is extensive, the rationale for its enactment was summarized in Capital Electric Cooperative Inc. v. Public Service Commission, 534N.W.2d 587 (N.D. 1995). In this case, it was noted that "the Act was adopted at the request of the North Dakota Association of Rural Electric Cooperatives to provide 'territorial protection' for rural electric cooperatives and to prevent public utilities from 'pirating' rural areas," and the "primary purpose of the Act was to minimize conflicts between suppliers of electricity and wasteful duplication of investment in capital-intensive utility facilities." In Capital Electric, the North Dakota Supreme Court established a requirement that a request by a new customer for electric service from a public utility must be made before the Public Service Commission may consider whether to issue a certificate of public convenience and necessity to the utility.

The Territorial Integrity Act basically allowed cooperatives to extend service in rural areas and public utilities to extend service in municipal areas without first obtaining a certificate of public convenience and necessity from the Public Service Commission, the theory being that the delineation of service areas would allow each type of enterprise to expand within its own sphere without conflict with each other. Problems arose, however, as the public utility companies believed that by being confined to municipal areas except as provided in the Act, they were being denied a fair share of the business arising in the rural "growth" areas. This objection to the effect of the Territorial Integrity Act resulted in Montana-Dakota Utilities Co. v. Johanneson, 153N.W.2d 414 (N.D. 1967), which squarely attacked its constitutionality. In Johanneson, the public utility companies took the position the law was an unconstitutional classification for several reasons. They contended cooperatives were given a monopoly in rural areas and were allowed to operate without Public Service Commission regulation, while the public utilities were regulated in every respect by that agency. They claimed that cooperatives could infringe on the existing service areas of public utility companies in rural localities and that new customers could be gained in municipal areas only if there was no interference with cooperative services already provided in the municipality. They also asserted cooperatives had a right to complain against public utilities' actions, but the utilities had no such right against actions of the cooperatives. Thus, they maintained, the Territorial Integrity Act was unfair, arbitrary, and unreasonable, and the Act discriminated against the public utility companies and the public generally.

The North Dakota Supreme Court in Johanneson upheld the constitutionality of the Act in all but one respect. It held that although the Act treated public utilities and cooperatives dissimilarly, the classification was not objectionable as it was based on legally justifiable distinctions. While public utilities were denied the right under the Act to complain of improper actions by cooperatives, the right remained to bring an action in the courts of the state for redress of any injury that might be suffered. Thus, the public utilities did have an adequate remedy and were not prejudiced.

However, the court found otherwise with regard to NDCC Section 49-03-01.2, which conditioned the issuance of certificates of public convenience and necessity on the written consent of the nearest cooperative, or upon a finding a cooperative could not provide the service. Here, the court found that it was "the cooperative, and not the public service commission ... that determines whether a certificate of public convenience and necessity shall be granted to a public utility in the area outside the limits of the municipality" and that "[n]o guidelines are set out in the law to be followed by the cooperative in making such determination, and no safeguards are provided against arbitrary action . . . ." Thus, the court held that when "the Act attempts to delegate, to either the Public Service Commission or the cooperative, powers and functions which determine such policy and which fix the principles which are to control, the Act is unconstitutional." Likewise, the court found that the portion of the Act that permitted supplying of service without certificates if a "consent" agreement was entered by the cooperative and public utility as to service areas also was unconstitutional, as again the cooperative was permitted to determine whether a certificate should be granted.

The impact of Johanneson immediately became evident. Because the provisions of the Territorial Integrity Act allowing for "consent" agreements in lieu of certificates of public convenience and necessity were declared unconstitutional, it was apparent the caseload of the commission and the issuance of certificates would increase substantially. In anticipation of this increase and to reduce the delay caused by the notices and hearings necessary for the issuance of certificates, the Public Service Commission requested an opinion of the Attorney General as to whether conditional certificates could be issued without the usual full-scale hearing and determination. The Attorney General, in an opinion dated October 30, 1967, said that the issuing of conditional certificates without hearing was proper, provided the controversy was fully submitted to the commission by an interested party in such a manner so a decision could be made, and the parties waived the notice and hearing required in the issuance of a certificate of public convenience and necessity. Thus, the issuing of temporary certificates under certain conditions was allowed.

When NDCC Section 49-03-01.2 was declared unconstitutional, the legislative directions to the Public Service Commission were eliminated, and no criteria upon which the commission could make its decisions remained. However, this deficiency was remedied by the court in Application of Otter Tail Power Co., 169N.W.2d 415, 418 (N.D. 1969), in which the court established that in addition to customer preference, factors to be considered in determining whether an application for a certificate of public convenience and necessity should be granted include "the location of the lines of the supplier; the reliability of the service which will be rendered by them; which of the proposed suppliers will be able to serve the area more economically and still earn an adequate return on its investment; and which supplier is best qualified to furnish electric service to the site designated in the application and which also can best develop electric service in the area in which such site is located without wasteful duplication of investment service." Thus, customer preference is not a controlling factor but only one of a number of factors that must be considered for a certificate of public convenience and necessity to be granted.

Previous Studies
1967-68 Study

In 1967 the Legislative Assembly approved House Concurrent Resolution No. "B-2" which requested a two-year study be made of the laws relating to certificates of public convenience and necessity for extensions of service by electric suppliers and the extensions of electric transmission and distribution lines of electric utilities. The resolution directed that a committee composed of three members of the House of Representatives and two members of the Senate meet during the succeeding biennium with two persons representing electric public utilities and two persons representing rural electric cooperatives to study what method, if any, should be provided to resolve territorial disputes between electrical suppliers, whether more lucrative market areas were essential to the efficiency of rural electric cooperatives, and if rural electric cooperatives should be regulated in the same manner as rural telephone cooperatives.

This committee received testimony from the Public Service Commission, rural electric cooperatives, and public utility companies. The public service commissioners were basically of the opinion that the Territorial Integrity Act was beneficial, and they pointed out some areas where improvements could be made. The position of the rural electric cooperatives was that the Territorial Integrity Act was working and that fair and adequate guidelines were being developed by the Public Service Commission in following the interpretation placed on the law by the North Dakota Supreme Court in Johanneson. The cooperatives maintained any change in the law would result in considerable expense to cooperatives and public utility companies alike, as interpretive measures would have to begin anew. The position of the public utility companies was that the Territorial Integrity Act stifled growth and created confusion and uncertainty as the utilities are not allowed to expand with the population move from city and rural areas into the fringe locations around cities. The public utilities maintained that in order to serve their customers economically and to provide a return to their stockholders, they must also continue to grow, and the only area in which growth was possible was in the metropolitan fringe areas. The committee made no recommendation as a result of this study.

1997-98 Study

In conducting its study of the impact of competition on the generation, transmission, and distribution of electric energy within this state, the 1997-98 interim Electric Utilities Committee reviewed the history and operation of the Territorial Integrity Act. The committee received testimony from representatives of the state's investor-owned utilities and the state's rural electric cooperatives.

Representatives of Montana-Dakota Utilities Company testified that the Territorial Integrity Act is unfair in fostering effective electric competition in North Dakota. They argued that it is a barrier to giving customers throughout the state the ability to make economic energy choices and as such should be repealed and fair play rules substituted in its place for all competitors. They testified if rural electric cooperatives wish to pursue loads in urban areas, in competition with public utilities, then rural electric cooperatives engaging in such activity should no longer qualify for favorable financing arrangements with the federal government, exemption from state and federal income taxes, preferential access to low-priced federal power, and potential for debt forgiveness by the Rural Utilities Service, and should be subject to the same regulatory overview as public utilities.

The committee received testimony from a representative of Otter Tail Power Company that the Territorial Integrity Act is not accomplishing what its stated objectives are--to efficiently allocate scarce resources and to minimize disputes between electric suppliers--because the Act leads to a wasteful duplication of electrical facilities and increases, rather than minimizes, the likelihood of disputes between electric suppliers.

Representatives of the state's rural electric cooperatives responded that the Territorial Integrity Act is working well and is serving the purposes for which it was enacted. The committee received testimony that the state's investor-owned utilities have exclusive territories within the state's municipalities the rural electric cooperatives cannot penetrate and that the Act avoids the costly duplication of utility infrastructure. They noted there is substantial undeveloped land within the service territories of the investor-owned utilities while there is an outmigration of population in the rural areas and a corresponding decline in electrical usage. They testified that if it were not for some larger industrial and commercial loads, and some growth around cities in areas that were previously rural, rural electric cooperatives would have experienced a substantial decline in their sales, and it makes no sense to expand investor-owned utility territorial growth at the expense of the rural electric cooperatives that have invested in rural North Dakota. Representatives of the rural electric cooperatives responded to the charge investor-owned utilities are competitively disadvantaged by the Territorial Integrity Act by testifying that since enactment of the Territorial Integrity Act, investor-owned utilities have continued to grow in customers and revenue and have not lost market share to rural electric cooperatives.

Representatives of the rural electric cooperatives also argued that the Territorial Integrity Act is not responsible for rural electric cooperative expansion into urban areas; that rural electric cooperatives can continue to serve their traditional service areas even when these areas become urbanized; and that the growth of the local rural electric cooperative around Fargo is overstated. The committee made no recommendation as a result of this study.

1999-2000 Study

The 56th Legislative Assembly enacted legislation that required the Electric Industry Competition Committee to study statutes relating to the extension of electric lines and facilities and the provision of electric service by public utilities and rural electric cooperatives within and outside the corporate limits of a municipality and to specifically address the criteria used by the Public Service Commission under NDCC Chapter 49-03 in determining whether to grant a public utility a certificate of public convenience and necessity to extend its electric lines and facilities to serve customers outside the corporate limits of a municipality and the circumstances under which a rural electric cooperative may provide electric facilities and service to new customers and existing customers within municipalities being served by a public utility.

The committee received testimony from the Public Service Commission that the 10 issues or factors that the commission considers in Territorial Integrity Act disputes are:

1. From whom does the customer prefer electric service?
2. What electric suppliers are operating in the general area?
3. What electric supply lines exist within a two-mile radius of the location to be served, and when were they constructed?
4. What customers are served by electric suppliers within at least a two-mile radius of the location to be served?
5. What are the differences, if any, between the electric suppliers available to serve the area with respect to reliability of service?
6. Which of the available electric suppliers will be able to serve the location in question more economically and still earn an adequate return on its investment?
7. Which suppliers extended electric service would best serve orderly and economic development of electric service in the general area?
8. Would approval of the application result in wasteful duplication of investment or service?
9. Is it probable that the location in question will be included within the corporate limits of a municipality within the foreseeable future?
10. Will service by either of the electric suppliers in the area unreasonably interfere with the service or system of the other?

Items 1, 9, and 10 were developed by the Public Service Commission while items 2, 3, 4, 5, 6, 7, and 8 are taken from Supreme Court decisions concerning the Territorial Integrity Act. The Public Service Commission reported that it received 483 Territorial Integrity Act applications between 1988 and 2000. Of these, 458 applications were granted, 11 applications were denied, 12 applications were withdrawn, and two were pending. The commission reported that rural electric cooperatives filed 33 objections of which 15applications were granted, 11 applications were denied, and seven applications were withdrawn. There were four applications appealed during this time period and one complaint appealed.

The committee received testimony from representatives of the state's investor-owned utilities that the Territorial Integrity Act and subsequent court interpretations have provided the distribution cooperatives with an opportunity to infringe upon the cities that are served by investor-owned utilities. They testified that over the years this situation has cut off their opportunity to share in the growth of the communities they serve and thus it is not a question of whether a change in the law is necessary but what changes need to take place to ensure the future, long-term viability of all the electric service providers in the state. Representatives of the state's investor-owned utilities testified that rural electric cooperatives currently enjoy virtually all of the growth opportunities in the state.

Representatives of the state's rural electric cooperatives testified that the Territorial Integrity Act is working well, and avoids costly duplication of service. They testified that rural electric cooperatives should be able to participate in the state's growth areas as well as rural areas and that Congress never intended to limit cooperatives to serving only remote farmsteads and pasture wells, but federal and state law encouraged cooperatives to grow with their service areas. They testified that as some cities have expanded into the countryside where only the cooperatives were first willing to serve, the investor-owned utilities want to take away these growth areas at great cost to the consumers who built and own their own cooperative business. Representatives of the Association of Rural Electric Cooperatives argued that investor-owned utilities have had a fourfold increase in electric sales, a rate of growth comparable to the rural electric cooperatives, and the recent slowdown in the investor-owned utilities' growth rate is not because of state law, but because the state has not experienced the economic growth occurring in other states. They also said rural electric cooperatives have suffered more from this lack of growth than have the investor-owned utilities.

The committee received testimony from representatives of Fargo, Bismarck, and Minot concerning the franchising of electricity providers. The committee learned the City of Fargo has entered franchise agreements with two electricity providers--an investor-owned utility and a rural electric cooperative. These franchise agreements are nonexclusive, in that either provider can provide electric service anywhere within the city of Fargo. The committee learned the usual practice is for franchise agreements to be amended to allow the provider to provide service in areas annexed by the city, and if there is a conflict, it is referred to the Public Service Commission for resolution.

Concerning franchise agreements in Bismarck, the committee learned in 1973 Montana-Dakota Utilities Company and Capital Electric Cooperative entered an area services agreement effectively demarcating the area of service by each provider. When Capital Electric Cooperative was granted a franchise by the City of Bismarck to operate within the city, the area service agreement was incorporated into Capital Electric Cooperative's franchise agreement. The committee received testimony from representatives of the City of Bismarck that this system has worked relatively well with only one serious dispute, which was resolved by the Bismarck City Commission without the Public Service Commission becoming involved.

Concerning franchise agreements in Minot, the committee learned the franchise automatically follows into areas annexed by the city, and there has never been a disagreement between Xcel Energy, Inc., and Verendrye Electric Cooperative, the local rural electric cooperative, that has reached the city commission.

Exclusive Electric Service Area Laws of Surrounding States
South Dakota

South Dakota Codified Laws Sections 49-34A-42 through 49-34A-44 and Sections 49-34A-48 through 49-34A-59 govern exclusive electric service areas in that state. Each electric utility has the exclusive right to provide electric service at retail at each location where it served a customer on March 21, 1975, and to each present and future customer in its assigned service area. An electric utility cannot render or extend electric service at retail within the assigned service area of another electric utility without the other electric utility's consent and without approval by the South Dakota Public Utilities Commission. An electric utility can extend its facilities to the assigned service area of another electric utility, however, if the extension is necessary to facilitate the electric utility connecting its facilities or customers within its own assigned service area.

The boundaries of each assigned service area, outside incorporated municipalities, are a line equidistant between the electric lines of adjacent electric utilities as they existed on March 21, 1975, provided that these boundaries may be modified by the South Dakota Public Utilities Commission to take account of natural and other physical barriers that would make service of electric power and energy beyond those barriers economically impracticable and must be modified to take into account existing contracts or to take into account orders entered before July 1, 1975, by the Electric Mediation Board. If a single electric utility provided electric service within a municipality on March 21, 1975, the entire municipality constitutes a part of the assigned service area of that electric utility. If two or more electric utilities provided electric service in a municipality on March21, 1975, the boundaries of the assigned service areas within the incorporated municipality must be assigned pursuant to the equal distance concept as applied to lines located only within the municipal boundaries.

Notwithstanding the establishment of assigned service areas for electric utilities, new customers at new locations that develop after March 21, 1975, located outside municipalities as the boundaries existed on March 21, 1975, and who require electric service with a contracted minimum demand of 2,000 kilowatts or more are not obligated to take electric service from the electric utility having the assigned service area where the customers are located if the South Dakota Public Utilities Commission determines after consideration of the following factors:

1. The electric service requirements of the load to be served.
2. The availability of an adequate power supply.
3. The development or improvement of the electric system of the utility seeking to provide the electric service, including the economic factors relating thereto.
4. The proximity of adequate facilities from which electric service of the type required may be delivered.
5. The preference of the consumer.
6. Any and all pertinent factors affecting the ability of the utility to furnish adequate electric service to fulfill the customer's requirements.

Minnesota

Minnesota Statutes Section 216B.37 provides that the state of Minnesota is divided into geographic service areas within which a specified electric utility is to provide electric service to customers on an exclusive basis. For purposes of the Minnesota exclusive electric service area law, the term "electric utility" includes facilities owned by a municipality or by a cooperative electric association.

Within six months from April 12, 1974, each electric utility was required to file with the Minnesota Public Utilities Commission a map showing all its electric lines outside incorporated municipalities and was required to submit a list of all municipalities in which it provided electric service on April 12, 1974. If two or more electric utilities served a single municipality, the commission could require each utility to file with the commission a map showing its electric lines within the municipality. Within 12 months from April 12, 1974, the commission established the assigned service area or areas of each electric utility and prepared a map to show the boundaries of the assigned service area of each electric utility. To the extent it was not inconsistent with the expressed legislative policy, the boundaries of each assigned service area, outside incorporated municipalities, was a line equidistant between electric lines of adjacent electric utilities as they existed on April 12, 1974.

Except as otherwise provided, each electric utility has the exclusive right to provide electric service at retail to each present and future customer in its assigned service area, and no electric utility may render or extend electric service at retail within the assigned service area of another electric utility unless the electric utility consents, but an electric utility can extend its facilities through the assigned service area of another electric utility if the extension is necessary to facilitate the electric utility connecting its facilities or customers within its own assigned service area. If a municipality owning and operating an electric utility extends its corporate boundaries through annexation or consolidation or determines to extend its service territory within its existing corporate boundaries, the municipality may purchase the facilities of the electric utilities serving the area.

There are two exceptions to the exclusive service right. After April 12, 1974, the exclusion by incorporation, consolidation, or annexation of any part of the assigned service area of an electric utility within the boundaries of a municipality does not impair the rights of the electric utility to continue and extend electric service at retail throughout any part of its assigned service area unless the municipality that owns and operates an electric utility elects to purchase the facilities and property of the electric utility. The other exception is for large customers. Customers located outside municipalities who require electric service with a connected load of 2,000 kilowatts or more are not obligated to take electric service from the electric utility having the assigned service area where the customer is located if the Public Utilities Commission determines after consideration of the following factors:

1. The electric service requirements of the load to be served.
2. The availability of an adequate power supply.
3. The development or improvement of the electric system of the utility seeking to provide the electric service, including the economic factors relating thereto.
4. The proximity of adequate facilities from which electric service of the type required may be delivered.
5. The preference of the customer.
6. Any and all pertinent factors affecting the ability of the utility to furnish adequate electric service to fulfill customers' requirements.

As in South Dakota, Minnesota electric utilities may extend electric lines for electric service to their own utility property and facilities.

Montana

The Montana Territorial Integrity Act is codified at Montana Code Annotated Section 69-5-101 et seq.; however, the provisions of the Act were substantially amended in the Electric Utility Industry Restructuring and Customer Act of 1997 to facilitate the implementation of that Act. Each electric service facilities provider has the right to provide electric service facilities to all premises being served by it or to which any of its facilities are attached on May 2, 1997. An electric utility is an entity other than an electric cooperative which provides electric service facilities to the public, and an electric cooperative is a rural electric cooperative or a foreign corporation admitted under the Montana cooperative statutes to do business in that state.

The electric facilities provider having a line nearest the premises provides electric service facilities to the premises initially requiring service after May 2, 1997, which creates a rebuttable presumption that the nearest line is the least-cost electric service facility to the new customer. A customer or another electric facilities provider may rebut the presumption, and another electric facilities provider may provide the electric service facilities if it can do so at less cost. An electric utility has the right to furnish electric service facilities to any premises if the estimated connected load for full operation at the premises will be 400 kilowatts or larger within two years from the date of initial service and if the electric utility can extend its facilities to the premises at less cost to the electric utility than the electric cooperative cost. The estimated connected load must be determined from the plans and specifications prepared for construction of the premises or, if an estimate is not available, must be determined by agreement of the electric facilities provider and the customer. The fact that the actual connected load after two years from the date of initial service is less than 400 kilowatts does not affect the right of the electric facilities provider initially providing electric service facilities to continue to provide electric service facilities to the premises.

Utilities can enter agreements that identify the geographical area to be exclusively served by each electric facilities provider that is a party to the agreement overriding the provisions of the Territorial Integrity Act. However, all agreements between electric facilities providers must be submitted to and approved by the Montana Public Service Commission. In approving agreements, the Montana Public Service Commission is required to consider the reasonable likelihood that the agreement will not cause a decrease in the reliability of electric service to the existing or future ratepayers of any electric facilities provider party to the agreement and the reasonable likelihood the agreement will eliminate existing or potentially uneconomic duplication of electric service facilities.

Testimony

A representative of the state's investor-owned utilities testified that the urgency for the state's investor-owned utilities to find a reasonable alternative to the Territorial Integrity Act is becoming critical. Representatives of the state's investor-owned utilities testified that under the Territorial Integrity Act, if a customer located outside a city's limits wants service from an investor-owned utility, the investor-owned utility must file an application for a certificate of public convenience and necessity to extend service to that customer. However, inside city limits, the process is different. Rural electric cooperatives have no limitations placed on them in extending service to new customers, but investor-owned utilities, even inside the city limits of a community they presently serve, cannot extend service to a new customer if it interferes with an existing rural electric cooperative's service or duplicates the cooperative's facilities. Representatives of the state's investor-owned utilities testified that no such limitation applies to rural electric cooperatives.

A representative of Montana-Dakota Utilities Company said the current Territorial Integrity Act is stifling the opportunity for investor-owned electric utilities to add new customers. The representative testified that while it is true that Montana-Dakota Utilities Company will show growth in electric revenues of 4percent for 2001, that growth is primarily due to off-system sales into the wholesale market, which although fairly robust for a few years have largely evaporated today--absent off-system sales and the operating efficiencies that Montana-Dakota Utilities Company has implemented, growth of its entire North Dakota electric system has been very minimal, probably in the 1percent range. Representatives of the state's investor-owned utilities testified that in Fargo and Bismarck, the number of new customers they are adding annually is declining, and soon the areas remaining for the investor-owned utilities in those cities to serve will be fully developed and the number of new customers they will be able to add will be zero. Representatives of the state's investor-owned utilities testified that the Territorial Integrity Act continues to be of urgency to the investor-owned electric providers, and it is an issue that needs to be resolved.

Representatives of the North Dakota Association of Rural Electric Cooperatives pointed out that the committee had not received any testimony from a consumer, a city official, or a representative of the Public Service Commission complaining or finding fault with the Territorial Integrity Act or how it has operated. They testified the Territorial Integrity Act works well for both the state's investor-owned utilities and the state's electric cooperatives. They testified the Act places service decisions where they belong, with local city governing bodies. They testified the Territorial Integrity Act creates a level playing field with a balanced approach, avoids duplication of expensive electric infrastructure, and thus there is no need to change the Territorial Integrity Act.

Representatives of the North Dakota Association of Rural Electric Cooperatives advocated that the rural electric cooperative enabling law, NDCC Chapter 10-13, be amended to allow electric cooperatives an unlimited right to serve in urban areas and to make urban customers cooperative members, provided that the cooperative purchases or otherwise acquires electric facilities from another utility on a willing buyer-willing seller basis. Under this proposal, sales by investor-owned utilities to cooperatives would be subject to approval by the Public Service Commission and the local franchising authority just as sales of cooperative property to investor-owned utilities are regulated. Proponents of this proposal said that providing more options for local electric service, rather than fewer, supports the idea that territorial integrity issues should be resolved through negotiation rather than legislation.

The committee received testimony from representatives of the state's investor-owned utilities opposing the willing buyer-willing seller proposal submitted by the North Dakota Association of Rural Electric Cooperatives. They testified that this would allow electric cooperatives to purchase much larger investor-owned or municipally owned utility electric systems than allowed under current law. They testified the proposal would encourage electric cooperatives to entice municipalities to acquire by purchase or eminent domain existing electric utilities from investor-owned utilities and an electric cooperative could subsequently repurchase the facilities from the municipality and thereby effectively remove the investor-owned utility from the community in a manner that could not otherwise be accomplished under current law. They testified that electric cooperatives would also have a substantial advantage in competing with investor-owned utilities for the purchase of other investor-owned or municipal-owned electric utilities because investor-owned utility rates are set based upon the net book value of their investment rate base, and the Public Service Commission generally will not allow an acquisition premium in an investor-owned utility's rate base. Representatives of the state's investor-owned utilities testified that if an investor-owned utility attempted to purchase utility assets, it could not bid more than the book value of those assets because it could not recover any excess in its rates, while a rural electric cooperative could bid two or three times the book value of the assets.

The committee received testimony from representatives of the cities of Fargo, Bismarck, and Minot that the franchise agreements they have with the electricity providers in those cities are working well.

Conclusion

The committee makes no recommendation concerning the Territorial Integrity Act.

WIND ENERGY STUDY
Background

In addition to the committee's study of the impact of competition on the generation, transmission, and distribution of electric energy within this state, the Legislative Council directed the committee to review wind energy as part of its study of electric industry competition and electric suppliers.

The National Wind Coordinating Committee estimates that the United States could meet 10 to 40percent of its electricity demand with wind power. Areas of the United States identified as having significant wind energy potential include areas near the coasts, along ridges of mountain ranges, and in a wide belt that stretches across the Great Plains, including North Dakota. The Great Plains is an especially attractive area for wind energy development because many coastal areas and mountain ridges are unsuitable for wind energy development because of rocky terrain, inaccessibility, environmental protection, or population density. Wind energy can be converted to electricity by using wind turbines. The amount of electricity created depends on the amount of energy contained in wind that passes through a turbine in a unit of time. This energy flow is referred to as wind power density. Wind power density depends on wind speed and air density, with air density being dependent on air temperature, barometric pressure, and altitude. Wind speed, wind shear, and turbine costs determine a site's wind energy potential.

A continued interest in wind energy development in the United States and worldwide has produced steady improvements in technology and performance of wind power plants. In addition to being cost-competitive, wind power projects may offer additional benefits to the economy and the environment. The National Wind Coordinating Committee has indicated that wind energy development carries the economic benefits of job and business creation while supporting local economies and reducing reliance on imported energy. Wind energy may also protect utilities and energy consumers from the economic risks associated with changing fuel prices, new environmental regulations, uncertain load growth, and other cost uncertainties. In addition, the National Wind Coordinating Committee has found the environmental benefits of wind energy development to be substantial by reducing a utility's pollutant emissions, thus easing regulatory pressure and meeting the public's desire for clean power sources. The National Wind Coordinating Committee summarizes the benefits of wind energy as being cost-competitive, creating no air pollution, and benefiting the public health, environment, and the economy. In addition, wind power does not require fuel, create pollution, or consume scarce resources.

Concerning the effect of wind energy development on state and local economies, the National Wind Coordinating Committee has identified several direct economic effects on the economy. Direct effects include increased revenues to local governments and landowners, creation of jobs and demand for local goods and services during construction and operation, and additional property tax revenues to local governments. Secondary or indirect effects identified by the National Wind Coordinating Committee include increased consumer spending power, economic diversification, and use of indigenous resources.

Rural landowners can reap substantial economic rewards from wind energy development. Rent to landowners is paid because land rights for a wind energy project must be secured in advance by purchase or lease. The National Wind Coordinating Committee estimates that rural landowners may receive $50 to $100 per acre from wind energy development projects. In addition, in most cases, farming operations may continue undisturbed. Thus, a landowner is recognizing significant increased income while retaining full use of the land.

Wind power plants generally can be constructed in less than a year. The National Wind Coordinating Committee estimates that for a 50-megawatt wind project, 40 full-time jobs may be created. Operation and maintenance of wind power plants generally require between two and five skilled employees for each 100 turbines. In addition, construction and operation of a wind project creates demand for local goods and services such as construction materials and equipment, maintenance tools, supplies and equipment, and accounting, banking, and legal assistance. These economic benefits are not weakened by heavy demands on state and local infrastructure, and wind projects require little support from public services such as water and sewer systems, transportation networks, and emergency services. Wind energy projects also contribute to economic diversification in a local economy, thus ensuring greater stability by minimizing high and low points of business cycles. The National Wind Coordinating Committee indicates this effect may be particularly important in rural areas that generally have one-dimensional economies.

2001 Wind Energy Legislation

The 57th Legislative Assembly enacted three bills concerning wind energy. House Bill No.1223 allows installations on property leased by a taxpayer to qualify for a long-form income tax credit for installation of a geothermal, solar, or wind energy device. To qualify for the credit, the device must be installed before January1, 2011. For a device installed before January1, 2001, the credit is equal to 5percent per year for three years, or for a device installed after December31, 2000, is equal to 3percent per year for five years, of the actual cost of acquisition and installation of the device.

House Bill No.1221 provides a sales and use tax exemption for production equipment and tangible personal property used in construction of a wind-powered electrical generating facility before January1, 2011, if a facility has an electrical energy generation unit with a nameplate capacity of 100 kilowatts or more.

House Bill No.1222 reduces the taxable valuation of centrally assessed wind turbine electric generators from 10percent of assessed value to 3percent of assessed value if the generation unit has a nameplate generation capacity of 100kilowatts or more and construction is completed before January1, 2011.

Testimony

Testimony indicated there are approximately 23,000 megawatts of installed wind-generating capacity in the world, of which approximately 4,200 megawatts are installed in the United States. Of the 4,200 megawatts installed in the United States, .4 megawatt of installed capacity is located in North Dakota. North Dakota has the greatest wind energy resource in the United States but is near the bottom of the states that utilize their wind energy resource. California and Texas are the twoleading wind-generating states and Texas is on pace to have 2,000 megawatts of installed generating capacity by 2010.

The committee learned that landowners may receive up to $3,000 to $4,000 per year per turbine for the use of their land for generating electricity from wind. In addition, the land may still be used for farming or ranching and thus the landowner realizes the additional income without losing use of that land. The committee learned that twochallenges facing the wind energy industry are the negotiation of power purchase agreements and the lack of transmission capacity.

Testimony indicated that electricity from wind generation blends well into a utility fuel portfolio, aids in fuel risk management, has a short permitting cycle, is a predictable and reliable source of energy, and is clean. Electricity from wind provides economic, environmental, and energy benefits for North Dakota. These economic benefits include tax, tourism, education, and royalty revenues for local communities and landowners; employment opportunities in construction and operation and maintenance of wind generation facilities; and the use of local contractors and suppliers for services required by wind generation facilities and their employees.

The committee reviewed wind energy incentives enacted in other midwestern states. Minnesota provides property and sales tax incentives and has a mandatory green power option. Minnesota has 320megawatts of installed wind generation capacity with 220megawatts planned. Wind energy projects are exempt from property taxation in Wisconsin, and Wisconsin has approximately 50megawatts of installed wind generation capacity. Montana has no installed wind generation capacity but has 285megawatts planned for construction. Montana has income tax incentives and a mandatory green power option. Iowa has enacted income and sales tax exemptions for wind energy projects, and Oklahoma provides a state income tax credit as well as property and sales tax exemptions. Texas has enacted income and sales and use tax benefits for wind power generators.

Wind energy proponents testified that the committee should consider extending North Dakota's property tax incentives to large projects, make the income tax credit transferable, and enact a state production tax credit, a mandatory utility green pricing program, and a nonmandatory renewable portfolio standard.

The committee also reviewed an analysis of the potential economic impact of commercial wind power development in North Dakota prepared for the Griggs/Steele Wind Power Development Group LLC. This study identifies the potential economic impact of commercial wind power development in North Dakota and concludes that wind energy development may offer substantial economic benefits to North Dakota's rural areas as well as to its larger communities. The report indicated that developing a commercial wind farm represents a major construction effort. In addition to providing potential job opportunities for local workers and economic stimulus for businesses in the project area, wind power development represents a major opportunity for firms that manufacture wind turbine towers, blades, and other components and for the state's engineering and construction firms. During a wind farm's operational period, the site area will benefit from the jobs and payroll represented by the operations and maintenance workforce, approximately 10workers for a 100megawatt project, from lease and royalty payments for landowners, approximately $4,000 for a 1.5megawatt tower, and from local purchases of supplies, materials, and services. These expenditures represent an ongoing contribution to local and state economies over the life of the facility. In addition, the report noted that wind power development will result in substantial added state and local tax revenues.

Conclusion

The committee makes no recommendation concerning its review of wind energy.

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