ELECTRIC INDUSTRY COMPETITION COMMITTEE

The Electric Industry Competition Committee was first 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 Section 54-35-18.2 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.

Senate Bill No. 2015 (2003) extended the Electric Industry Competition Committee from August 1, 2003, to August 1, 2007. The bill also expanded membership of the committee from three or four members of the House of Representatives, no more than two of whom may be from the same political party and three or four members of the Senate, no more than two of whom may be from the same political party, to six members of the House of Representatives, four of whom must be from the majority political party and two of whom must be from the minority political party and six members of the Senate, four of whom must be from the majority political party and two of whom must be from the minority political party.

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 assigned to the committee a study directed by House Concurrent Resolution No. 3061 of the feasibility and desirability of enacting legislation to tax electric utility providers with a fair and uniform tax system and a study directed by Section 1 of Senate Bill No. 2310 of issues related to wind energy development in this state.

Committee members were Representatives Matthew M. Klein (Chairman), Arden C. Anderson, Wesley R. Belter, Jim Kasper, George Keiser, and James Kerzman and Senators Duane Mutch, David P. O'Connell, Larry Robinson, Ben Tollefson, Thomas L. Trenbeath, and Herb Urlacher. Representative Bruce Eckre was a member of the committee until his resignation from the Legislative Assembly on October 1, 2003.

The committee submitted this report to the Legislative Council at the biennial meeting of the Council in November 2004. The Council accepted the report for submission to the 59th 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 are promoting electric industry restructuring. Arguments put forward for restructuring or implementing competition in the electric industry include greater customer choice and the possibility that open competition may lower costs, encourage generating efficiency, and allocate capital. However, risks and challenges of retail competition include 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 has also come from large industrial and commercial energy users that are opposed to subsidizing residential electricity users. For example, some industrial users are paying 150 percent of the actual cost of providing energy to those users, while residential customers are 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 for 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:

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 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.

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

The Regulatory Compact

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

In markets exhibiting the characteristics of 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. One critic has stated that rate of return regulation fails to penalize inefficient producers or reward efficient ones.

As an alternative to traditional rate of return regulation, some commentors have advocated and some states have implemented various forms of incentive regulation, including flexible regulation, targeted 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.

Finally, 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 Section 211 wheeling orders, ordering open-access transmission tariffs, and issuing the open-access transmission rule (FERC Order No. 888). Market-based rates are those set by willing buyers and sellers of power. This method may be used instead of the more traditional method of ratesetting by regulators pursuant to administrative hearings, with rates based on the cost of producing power. On April 24, 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. Finally, FERC Order No. 888 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

Twenty-four states and the District of Columbia have either enacted enabling legislation or issued a regulatory order to implement retail access. The local distribution company continues to provide transmission and distribution (delivery of energy) services. Retail access allows customers to choose their own supplier of generation energy services, but each state's retail access schedule varies according to the legislative mandate or regulatory orders. Arizona, Connecticut, Delaware, District of Columbia, Illinois, Maine, Maryland, Massachusetts, Michigan, New Hampshire, New Jersey, New York, Ohio, Oregon, Pennsylvania, Rhode Island, Texas, and Virginia have either enacted enabling legislation or issued a regulatory order to implement retail access. Retail access is either currently available to all or some customers or will soon be available. In Oregon no customers are participating in the state's retail access program but that state's laws allow nonresidential customers access. Alabama, Alaska, Colorado, Florida, Georgia, Hawaii, Idaho, Indiana, Iowa, Kansas, Kentucky, Louisiana, Minnesota, Mississippi, Missouri, Nebraska, North Carolina, North Dakota, South Carolina, South Dakota, Tennessee, Utah, Vermont, Washington, West Virginia, Wisconsin, and Wyoming are not actively pursuing restructuring. In West Virginia the legislature and Governor have not approved the Public Service Commission restructuring plan authorized by state law. The legislature has not passed a resolution resolving the tax issues of the Public Service Commission's plan, and no activity has occurred since early in 2001. Arkansas, Montana, Nevada, New Mexico, and Oklahoma have delayed their restructuring process or implementation of retail access. California has suspended direct retail access.

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 106th Congress; 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 were introduced in the 107th Congress. To date, at least 34 bills relating directly or indirectly with the issue of restructuring the United States electric power industry have been introduced in the 108th Congress.

Territorial Integrity Act

Background

In conducting past studies of the impact of competition on the generation, transmission, and distribution of electric energy within this state, the committee has 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, 534 N.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, 153 N.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 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., 169 N.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.

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 in which 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 to serve their customers economically and to provide a return to their stockholders, the public utilities also must 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 the study.

1997-98 Study

In conducting a 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 fairplay 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 the 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 considered in Territorial Integrity Act disputes were:

• From whom does the customer prefer electric service?
• What electric suppliers are operating in the general area?
• What electric supply lines exist within a two-mile radius of the location to be served, and when were they constructed?
• What customers are served by electric suppliers within at least a two-mile radius of the location to be served?
• What are the differences, if any, between the electric suppliers available to serve the area with respect to reliability of service?
• 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?
• Which suppliers extended electric service would best serve orderly and economic development of electric service in the general area?
• Would approval of the application result in wasteful duplication of investment or service?
• Is it probable that the location in question will be included within the corporate limits of a municipality within the foreseeable future?
• 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 were 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 2 applications were pending. The commission reported that rural electric cooperatives filed 33 objections of which 15 applications were granted, 11 applications were denied, and 7 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 enjoyed 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 had entered franchise agreements with two electricity providers--an investor-owned utility and a rural electric cooperative. These franchise agreements were nonexclusive, in that either provider could 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, which has reached the city commission.

2001-02 Study

In conducting yet another study of the impact of competition on the generation, transmission, and distribution of electric energy within this state, the 2001-02 interim Electric Industry Competition Committee again reviewed the history and operation of the Territorial Integrity Act. The committee received testimony from representatives of the state's investor-owned utilities, the state's rural electric cooperatives, and representatives of the cities of Fargo, Bismarck, and Minot.

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 Territorial Integrity Act was 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 would show growth in electric revenues of 4 percent for 2001, that growth was primarily due to off-system sales into the wholesale market, which although fairly robust for a few years had largely evaporated--absent off-system sales and the operating efficiencies that Montana-Dakota Utilities Company had implemented, growth of its entire North Dakota electric system had been very minimal, probably in the 1 percent range. Representatives of the state's investor-owned utilities testified that in Fargo and Bismarck the number of new customers they were adding annually was declining, and soon the areas remaining for the investor-owned utilities in those cities to serve would be fully developed and the number of new customers they would be able to add would be zero. Representatives of the state's investor-owned utilities testified that the Territorial Integrity Act continued to be of urgency to the investor-owned electric providers, and it was an issue that needed 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 had operated. They testified the Territorial Integrity Act was working well for both the state's investor-owned utilities and the state's electric cooperatives. They testified the Act placed service decisions where they belong, with local city governing bodies. They testified the Territorial Integrity Act created a level playing field with a balanced approach and avoided duplication of expensive electric infrastructure and thus there was 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 acquired 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 were regulated. Proponents of this proposal said that providing more options for local electric service, rather than fewer, supported 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 this would allow electric cooperatives to purchase much larger investor-owned or municipal- 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 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 were set based upon the net book value of their investment rate base, and the Public Service Commission generally would 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 had with the electricity providers in those cities are working well.

Testimony

At the outset of the interim, the committee solicited comments from representatives of the state's investor-owned utilities, the Association of Rural Electric Cooperatives, the Utility Shareholders of North Dakota, and municipal electric utilities concerning the committee's study of the impact of competition on the generation, transmission, and distribution of electric energy in this state to date, the direction the study should take during the 2003-04 interim, the future of the electric energy industry in this state, suggestions for a common electric industry taxation system, and the feasibility and desirability of encouraging electric energy providers to exchange or trade service areas to promote efficiency.

A representative of Montana-Dakota Utilities Company, the utility division of MDU Resources Group, Inc., testified that while interest in deregulating the electric industry has virtually evaporated for the time being, other issues remain. As a result of the committee's deliberations, all generation in the state, regardless of ownership or size, is now taxed on the same basis, legislation was enacted in 2003 granting property tax relief for five years for new high-voltage transmission lines, and legislation was enacted to eliminate the double taxation, or pancaking of taxes, on certain rural electric cooperative transmission lines. The committee received testimony that although all generation is taxed fairly and equally by the coal conversion tax, similar transmission and distribution property is not taxed equally. If transmission and distribution property is owned by an investor-owned utility, the property is subject to centrally assessed property taxes. If the same property is owned by a rural electric cooperative, it would be taxed entirely differently. In addition, the representative of Montana-Dakota Utilities Company noted that income of an investor-owned utility from the sale of electricity is subject to both federal and state corporate income tax and that the equivalent of electric operating income to a rural electric cooperative is not subject to income taxes.

The Montana-Dakota Utilities Company representative testified that that company continues to oppose the Association of Rural Electric Cooperatives proposal put forward during the 2001-02 interim which would have allowed a rural electric cooperative, or consortium of cooperatives, to acquire and operate electric properties owned and operated by an investor-owned electric utility, known as the willing buyer-willing seller proposal. The investor-owned utility representative testified that passage of this proposal without consumer safeguards such as Public Service Commission jurisdiction over rates and amendments to guarantee a level and fair bidding process could allow rural electric cooperatives to force investor-owned utilities out of business.

The Montana-Dakota Utilities Company representative also testified that another area the committee should review is the operation and effect of the Territorial Integrity Act. The committee received testimony that this law is a noose around the necks of the investor-owned utilities in North Dakota which is limiting their opportunity for growth in the state.

A representative of Xcel Energy, Inc., testified that Xcel Energy, Inc., has an intense desire, but little opportunity, to serve new customers at the distribution level. The representative testified that a solution must be found which will allow both rural electric cooperatives and investor-owned utilities to serve new customers. The representative testified that this lack of growth has the potential to create further problems for its customers as they could face potential rate hikes or service issues because of the inability of Xcel Energy, Inc., to grow its business in North Dakota.

A representative of Otter Tail Power Company testified that investor-owned utilities and rural electric cooperatives receive disparate treatment under the Territorial Integrity Act. Investor-owned utilities must apply to the Public Service Commission to serve customers outside city limits but cooperatives do not because it is assumed that this is automatically in the public interest. Another example of the disparate treatment cited by the representative is that while an investor-owned utility does not need a certificate of public convenience and necessity to expand its service within a city where it is already providing service, it cannot expand to an area in the city if the expansion would interfere with the service of an electric cooperative or unreasonably duplicate the cooperative's facilities. The representative testified that in contrast, an electric cooperative can expand anywhere in a rural area. The committee received testimony that the rationale for this different regulatory treatment is that, although a cooperative might duplicate the facilities of an investor-owned utility in areas just outside a city, regulation of such duplication has been deemed unnecessary because the cooperative's management would not unnecessarily invest member money to duplicate the facilities of an investor-owned utility. However, the representative of Otter Tail Power Company testified that that company is familiar with instances in which rural electric cooperatives have extended their facilities into areas regardless of cost and likely return on investment in an apparent attempt to claim an area as a part of their service territory and thereby foreclose future expansion into the area by an investor-owned utility.

Representatives of the North Dakota Association of Rural Electric Cooperatives testified that the Territorial Integrity Act is working well and that there is no need to change the Act.

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.

ELECTRIC INDUSTRY TAXATION STUDY

House Concurrent Resolution No. 3061 directed a study of the feasibility and desirability of enacting legislation to tax electric utility providers with a fair and uniform tax system. The resolution reflected the Legislative Assembly's concern with electric industry taxation and noted that investor-owned electric utilities pay a public utility property tax on their transmission and distribution property while electric cooperatives pay land taxes and replacement property taxes, including a 2 percent gross receipts tax and a high-voltage transmission line tax, that investor-owned electric utilities are subject to state and federal corporate income taxes, and that this system of taxation results in disparities in tax collections among the state and its political subdivisions and creates unfairness in tax burdens among electric utilities.

Electric Industry Entities

The participants in the electric utility industry in North Dakota may be grouped in four categories:

• Rural electric cooperatives - Nonprofit, member-owned corporations engaged in the electric utility business. Rural electric cooperatives may be further divided into distribution cooperatives, of which there are 19 operating in North Dakota, and generation and transmission cooperatives, of which there are seven operating in North Dakota.
• Investor-owned utilities - For-profit corporations owned by their shareholders. Three investor-owned utilities do business in North Dakota.
• Municipal utilities and municipal power agencies - Political subdivisions engaged in distribution of electricity to residents of a city or group of cities. A municipal utility provides services to one city. In North Dakota there are 12 municipal utilities. A municipal power agency is composed of two or more municipal utilities functioning jointly to take advantage of economies of scale. In North Dakota there is one municipal power agency functioning on behalf of six member municipal utilities.
• Power marketers - Entities engaged in purchase and resale of electricity through transmission and distribution infrastructure owned by electric utilities. In North Dakota one power marketer is doing business.

Tax Types Imposed on the Electric Industry

In addition to differences in types of taxes that apply to electric utilities depending upon how they conduct business, different forms of taxation apply to each part of the process of generating and delivering electricity. Separate forms of taxation apply to severance of coal from the earth, generation of electricity or production of other products from coal, generation of electricity from wind, transmission of electricity through large-capacity transmission lines, and distribution of electricity to consumers.

Coal Severance Tax

The coal severance tax was initially imposed in North Dakota in 1975 and has been the subject of numerous rate changes and other adjustments. A substantial change in severance and conversion tax policy was made by passage of Senate Bill No. 2299 (2001). The legislation was intended to assist the North Dakota lignite industry to maintain its competitive position in the market by shifting some tax burden from severance to generation of electricity. The legislation reduced the general coal severance tax rate from 75 cents per ton to 37.5 cents per ton and increased the rate of coal conversion taxes to offset revenue losses to the state and affected political subdivisions. The revenue from the general severance tax is allocated 30 percent to a constitutionally established coal development trust fund and 70 percent to the coal-producing counties based upon coal production in each county. Severance tax revenues received by a county are further allocated 30 percent among cities, 30 percent among school districts, and 40 percent to the county.

In addition to the general severance tax rate, a separate two cents per ton tax is imposed upon severance of coal. The entire revenue from the two cents per ton tax is deposited in the lignite research fund.

Coal Conversion Tax

The coal conversion tax is imposed on the operator of a coal conversion facility, defined to include any coal-fired electric generating unit with a capacity of 10,000 kilowatts or more and any coal gasification facility. The tax is in lieu of property taxes on the facility, but the land on which the facility is located remains subject to local property taxes. The coal conversion tax for an electric generating facility is imposed at a rate of .65 mill times 60 percent of the installed capacity of the facility times the number of hours in the taxable period and an additional tax of .25 mill per kilowatt-hour of electricity produced for sale. For coal gasification plants, the tax is imposed at the greater of 4.1 percent of gross receipts or 13.5 cents per 1,000 cubic feet of synthetic natural gas produced for sale.

Coal conversion tax revenues are allocated 15 percent to the producing county and 85 percent to the state general fund, except the separate tax of .25 mill per kilowatt-hour produced for sale and, through 2009, the first $41,666.67 each month from coal gasification plant tax revenues must be deposited in the state general fund. Coal conversion tax revenues received by a county are allocated 30 percent among cities, 30 percent among school districts, and 40 percent to the county general fund.

Among the changes in Senate Bill No. 2299 (2001) was a change in the tax status of the Heskett generating station in Morton County, which was an issue that arose in earlier discussions of the Electric Industry Competition Committee. Under previous law the Heskett station was excluded from the definition of a coal conversion facility because the production capacity of its two generating units was less than the threshold for application of the coal conversion tax. The 2001 legislation reduced the threshold for inclusion as a coal conversion facility, changing the status of the Heskett station from payment of property taxes to payment of coal conversion taxes. A special provision was added to the coal conversion tax law to incorporate a "hold harmless" provision for Morton County and taxing districts in Morton County to ensure that the county and taxing districts would continue to receive at least as much coal conversion tax revenue as was received from the property taxes for the facility for taxable year 2001.

Property Taxes

Under Article X, Section 4, of the Constitution of North Dakota, property used to furnish or distribute electricity is subject to central assessment by the State Board of Equalization as prescribed by law. Under Article X, Section 5, of the Constitution of North Dakota, the Legislative Assembly may exempt any personal property from taxation and may classify any property other than land as personal property.

Property of investor-owned utilities is subject to property taxes. All operative property is subject to assessment by the State Board of Equalization under NDCC Chapter 57-06. Operative property is defined to include all property reasonably necessary for use by a public utility in operation and conduct of the business engaged in by the company. Property subject to assessment by the State Board of Equalization has its valuation assigned to the taxing district in which the property is located. Assessments of continuous lines of property, such as transmission and distribution lines, are allocated among counties based on the prorated portion of mileage of such lines in each county. The Tax Commissioner certifies to the county auditor of each county the total assessed valuation of centrally assessed property and the amount in each assessment district within the county. Local tax levies are then applied against the valuation in the same manner used for other property subject to local property taxes.

Property of a municipal utility or municipal power agency is exempt from property taxes under Article X, Section 5, of the Constitution of North Dakota.

Property, other than land, owned by a rural electric cooperative and used as operative property or part of a generating facility is exempt from property taxes and is instead subject to gross receipts taxes under NDCC Chapter 57-33, which applies to operative property of rural electric cooperatives, or Chapter 57-33.1, which applies to cooperative electrical generating plants. Taxes imposed under each of these chapters is in lieu of property taxes, except taxes on land (which may not be exempted under Article X, Section 5, of the Constitution of North Dakota). Land owned by a rural electric cooperative is subject to local assessment and payment of property taxes. In addition, Basin Electric Power Cooperative pays locally assessed property taxes on its headquarters land and buildings because the building is not a part of the cooperative's operative property or part of a generating facility.

Wind generation facilities are subject to differing taxes depending on ownership. A wind generation unit owned by a rural electric cooperative is exempted from property taxes but subject to the 2 percent gross receipts tax. A wind generation unit with a nameplate generation capacity of at least 100 kilowatts owned by an investor-owned utility is subject to property taxes but if completed before 2011 receives a reduced taxable valuation under NDCC Section 57-02-27.3 of 3 percent of assessed value (only 30 percent of the usual taxable valuation for centrally assessed property).

Gross Receipts Taxes and Transmission Line Taxes

A 2 percent tax on gross receipts is imposed on rural electric cooperative transmission and distribution cooperatives. A 2 percent gross receipts tax also applies to rural electric cooperative generation cooperatives, but only if a generation facility is not subject to coal conversion taxes under NDCC Chapter 57-60. An additional tax of $225 per mile applies to rural electric cooperative-owned transmission lines of 230 kilovolts or larger under Section 57-33.1-02.

Gross receipts taxes from transmission and distribution cooperatives are allocated among counties in proportion to the miles of line in each county. Tax revenues received by a county are allocated among taxing districts in proportion to the miles of line in each taxing district. Gross receipts taxes from a cooperative electrical generating plant during the first two years of operation go entirely to the county in which the facility is located. After the first two years of operation, taxes from an electrical generating plant are allocated so that the first $50,000 goes to the county, the second $50,000 is split evenly between the county and the state general fund, and all additional revenue is divided 25 percent to the county and 75 percent to the state general fund. Cooperative electrical generating plant gross receipts taxes received by the county are allocated 15 percent to cities, based on population; 40 percent to the county general fund; and 45 percent to school districts, based on average daily attendance. Transmission line taxes under NDCC Section 57-33.1-02 are allocated among counties in proportion to the miles of line in each county and are allocated entirely to the county general fund.

Passage of House Bill No. 1348 (2001) increased the rate of the transmission line tax to $300 per mile for a transmission line of 230 kilovolts or larger initially placed in service on or after October 1, 2002. However, House Bill No. 1348 also created an exemption from this tax for the first year after a new transmission line is placed in service and provided a 75 percent reduction for the second year, 50 percent reduction for the third year, and 25 percent reduction for the fourth year of operation of the transmission line. House Bill No. 1348 also established a distinction between a transmission line and a distribution line. A transmission line is one which operates at a voltage of 41.6 kilovolts or more, and a line operating at lower voltage is a distribution line.

Another significant change made by House Bill No. 1348 was that a new transmission line owned by an investor-owned utility is exempt from property taxes and subject to taxation in the same manner as taxes apply to transmission lines of rural electric cooperatives for lines placed in service on or after October 1, 2002. Such lines of investor-owned utilities are subject to a tax of $300 per mile and are entitled to exemption for the first year of operation and a reduction of 75 percent for the second year, 50 percent for the third year, and 25 percent for the fourth year of operation of the transmission line.

A problem with "pancaking" of gross receipts taxes for certain rural electric cooperatives was described to the Electric Industry Competition Committee in 1997. The compounding of taxes arose because generation and transmission cooperatives pay a 2 percent gross receipts tax on generated electricity and that electricity is again subjected to a 2 percent gross receipts tax at the distribution level. The problem applied to rural electric cooperatives that purchased power through intermediate transmission cooperatives in North Dakota. Transmission cooperatives purchasing power from Basin Electric Power Cooperative and blending it with hydroelectric power purchased from the Western Area Power Administration were subjected to a 2 percent gross receipts tax on revenue from member cooperatives purchasing power. The member cooperatives were subjected to a 2 percent gross receipts tax on resale of power to consumers. In 1999 the Association of Rural Electric Cooperatives announced to the Electric Industry Competition Committee that a change in contractual arrangements had been made to provide that 95 percent of power previously purchased by an intermediate cooperative from Basin Electric would instead be purchased directly from Basin Electric by individual cooperatives. This arrangement allowed 95 percent of power purchased by individual cooperatives to be subjected to only one 2 percent gross receipts tax, thus avoiding most of the impact of the pancaking effect.

Gross receipts taxes do not apply directly to investor-owned utilities, municipal utilities, municipal power agencies, or power marketers but may be embedded in the cost of electricity purchased from a rural electric cooperative.

City Privilege Tax

Under NDCC Section 57-33-04, a city is allowed to impose a privilege tax on the value of electric distribution facilities of a rural electric cooperative furnishing power to city consumers. The tax must be reduced by the amount of gross receipts tax allocated to the city.

Municipal Utility Revenues

A municipal utility is limited by NDCC Section 40-33-12 to a maximum of 20 percent of its annual gross revenues which may be transferred by the municipal utility to the general fund of the city. It appears that Section 40-33-12 would allow a greater amount of gross revenues to be transferred if approved by electors of the city at a regular city election.

Testimony

To facilitate the electric industry taxation study, the committee requested the Association of Rural Electric Cooperatives and investor-owned utilities reprise their electric industry taxation study working group to compile updated taxation information for the committee's use. The electric industry taxation study working group compiled statistics on generation capacity, transmission line miles, electric sales, and taxes.

Concerning statistics relating to the generation of electricity, information compiled by the group shows the state's electric generation--nearly 4,000 megawatts of generation capacity--is fueled largely by coal. Hydropower from the Garrison Dam contributes almost 550 megawatts of generation capacity. There are 80 megawatts of small generation peaking plants and 67 megawatts of potential wind generation. While coal and hydropower generation remain largely unchanged over the past several years, nearly all of the wind generation has been added during the past two years. The wind generation includes two 900-kilowatt turbines, owned and operated by Minnkota Power Cooperative near Valley City and Petersburg; two 1.3-megawatt turbines south of Minot, owned and operated by Basin Electric Power Cooperative, and 62 megawatts of wind generation built in the Edgeley-Kulm area by FPL Energy under long-term purchase contracts to supply wind energy to Basin Electric Power Cooperative and Otter Tail Power Company. Total generation capacity in North Dakota is 4,658 megawatts.

North Dakota's electric utility industry has paid over $73 million in coal conversion taxes over the past five years, with the amount of taxes increasing from approximately $12 million in 1998 to nearly $21 million in 2002. This increase in coal conversion revenue resulted from legislative changes adopted in 2001. The most significant change was an increase in the coal conversion tax formula and the corresponding decrease in coal severance tax formula. In addition, the Legislative Assembly amended the coal conversion tax to make the tax applicable to smaller coal-based plants. Thus, the 86-megawatt Heskett plant in Mandan owned by Montana-Dakota Utilities Company is now subject to the coal conversion tax instead of the public utility property tax.

Concerning the transmission function, representatives of the electric industry reported that the state has over 12,500 miles of transmission lines, including over 5,000 miles owned by rural electric cooperatives, nearly 5,000 miles owned by investor-owned utilities, and more than 2,000 miles of lines owned by the Western Area Power Administration. There has been almost a 3 percent increase in total transmission line miles in the past two years. Rural electric cooperatives pay a $225 per mile tax on high-voltage transmission lines of 230 kilovolts or more. Transmission lines of all sizes owned by investor-owned utilities are subject to centrally assessed ad valorem property taxes. Taxes on transmission lines from 41.6 kilovolts to less than 230 kilovolts owned by rural electric cooperatives are collected under the provisions of the gross receipts tax. Legislation enacted during the 58th Legislative Assembly (2003) grants both investor-owned utilities and rural electric cooperatives a four-year declining property tax exemption for transmission lines rated at 230 kilovolts or larger placed in service after October 1, 2002. Following the four-year declining property tax exemption, the affected transmission line facilities will be taxed at $300 per mile for both rural electric cooperatives and investor-owned utilities. In addition to the high-voltage transmission line tax, cooperatives pay gross receipts tax, in lieu of personal property tax, on electric facilities and on transmission lines smaller than 230 kilovolts. Cooperatives also pay real estate taxes on the unimproved value of their real estate. As a federal agency, the Western Area Power Administration lines are not subject to state taxation. Municipal utilities, which own approximately 10 miles of transmission line in the state, do not pay property taxes on these facilities. The state collects approximately $411,000 in transmission line taxes annually.

Concerning retail sales of electricity, the electric industry taxation study working group reported that for the three-year period from 2000 to 2002, investor-owned utilities had approximately 54 percent of retail sales, cooperatives had approximately 43 percent, and municipal electric utilities accounted for 3 percent of total retail electricity sales in the state.

Rural electric cooperatives pay a gross receipts tax. The gross receipts tax is a tax in lieu of a personal property tax and is a 2 percent tax on all cooperative revenue, excluding the sale of capital assets and revenue attributable to electric generation plants subject to the coal conversion tax. The 58th Legislative Assembly added two additional exemptions. First, revenue from wholesale sales of electric energy to cooperatives subject to paying the gross receipts tax on retail sales on the energy is exempt. This exemption is expected to reduce future gross receipts tax payments by Central Power Electric Cooperative and Upper Missouri Generation and Transmission Cooperative by slightly more than $100,000 each per year. Second, revenue from the sale of wind energy from a North Dakota wind energy facility subject to centrally assessed property taxation is exempt from gross receipts taxation. This puts North Dakota wind energy sales on the same footing as sales from coal conversion facilities. Before enactment of the 2003 legislation to address duplicate gross receipts taxation, member cooperatives of Central Power Electric Cooperative and Upper Missouri Generation and Transmission Cooperative executed contract amendments with their power suppliers to purchase most of their electricity directly from Basin Electric Power Cooperative and not through their intermediate transmission cooperative. This change was implemented in the last quarter of 1999 and accounts for the somewhat lower taxes paid by Central Power Electric Cooperative and Upper Missouri Generation and Transmission in 2000.

A city is authorized by law to impose a privilege tax on the value of rural electric cooperative-owned facilities within the city. When a city imposes a privilege tax, the amount of this tax is reduced by the amount of the gross receipts tax revenue the city receives. During 2002 only the city of New Town imposed this tax.

Investor-owned utilities pay a public utility property tax. This tax is based upon the value of the utility's entire electric system, including real estate, distribution, transmission, and generation that is not subject to the coal conversion tax. In 2001 the Legislative Assembly amended the law to make the coal conversion tax applicable to smaller-based load power plants, including the 86-megawatt Heskett plant owned by Montana-Dakota Utilities Company, which was previously included as part of Montana-Dakota Utilities Company's property subject to the utility property tax.

Concerning state income taxes, as nonprofit cooperative associations, rural electric cooperatives are generally exempt from federal and state income taxation under Section 501(c)(12) of the Internal Revenue Code. However, rural electric cooperatives are subject to income taxes on their electric operations when more than 15 percent of their revenues are derived from nonmember sources. In addition, should a rural electric cooperative engage in a nonelectric utility business, any income derived from the operation is most likely subject to state and federal income taxes as unrelated business income.

The electric industry taxation study working group reported that distribution and generation and transmission cooperatives paid an average of $5,650,330 in gross receipts taxes for the years 1998 through 2002. The working group reported that the state's investor-owned utilities paid an average of $6,134,623 in public utility property taxes for the years 1998 through 2002. The working group reported that the state's distribution cooperatives and generation and transmission cooperatives paid an average of $670,994 in electric utility real estate taxes for the year 2000 and the year 2002. The working group reported that the state's investor-owned utilities paid an average of $2,395,898 in North Dakota corporate income taxes on electric operations for the years 1998 through 2002. The working group reported that the state's municipal power systems paid an average of $1,877,205 in lieu of taxes for the years 1998 through 2002.

The working group reported that North Dakota electric utilities paid an average of $33,721,247 in taxes for the years 2000 through 2002. This includes $16,464,937 in coal conversion taxes, $6,190,235 in public utility property taxes, $670,994 in real estate taxes, $411,435 in transmission line taxes, $5,531,268 in gross receipts taxes, $2,932 in city privilege taxes, $2,430,539 in income taxes, and $2,018,908 in payments in lieu of taxes.

The committee considered a bill draft relating to the taxation of generation, transmission, and distribution of electric power. Representatives of the Association of Rural Electric Cooperatives testified that the proposal was based on three principles--taxes be revenue-neutral; taxes be fair and equitable; and taxes be easy and inexpensive to administer, collect, and distribute. The proposal would have eliminated the public utility property tax on investor-owned utilities, the 2 percent gross receipts and city privilege taxes on rural electric cooperatives, and the high-voltage transmission line tax on rural electric cooperatives. The proposal would have retained the coal conversion tax, wind tax incentives under NDCC Section 57-02-27.3, property taxes on land owned by electric utilities, and city franchise fees on electric utilities. Concerning the generation function of producing electricity, the proposal would have left the current coal conversion tax in place, continued tax incentives for wind generation facilities, and made the conversion tax applicable to noncoal or wind generation plants of five megawatts or more. Concerning the transmission function of electricity generation, the proposal would have taxed all transmission facilities on a line-mile basis based on an increasing tax based on transmission line voltage. The proposal would have taxed transmission facilities of less than 50 kilovolts at $75 per mile, transmission facilities of 50 to 99 kilovolts at $150 per mile, transmission facilities of 100 to 199 kilovolts at $300 per mile, transmission facilities of 200 to 299 kilovolts at $450 per mile, transmission facilities of 300 to 399 kilovolts at $600 per mile, and transmission facilities at 400 kilovolts and above at $900 per mile. Concerning the distribution fund of electricity production, the proposal would have implemented a two-part formula--a flat tax of 52 cents per megawatt-hour of delivered power and .88 percent of revenue collected on the retail sale of kilowatt-hours of electricity. Although a political decision, proponents testified that in the interest of presenting a complete proposal it contained an allocation of tax revenues. Under the proposal, revenue from the transmission line tax would have been allocated to counties and taxing districts based on transmission line miles and rates of tax of each taxing district. Revenue from the megawatt-hour tax would have been allocated to the county in which the retail sale was made and allocated among taxing districts in proportion to their most recent property tax levies in dollars. Revenue from the tax on retail revenue would have been allocated according to the ratio of miles of distribution line in a county compared to the total number of miles of distribution lines the utility had in the state. Revenue would have been allocated among taxing districts in proportion to their most recent property tax levies in dollars.

Proponents testified that the proposal was revenue-neutral with both the current and proposed tax systems raising approximately $11.2 million on transmission and distribution property, was fair to utilities with benefits and burdens shared among rural electric cooperatives and investor-owned utilities and rural electric cooperatives and investor-owned utilities being taxed the same, and was easy to administer as the plan was understandable and easy to apply.

The proposal would have reduced taxes paid by distribution cooperatives by $330,147, increased taxes paid by generation and transmission cooperatives by $249,793, and increased taxes paid by investor-owned utilities by $88,225. All distribution cooperatives except Cass County Electric Cooperative and Mor-Gran-Sou Electric Cooperative would have realized a decrease in tax burden. Under the proposal, taxes would have increased for Basin Electric Power Cooperative, Square Butte Electric Cooperative, and Great River Energy, while decreasing for Minnkota Power Cooperative, Central Power Cooperative, and Upper Missouri Generation and Transmission Cooperative. Under the proposal, taxes would have decreased for Xcel Energy, Inc., and Otter Tail Power Company while Montana-Dakota Utilities Company would have realized an increase of $243,485.

Proponents of the proposal testified there were several good reasons to support the plan. First, the in lieu taxes would have been uniform for all investor-owned utilities and rural electric cooperatives so the proposal met the test of fairness. Second, the proposal would have minimized tax shifting between rural electric cooperatives and investor-owned utilities. Although individual utilities might have paid more or less in taxes, overall the tax shift between investor-owned utilities and rural electric cooperatives would have been only 1.5 percent. Third, the tax formulas would have been easy to calculate and administer. Fourth, the in lieu taxes would have been predictable, which led to the final benefit which would have been that the proposal guaranteed that overall the plan would raise approximately the same amount of revenue for local taxing districts as the current taxation system of ad valorem and gross receipts taxes that would be replaced. In addition, if the electric industry grows, political subdivisions automatically would have seen increased tax revenues in future years.

In addition to the Association of Rural Electric Cooperatives, the proposal was supported by Cass County Electric Cooperative, Basin Electric Power Cooperative, Verendrye Electric Cooperative, Capital Electric Cooperative, Slope Electric Cooperative, and Dakota Valley Electric Cooperative.

Representatives of Montana-Dakota Utilities Company testified in opposition to the bill draft. They testified property taxes should be taxes on the value of property, not an "in lieu of" system that is confusing and contained opportunity for mischief by shifting taxes from one property owner to another. They testified the proposal violated the concept of simplicity and easy understandability and that a tax on transmission lines, but not including substations, appeared to be an effort to achieve a predetermined effect, i.e., a minimalization of tax increases for the large-voltage transmission lines. They testified the proposal would have imposed an administrative burden on investor-owned combination utility companies, such as Montana-Dakota Utilities Company, because it would have subjected their property to two different tax systems--one for electric operations and one for natural gas operations.

The committee considered an amendment to the bill draft which would have limited the transmission line mile tax contained in the proposal to alternating current lines and imposed a separate tax on direct current lines. The tax on direct current lines would have provided that for transmission lines that operate at a nominal operating direct current voltage of less than 300 kilovolts, a tax of $450 would be imposed for taxable year 2006, $500 for taxable year 2007, $550 for taxable year 2008, $600 for taxable year 2009, and $650 for taxable years after 2009 for each mile or fraction of a mile. The amendment also would have imposed a tax for transmission lines that operate at a nominal operating direct current voltage of 300 kilovolts or more of $900 for taxable year 2006, $950 for taxable year 2007, $1,000 for taxable year 2008, $1,050 for taxable year 2009, and $1,100 for taxable years after 2009 for each mile or fraction of a mile. The amendment also would have deleted the requirement that revenue collected on the retail sale of kilowatt-hours of electricity be allocated according to the ratio that the miles of distribution line in a county bears to the total number of distribution lines the utility has in the state and would have required that all revenue be allocated to the county in which the retail sale was made and allocated among taxing districts in proportion to their most recent property tax levies in dollars.

This amendment was opposed by the Association of Rural Electric Cooperatives. Representatives of the association testified that the paramount reason for not setting higher tax rates for direct current transmission lines is that North Dakota has a strong economic interest in encouraging the export of its lignite and wind resources, and direct current transmission lines are one way to export the state's energy resources economically. If the state were to impose too great a tax burden on its high-voltage transmission lines, it would discourage further transmission investment at a time when the state should be doing everything possible to promote energy development for export and that a further increase of these taxes is not warranted, particularly in light of the competitive challenges faced by lignite-fired generation. In addition, a representative of Slope Electric Cooperative testified that no matter where the end sale occurs, transmission lines and other infrastructure must be constructed to serve the load. Thus, the representative testified that it would be unfair to direct all of the revenue to taxing districts where the load is located rather than distributing some of the revenue more broadly throughout the service area of the cooperative.

The committee considered a bill draft that would have eliminated gross receipts taxes for rural electric cooperatives and would have subjected their property to centrally assessed ad valorem property taxes. Proponents of this proposal testified that rural electric cooperative property would be taxed in exactly the same manner in which investor-owned property is taxed. Proponents testified that the central assessment method is a well-developed system for determining value for investor-owned property and an appropriate methodology could be developed to extend this method to rural electric cooperative property, even if some of their original records were lost or unavailable.

A representative of Utility Shareholders of North Dakota testified that a switch in policy that would tax electric cooperatives on an ad valorem basis, the same as shareholder-owned utility companies are taxed, would be a positive move for all consumers, taxpayers, and competitors.

The committee requested that the state supervisor of assessments prepare an analysis of converting Verendrye Electric Cooperative to a centrally assessed property taxation system. The committee learned that it was not possible for Verendrye Electric Cooperative to provide a schedule showing an original cost of its property in each taxing district because cooperatives were not required to collect this information. However, that information is necessary to calculate the tax amount due each taxing district and to compare it with the tax amount each taxing district received from Verendrye Electric Cooperative's gross receipts tax. Because it was not possible to make these calculations, the state supervisor of assessments testified that it was not possible to estimate the tax shift among taxing districts which would occur if Verendrye Electric Cooperative paid centrally assessed property tax instead of gross receipts tax and locally assessed property taxes on its land. Neither could Verendrye Electric Cooperative's total property tax, if it were centrally assessed, be estimated accurately because the Tax Department did not have the required information to multiply individual taxing district mill rates by the taxable value located in each taxing district. However, the state supervisor of assessments testified that preparing a sample assessment for Verendrye Electric Cooperative for 2003 using Verendrye Electric Cooperative's capital structure and returns resulted in an estimated 2003 property tax of $634,569.39, while under current law Verendrye Electric Cooperative paid $363,023.91. Using the investor-owned utility capital structure and rates, the state supervisor of assessments testified that the estimated 2003 property tax for Verendrye Electric Cooperative was $263,042.95, compared to $363,023.91 paid.

Representatives of the Association of Rural Electric Cooperatives testified that in light of the study conducted by the state supervisor of assessments, the ad valorem system would not be easy to administer nor could one predict whether it would be revenue-neutral to political subdivisions. In addition, it would take each cooperative several years of work to assign investment costs properly to political subdivisions. They testified that the system would be subjective, unpredictable, and difficult to administer. They testified that implementing the ad valorem property tax plan would be very burdensome to electric cooperatives, require added staff for the Tax Department to administer the plan, and lead to unpredictable tax impacts on cooperatives and unknown revenue impacts on local taxing districts.

Proponents of the proposal noted that the Tax Commissioner would be able to assign a cost to rural electric cooperative property in instances in which adequate records of original cost were not available. Investor-owned utility representatives also noted that Minnesota, Montana, Wyoming, and Colorado, as well as other states, use an ad valorem property tax system for rural electric cooperatives. As a result, those states have already determined a system value for those generation and transmission cooperatives that own property in those states, a system value that could be used to value cooperative property in North Dakota.

Conclusion

The committee makes no recommendation concerning its study of electric industry taxation.

WIND ENERGY DEVELOPMENT STUDY

Background

Senate Bill No. 2310 (2003) provided that the Legislative Council consider studying, during the 2003-04 interim, issues related to wind energy development in this state, including wind turbine siting requirements, wind energy development contract provisions, the potential economic benefits of wind energy development for farmers and ranchers, the potential adverse impacts of wind energy development on landowners, and the impact of wind energy development on organized labor, especially in the energy industry. The Legislative Council, however, revised this study by directive. At its May 16, 2003, meeting to prioritize resolutions and bills for study, the Legislative Council removed the language relating to wind turbine siting requirements and the impact of wind energy development on organized labor, removed the words "for farmers and ranchers" and "on landowners," and directed that the study include consideration of transmission of electrical energy and the impact on the electric energy industry of wind energy development.

As revised by the Legislative Council, Senate Bill No. 2310 (2003) provided for a study of issues related to wind energy development in this state, including wind energy development contract provisions, the potential economic benefits of wind energy development, the potential adverse impacts of wind energy development, consideration of transmission of electrical energy, and the impact on the electric industry of wind energy development.

The National Wind Coordinating Committee estimates the United States could meet 10 to 40 percent 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.

According to the American Wind Energy Association, installed wind energy generating capacity totals 4,685 megawatts and generated approximately 11.2 billion kilowatts of electricity, less than 1 percent of electricity generation in the United States. By contrast the American Wind Energy Association estimates the total amount of electricity that could potentially be generated from wind in the United States at 10,777 billion kilowatts annually, three times the electricity generated in the United States today. North Dakota ranks first among the top 20 states for wind energy potential, as measured by annual energy potential in billions of kilowatt hours, factoring in environmental and land use exclusions for wind Class 3 and higher. The top 20 states are listed in the following table:

Similarly, the Department of Energy's National Renewable Energy Laboratory has identified North Dakota as having the greatest wind resource of any of the lower 48 states. North Dakota also has few environmental restraints regarding land availability. However, the Division of Community Services, Department of Commerce, has identified a number of issues that must be addressed before significant wind energy development in North Dakota. The single biggest obstacle identified by the Division of Community Services is constraints on the state's existing transmission grid. North Dakota currently exports nearly 60 percent of the power generated within the state, and it is likely that most wind-generated electricity also will be exported. Thus, additions to the current transmission grid will be necessary for a significant generation expansion in the state, regardless of fuel source. Other issues related to the development of wind energy noted by the Division of Community Services include identification of the market for wind energy and possible avian issues related to raptors and nesting waterfowl.

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. For example, an article in the August 24, 2003, edition of the Bismarck Tribune noted that the 41 wind turbines being constructed east of Kulm will each generate $5,000 annually in local tax revenue. The wind farm is located in the Kulm School District, which will receive 60 percent of the tax revenue, approximately $120,000 per year.

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 may recognize significant increased income while retaining use of that landowner's 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 (2001) enacted three bills concerning wind energy. House Bill No. 1223 allowed installations on property leased by the taxpayer to qualify for long-form income tax credit for installation of geothermal, solar, or wind energy devices. To qualify for the credit, the device must be installed before January 1, 2011. For a device installed before January 1, 2001, the credit is equal to 5 percent per year for three years, or for a device installed after December 31, 2000, the credit is equal to 3 percent per year for five years, of the actual cost of acquisition and installation of the device.

House Bill No. 1221 provided a sales and use tax exemption for production equipment and tangible personal property used in construction of a wind-powered electrical generating facility before January 1, 2011, if a facility has an electrical energy generation unit with a nameplate capacity of 100 kilowatts or more.

House Bill No. 1222 reduced the taxable valuation of centrally assessed wind turbine electric generators from 10 percent of assessed value to 3 percent of assessed value if the generation unit has a nameplate generation capacity of 100 kilowatts or more and construction is completed before January 1, 2011.

Testimony

The energy program manager for the Department of Commerce testified that in order to export electricity generated by wind turbines, a solution must be found for the transmission problem. The chairman of the steering committee of Coteau Hills Wind Energy, LLC, testified that the wind turbine farm near Edgeley is approximately 10 square miles--2 miles by 5 miles. There are 41 towers and turbines in the wind farm. The chairman cautioned that the Legislative Assembly should move cautiously and observe the development of the state's wind energy resource before enacting any legislation affecting the wind energy industry. A landowner from Kulm testified that the Legislative Assembly should not micromanage the relationship between wind energy producers and landowners but allow landowners to negotiate with wind energy developers on a one-to-one basis. The legislative and regulatory affairs manager for FPL Energy testified that the wind energy tax incentives enacted in 2001 were instrumental in drawing wind energy developers to North Dakota and without these incentives the $61 million invested in the Edgeley, Kulm, and Ellendale wind farm would have been invested in another state.

The president of Harnessing Dakota Wind testified that the committee should recommend legislation providing that options to lease land for wind energy development terminate five years after the date the option is granted; prohibiting confidentiality provisions in wind energy contracts, options, and leases; establishing decommissioning restoration standards, timelines, and bonding provisions for the removal of wind turbine equipment and the restoration of land used for wind turbines; prohibiting the severance of wind rights from the surface estate; and establishing spacing requirements for wind turbines. The president of Harnessing Dakota Wind also urged the committee to develop and set a wind power objective for the state.

Representatives of the Powering the Plains Project testified on renewable and carbon-neutral energy production efforts in North Dakota and the Upper Midwest. They reported that the Powering the Plains Project has learned that large increases in renewable energy are achievable; encouraging renewable energy and reducing greenhouse gas emissions can drive innovation, job creation, and growth; ownership and scale of renewable energy projects is important; a 30- to 50-year vision with bold and measurable targets and clear policy incentives is critical; comprehensive strategies yield maximum results; and leadership and public support matter more than resources or population base.

The committee reviewed a bill draft relating to a renewable electricity credit trading and tracking system by the Public Service Commission. The bill draft would have allowed the Public Service Commission to establish a program for tradable credits for electricity generated from renewable sources, would have allowed the commission to facilitate the trading of renewable electricity credits between states, and would have applied to all public utilities, including electric cooperatives and municipal electric utilities. One reason for considering the bill draft is that non-Minnesota utilities may only trade renewable electricity credits with firms located in Minnesota if the states in which those utilities operate have enacted legislation similar to Minnesota legislation regarding a program for tradable credits for electricity generated from renewable sources.

Representatives of the Powering the Plains Project testified that a renewable energy credit is a mechanism that allows a utility or nonutility consumer of electric power to purchase a credit from another utility or generator rather than invest in renewable energy generation itself. The buyer of the credit may be subject to regulatory requirements to supply a percentage of electricity from renewable sources to its retail customers, or it may simply wish to voluntarily support the development and use of renewable energy through credit purchases. A credit tracking system records and verifies the creation of renewable credits and their subsequent transaction between parties. A tracking system provides accountability and gives buyers of credits confidence that the credits in question represent real renewable electricity produced and that they have not been double-counted or already sold to another party. The representative of the Powering the Plains Project testified that the legitimacy, both perceived and real, of credits in the marketplace is essential to creation of a robust trading system and will provide an important economic stimulus for development of wind and other forms of renewable energy in North Dakota.

Conclusion

The committee makes no recommendation concerning its study of wind energy development.

LIGNITE VISION 21 PROGRAM

The committee received updates from the president of the Lignite Energy Council throughout the interim concerning the Lignite Vision 21 Program. The objective of the Lignite Vision 21 Program is to build a clean coal generating station in North Dakota. The Lignite Vision 21 Program is important for the state because one 500-megawatt power plant means three million more tons of coal mined; 1,300 more jobs; $140 million in business volume; and $6 million more in tax revenue to the state. The strategy of the state and the Lignite Energy Council contained in the Lignite Vision 21 Program is to lower the risk to developers so lignite is the fuel of choice by lowering overall project costs. The program is designed to help identify problems, find solutions, eliminate government "showstoppers," and prevent government delays in siting and constructing a new power plant in North Dakota. The program is industry-driven and market-based and the bottom line of the program is to activate state help for the benefit of lignite developers. The Industrial Commission has approved $10 million in matching funds for the development phase of each project and $2 million of nonmatching funds for management, feasibility assistance, and marketing efforts. The Industrial Commission has designated the Lignite Energy Council to manage the Lignite Vision 21 Program.

The president of the Lignite Energy Council reported that the Lignite Vision 21 Program has two applicants under contract with the Industrial Commission--MDU/Westmoreland Coal Company and Great Northern Power Development. MDU/Westmoreland Coal Company is examining a site near Gascoyne and Great Northern Power Development is examining a site near South Heart. Both applicants have completed preliminary studies, including environmental, water availability, mine plan, socio-economic, generation technology, transmission, coal quality, site, economic, and market studies. All of these studies were successful. MDU/Westmoreland Coal Company is evaluating the economics of 175-, 250-, and 500-megawatt plants. The Industrial Commission has approved Phase II project funding for Great Northern Power Development and that company submitted its air quality impact modeling protocol to the State Department of Health on August 27, 2003. Great Northern Power Development is now pursuing a power purchase agreement.

The Lignite Vision 21 Program has identified two critical challenges still remaining in building projects in North Dakota--environmental issues and transmission issues. The three primary issues in the environmental area are the prevention of significant deterioration, mercury, and visibility issues.

The president of the Lignite Energy Council testified that concerning the prevention of significant deterioration, the issue is whether there are "modeled" exceedances of air quality standards in Class I areas. The primary Class I area in North Dakota is Theodore Roosevelt National Park. The president of the Lignite Energy Council testified that the actual measurements show no deterioration and the trend in sulfur dioxide emissions is down. North Dakota is one of 16 states in compliance with all ambient air quality standards and North Dakota air is clean and getting cleaner. The State Department of Health has conducted two hearings concerning the prevention of significant deterioration and the State Health Officer determined there are no violations of Class I increments, no deterioration of Class I air quality, and the state's state implementation plan and prevention of significant deterioration program are adequate. From the state and the Lignite Energy Council's perspective, solutions to these problems exist which protect air quality from deterioration, allow existing operations to operate at current levels, and allow Lignite Vision 21 Program Projects to be permitted.

The president of the Lignite Energy Council testified that the other significant problem facing construction of a new coal generating station in North Dakota is transmission. The Lignite Energy Council has been requested by the Congressional Delegation, Governor, and the Industrial Commission to assist with the resolution of North Dakota export constraints for the Lignite Vision 21 Program. The future growth of the lignite industry is largely dependent on the resolution of North Dakota export constraints. Adding new transmission is difficult because of both physical and regulatory constraints and uncertainties that lead to increased financial risk for the development of new transmission. Physical constraints include long transmission distances and the operation of a complex transmission system. Solutions include adding equipment to maximize existing lines, upgra