CHAPTER FIVE: CHANGES AND IMPACTS ON NEBRASKA'S ELECTRIC INDUSTRY STRUCTURE AND OPERATIONS

5.0 Introduction

This chapter examines the impacts of electric industry restructuring and formation of competitive markets on existing utility structure and operations in Nebraska. It outlines the key issues and options related to structure and operations. It provides an assessment of the types of changes that would be required in Nebraska for variations in the industry structure and operations. A determining factor for any of these options will be whether Nebraska systems work together to schieve efficiencies in generation, transmission, or distribution; or market pressures and a philosophy of independence induces them to choose alliances and other business relationships to an extent that competitive tensions between the systems increase. The chapter closes with a description of Advisory Group positions on key issues and options and recommendations of the Task Force.

Changes In Nebraska's Electric Industry

As noted in earlier chapters, Nebraska's electric industry is based on non-profit operation using principles of cost-of-service and non-discrimination subject to the control of local boards. As the largest electric systems in the state, Nebraska Public Power System, Omaha Public Power District, and Lincoln Electric System own most of the state's and generation facilities. The vast majority of Nebraska's 163 systems that serve at retail are distribution-only systems. These distribution systems have carried out competition for wholesale power supply for more than 30 years. In essence, they have already engaged in competitive power supply for their consumers aggregated by municipalities, public power districts and rural electric cooperatives.

It is inevitable that there will be some change in the Nebraska electric industry in response to evolution of technology and public and economic policies. The extent and timing of change will depend upon the benefits perceived.

Expansion of competition in the wholesale market can be accomodated within the existing structure with minor changes in law. Modification of the Current Structure and operations of the distribution systems could occur to address pressures of retail competition and meet the demands of changing markets and technology. However, a transition to a competitive retail market could have far reaching effects. The three major systems (NPPD, OPPD and LES) as well as other smaller generation-owning systems that participate in retail competition are likely to be required to separate the functions of transmission, generation and distribution. The systems that provide distribution services only could be left to function as "wires" companies, or competing multi-service providers and providers of default electric service at spot market prices. As competition for customers proceeded, the cooperation and non-profit basis on which the systems currently operate would be altered. New distribution level functions would be needed for aggregation, advertising, accounting, scheduling, and contracting. And as noted earlier, a statewide regulatory system would be needed to oversee the market. In brief, a transition to retail competition would require changes in principles, operations, structure, local control, and costs to consumers.

Proponents of retail competition in other states reason that a transition will bring savings, economic growth, innovation in technology and multi-service packages to consumers. Other proponents focused more narrowly reason that "privatization" of the industry. divestiture of consumer-owned facilities. would deliver greater benefits than non-profit consumer-owned systems.

This chapter addresses a broad range of restructuring and competition issues related to structure and operations, and takes up divestiture of generating plants and distribution systems as one of the possible elements of restructuring. Other studies could focus on divestiture alone, however, this report addresses it only as one option in the general context of restructuring and competition.

Given the relative efficiency and low cost of the Nebraska consumer-owned electric systems, benefits of any change need to be assured to justify a transition from the existing industry structure.

Chapters One and Two noted federal, regional, and in-state pressures to establish retail competition. Chapters Two and Three noted the preconditions necessary to support retail competition. These preconditions include having a functional ISO and market hub in place, comparable wholesale pricing at the regional level, a statewide regulatory body, and rules and standards to protect consumers and prevent market power abuse.

Chapter Four described the existing structure of the industry and outlined three basic options for Nebraska. The first option is modification of the Current Structure. The second is establishment of Limited Access for a qualified group of customers to participate in retail competition. The third is Open Access for all customers to participate in retail competition.

The challenge facing Nebraska is how to address competitive pressures and preserve its low costs. The course of action to be determined at the state and local levels need to be assessed based on key issues and criteria.

Key Issues and Criteria for Evaluating Options

The overriding issues facing Nebraska electric systems in terms of structure and operations are: 1) how best to accommodate expanded competition at the wholesale level (generation and power supply) to benefit Nebraska consumers; 2) how best to participate in new regional transmission organizations; 3) whether a transition to retail competition at the distribution level would produce greater efficiencies, more reliable service, reduced costs, and adequate protection for consumers; or minimal changes in the existing structure will achieve the same or greater benefits.

At the wholesale market level, options must be considered for their ability to retain the benefits of the state's low cost power supply resources, and at the same time address the expansion of a competitive wholesale power market in the region.

At the transmission level, options must be assessed for capability to provide low cost access for all Nebraska systems.

At the retail distribution level, options for the Current Structure, Limited Access Structure, or Open Access Structure require a detailed examination and evaluation in terms of both economic and non-economic criteria. Economic criteria include the costs and benefits of any given model as noted in Table 5-1. These would incorporate anticipated reductions in wholesale power costs that might offset start-up costs, transition costs, and on-going operational and transaction costs of a new competitive system.

Table 5-1

Non-economic criteria include issues that may translate into economic results over time, ower prices, system reliability, the relative need for consumer protection/education, environmental protection, workforce training and safety, and multi-service delivery.

Table 5-2

Each of these issues needs to be placed in context to have meaning for decision-makers. This requires a step-by-step analysis beginning with the preconditions for competition: wholesale supply and prices, wholesale market hubs or transaction centers, non-discriminatory access through ISOs and transmission organizations, and a regulatory structure to provide adequate market rules and consumer protection and education.

Wholesale Power Supply Market

The wholesale power supply market for Nebraska electric systems consists of contracts made with in-state power suppliers, such as NPPD and OPPD, or with regional power suppliers such as Tri-State Generation and Transmission Association. As noted earlier, expansion of this market may be accommodated within the existing structure, although changes in the market could require changes in policies, practices, and structure of generation and transmission of Nebraska systems.

There have been a number of recent reports that included assumptions on wholesale prices. During 1997 and 1998, three national reports on retail electricity competition offered projected electricity prices resulting from industry restructuring. These were followed by a fourth unreleased report in 1999. The results were conflicting. Two of the reports showed price reductions in Nebraska due to wholesale and retail competition and two showed price increases.

The two reports indicating retail price reductions for Nebraska were issued by the U.S. Energy Information Administration (August 1997 and update July 1998) and the U.S. Department of Energy (March 1998).

The two reports that indicated retail price increases for Nebraska were developed by the Science Applications International Corporation (July 1998) and the USDA Office of the Chief Economist (unreleased).

On balance, the report of the Science Applications International Corporation (SAIC) is viewed as the most pragmatic and realistic vision of the changes now taking place in the industry and its impact on retail electricity prices. The DOE and EIA reports indicating savings tend toward a more theoretical and academic vision of perfect competition as it might be applied to the electric power industry and do not adequately address some of the inherent real-world difficulties associated with retail competition.

The SAIC report indicates that with open retail access, prices in Nebraska will increase.(See Chapter 8 for more discussion on the SAIC report.) The USDA report reaches similar conclusions to the SAIC report that Nebraska would experience price increases under retail competition. The USDA analysis utilizes the same computer model as the earlier DOE study, but with differing market assumptions and conflicting results which have stirred controversy.

The five key findings of the USDA analysis were:

1. In contrast to the DOE analysis that showed savings in every state, the USDA analysis presented a state-by-state examination that showed 19 states (including Nebraska) would experience higher electric rates.

2. Rural electric cooperatives may experience financial stress which may carry risk to US taxpayers, should they not be able to repay loans on schedule.

3. A much larger rural safety net would be needed to insulate certain regions of the US from the harm of retail competition. That rural safety net would require funding of $1 billion in the year 2000 and up to $2.4 billion by the year 2015.

4. Even higher electric prices would result if Federal Power Marketing Administrations (PMAs) were opened to competitive pricing. The briefing report says that in the case of the Western Area Power Administration (WAPA), electric prices in Nebraska would rise between 4.1 percent to 4.4 percent.

5. Finally, the USDA analysis predicted that overall economic growth would slow in those states that experience increases in electric utility rates under retail competition. Nebraska's economic growth rate was predicted to be damaged by as much as 1.5 percent.

Given the variations in these four national reports, a study was undertaken by the Nebraska Power Association. While the national studies included fixed distribution and transmission costs, the Nebraska price study focused specifically on wholesale power supply prices, the key element of competition.

This study shows Nebraska's current wholesale power supply costs are below those of the MAPP region and the national average as previously described in Chapter 3. Chart 5.1 indicates that Nebraska's wholesale power and energy costs are likely to stay below those of the regional market through 2010 under current contract and conditions in the state.

CHART 5-1 WHOLESALE POWER PRICE PROJECTIONS

The estimated prices begin at 2.77 cents per kilowatt hour for Nebraska and 3.11 cents per kilowatt hour for the region in 1999 and extend to a range of 2.62 (low cost assumptions) to 3.83 cents (high cost assumptions) for Nebraska in 2010; and 2.94 (low cost assumptions) to 4.30 cents (high cost assumptions) for the region in 2010. It is generally assumed that the same low and high cost assumptions can be applied to the state and the region.

Nebraska's wholesale power cost advantage is the result of a combination of factors: 1)proximity to low-sulfur coal mines in Wyoming; 2) preference power and energy from the Western Area Power Administration (WAPA); 3) use of tax exempt bonds to finance consumer-owned power plants, and 4) lower operating costs for generating plants.

While it is difficult to predict what Nebraska electric prices or those of the region will be in the future, Nebraska should be in a favorable position and generally below the surrounding market based on in-state power plant production costs and purchased power costs.

5.3.1 Power Plant Production Cost

Power Plant Production Cost includes two components: (1) Fuel cost and (2) the Operating (less fuel) and Maintenance expenses. Fuel costs generally make up two-thirds of production costs. Table 5-3 shows that Nebraska plants generally compare favorably with plants in both the MAPP region and the nation as a whole. Proximity to coal fields contributes to the state's lower production costs. Nebraska. s higher nuclear plant costs are due in part to the design of two single unit plants rather than multiple unit plants operating in other states.

Table 5-3

Source: L.R. 455 Phase I

5.3.2 Purchased Power Costs and Wholesale Rates

Purchased power costs and wholesale rates reflect the cost of power for Nebraska distribution systems acquired from generating agencies located primarily in Nebraska. Western Area Power Administration (WAPA) is also a partial requirements wholesaler to a number of Nebraska utilities.

At the wholesale level, two 1995 surveys indicated that Nebraska wholesale firm rates compared favorably with regional and national data. The first (shown in Table ) was a National Rural Utilities Cooperative Finance Corporation (CFC) survey and updates involving only rural systems purchasing at wholesale which revealed Nebraska 14 percent below regional wholesale rates and 19 current below national. The second (shown in Table 5-5) was an Edison Electric Institute (EEI) comparison for investor-owned utilities for resale. The Nebraska average for 1995 was 21 percent below the January national cost and 11 percent below the July national cost.

Table 5-4

Table 5-5

All consumer-owned systems in the state receive wholesale power at the same relative low price. Rate differentials for retail consumers are the result of local conditions, distribution system load factors, and operating costs that are fixed and would not necessarily be subject to change with competition. Most local distribution systems currently have long term supply contracts with NPPD, or OPPD, MEAN, or Tri-State. Pricing in these contracts would need to be altered, or other events would need to occur to offset the low cost wholesale supply.

Prices in the region and in Nebraska could be affected by a number of events. WAPA power could undergo price increased due to federal decisions. Environmental requirements could raise operational costs at Nebraska coal-fired generating stations, as could increases in coal prices. Loss of tax-exempt financing would affect the cost of new transmission and generating plant construction. Divestiture of generating plants, or construction of new plants by merchant generators could also have an effect on wholesale pricing. And export of substantial amounts of Nebraska's low cost power into higher-priced out of state markets could create upward pressure on wholesale prices in the state. While individually these events are not likely to erode all of Nebraska's wholesale price advantage, combinations of events over time could push wholesale prices toward regional market levels. Detailed pricing studies undertaken in other low-cost states have resulted in similar findings that market pressures and export of power could result in substantial price increases for those states.

5.3.3 Retaining Nebraska's Low-Cost Wholesale Power

There are methods with which Nebraska systems may continue to participate in the regional power market, accommodate and prepare for wholesale market expansion, and retain low cost power supply. The simplest method would be to assure provisions are included in long term power supply contracts between Nebraska distribution and Nebraska generating entities. These provisions could assure that Nebraska's low-cost generation would be reserved for Nebraska customers first, and only surpluses (short or long term) would be sold outside Nebraska.

More complex administrative or structural methods to retain low cost power supply could also be undertaken in a manner that provides adequate compensation to generation owners and price security for Nebraska wholesale purchasers. Both of the methods discussed below could be used with or without a competitive retail market. Each requires more comprehensive examination.

5.3.3.1 Nebraska Power Transaction Center

One concept to allow flexible participation in the regional market and offer Nebraska's low cost generation for use by Nebraska's customers is establishment of a Nebraska Power Transaction Center (NPTC). As noted in Chapter 4, this is an administrative facility similar to the Open Access Scheduling and Information System (OASIS) electronic bulletin board required by FERC's Open Transmission Order 889. The MAPP region has an OASIS operating which allows wholesale electric organizations that subscribe to this Internet-based service the ability to monitor all transmission reservations and prices. This is a real time system with minute-to-minute updates.

The NPTC would enhance the ability to purchase and sell at cost plus an administrative fee Nebraska public power resources by establishing a bidding forum among Nebraska buyers and sellers. The purpose would be to ensure that the primary benefits of public power resources that are not already committed can be made available to other Nebraska utilities to keep wholesale rates in Nebraska as low as possible. The NPTC would require some commitment on the part of Nebraska generating entities and purchasing entities. Sellers would need to adhere to a cooperative approach and not "bid-up" pricing. Buyers would need to be restricted from purchasing at cost-based pricing and re-selling out-of-state for a profit.

The NPTC basic parameters could include the following:

• All Nebraska systems would be required to offer through the Center their surpluses, both short and long term.
• Nebraska systems could sell through markets other than the Center only after no offers have been accepted by other Nebraska consumer-owned systems.
• Nebraska systems are required to purchase from the Center when the price quoted to the Center is less than the alternative including transmission and other fees.
• The price for offers through the Center would be cost plus an administrative fee.
• Appropriate timing would have to be established so that surpluses could be offered and sold out-of-state if there were no Nebraska acceptances of offers through the Center.
• Purchases from the Center could not be resold at wholesale by the purchaser to others without a reoffer through the Center.

The Transaction Center would require either contractual agreements, state policy guidelines and rules, or both, that would be consistent with federal and state law. While commitments from the Nebraska systems would be necessary, the Transaction Center would also require flexibility to evolve with the market system. This option could provide security for wholesale pricing in the state, but it may lack the market presence that might be provided by a statewide Generation Cooperative.

5.3.3.2 Nebraska Generation Cooperative

Another concept to retain Nebraska's low cost generation for use by Nebraska customers is the formation of Nebraska Generation Cooperative Company (NGCC). As noted in Chapter 4, this structural approach could be more advantageous than the administrative Transaction Center, or could be created in addition to, or as an alternative to the Transaction Center.

This concept would also serve to identify the equity holders of the Nebraska facilities as well as their share of the ownership since the cooperative concept issues capital credits based on use of the cooperative. Therefore, this concept has the ability to retain consumer ownership in an open access retail competition environment. A cooperative could become involved in products and services that a public power district and possibly a municipality cannot. Also a large consolidated organization could provide the consumer-owned systems with a greater competitive presence to balance that of large holding companies. The NGCC could also provide more options to stay competitive in an open retail access market, or to address competitive pressures in a Modified Current Structure.

The NGCC could operate with central dispatch similar to a closed or tight power pool from which all wholesale and retail distribution entities in Nebraska could purchase power on an equitable basis. In one form, a comprehensive NGCC could include future generation and assignment of existing generation with proper credits for generation owners and accommodation for current out-of-state sales to avoid negative rate impacts. Such assignments of existing generation could also be phased in over time.

A more limited form of NGCC, or an initial phase, would include only joint development and ownership of new generating resources.

Basic parameters of the NGCC could include the following:

• All Nebraska-owned generation (except distributed generation) could be included as assignment or sale.
• Recapitalization of existing generation would be done only if advantageous.
• Changes in ownership, operation, and financing would occur as appropriate.
• Existing contracts for sale of power and energy at wholesale or other bulk arrangements could remain in place and change potentially only when some form of divestiture or ownership change is requested (such as functional separation).
• Existing purchase agreements by Nebraska utilities could be included.
• Existing wholesale and retail agencies would purchase requirements from the cooperative.
• Determination would have to be made as to whether future generation or purchase additions become a part of the cooperative.

While providing the potential for greater market presence, the NGCC would also require commitment from the Nebraska systems. This commitment may be less than a commitment to the Transaction Center if only future generation is developed and owned jointly, and greater if all resources were assigned to the NGCC. That commitment could expand based upon achievement of specific milestones and judgements concerning regional market prices and conditions.

The Task Force recommends that a working group be designated to examine options to retain low wholesale power costs including initial study of a Nebraska Power Transaction Center, and a full study of the formation of a Nebraska Generating Cooperative Company.

Competitive Power Supply Alternatives that Will Affect Wholesale Prices

As noted in Chapter Two, the existing wholesale power supply markets are undergoing rapid expansion with many new players and new products being offered. As a "commodity" rather than a "service" electricity is being offered as a "financial product" with many components and risk levels, rather than energy and capacity subject to physical delivery. Brokers and traders with backgrounds in finance and other energy commodities such as oil and gas have entered the field along with new power suppliers affiliated with electric or other energy companies. The general view is that electricity may be traded ten times, like other commodities, before reaching the consumer. This has created a market that is more complex, more volatile, and more demanding for those purchasing or selling wholesale power. The general experience has been an upward pressure in wholesale prices in regions that have instituted retail competition.

Within the MAPP region, it is assumed that some type of regional market hub will form to conduct the bulk of wholesale transactions. This hub and the type of market that evolves will affect wholesale pricing in Nebraska through the practices, policies, pricing patterns and expectations that evolve.

There are two alternatives being utilized in other states under competitive environments, both possible in the MAPP region. One is a "bilateral contract" arrangement in which the buyer and seller agree upon contract terms that remain undisclosed (potentially a serious barrier to viable competitive markets). The second is a Power Exchange (PX) that utilizes public bidding and posting of prices.

5.3.4.1 Bilateral Contract Arrangements

Under the bilateral contract model, wholesale and retail customers have access to competitive generation via individual or collectively negotiated contracts with generators or suppliers of their choosing. A customer or its aggregator or competitive power supplier may choose to purchase all needs via a longer-term contract with a fixed price. Another customer may decide to utilize the bilateral spot market and purchase all generation one hour at a time, or a combination of approaches could be used. The price for contracts, the terms, and conditions are market-based with performance disputes settled pursuant to the contract terms.

Certification of aggregators and competitive power suppliers would provide some customer protection related to the ability of the marketer to perform both financially (bonding) and in day-to-day operations (providing around-the-clock response to emergency situations).

Bilateral contracts do not result in any single market clearing price, as does a Power Exchange (described below). Instead, all trades are individual between customers, generators, and a variety of market facilitators (such as retail aggregators, electric service companies, brokers, or retail power marketers). A variation of this arrangement is a single competitive power supplier rate for each class of service and all customers are offered the same rate. But that is not a requirement in states where bilateral contract choice has been implemented.

Because bulk power market prices are essentially deregulated in the bilateral contract environment, buying and selling prices are not necessarily "posted" or known, except by the parties involved. Prices are confidential. Generation power suppliers and interested customers will have to shop and discover price, as they do in other unregulated markets, through advertising, market information, and comparison shopping. There could be a state requirement that all prices of bilateral contracts be posted on an electronic bulletin board. FERC mandates such a posting of transmission service pricing.

Each major Nebraska utility with generation has a centralized economic dispatch system that has been successful in optimizing generation costs. However, it does not necessarily accommodate competition because only one or a few sellers are controlling production and dispatch, and there are no buyer-side signals allowing consumer analysis. Under a bilateral contract model, the market decides which generators operate, based upon specific contracts with specific buyers. The bilateral contract model promotes no need for an "industry-wide overall" centralized dispatch because the market provides incentives for each power supplier/aggregator to acquire the lowest cost product for its customers. This will force them to run or acquire the low cost generation units.

Although market pricing could replace economic dispatch on an industry-wide basis, Nebraska generation utilities with multiple units will likely continue to use existing economic dispatch methodologies and automatic generation control to optimize their systems for native load requirements. In order to provide the lowest cost power to the open market, a multiple generation facility operator will dispatch units much like today, and the optimum mix of power will set the price they offer to the bilateral market.

Nebraska generators would, through their power supply marketing efforts, need to compete to retain current customers in existing service areas or attract customers outside their generation service areas. In theory, they would face competition from other Nebraska generation suppliers and out-of-state power marketers, generation utilities, and independent power producers.

In addition to new pressures for Nebraska generators, bilateral contracts would create new functions or roles. Two roles of primary importance are Power Supply/Scheduling Coordinators (S/C) and the aggregator or Competitive Power Supplier (CPS). Both of these functions essentially are interfaces between the seller (generators) and the buyer (customers).

In a general assessment of bilateral contracts, the Task Force has noted that this type of market arrangement can create problems for a viable market because it relies upon private terms and pricing. It is does not let competitive forces work, is vulnerable to preferential treatment for selected contract partners, and offers potential for market abuses. The existing standard offer form of contract between wholesal suppliers and distributors are not like the bilateral contracts discussed in this section and are recommended to continue as noted in section 5.3.3.

5.3.4.2 Power Exchange (PX) Concept

Another open access approach for generation is the Power Exchange (PX) or Poolco model. Under this approach, all generation resources (within a defined region) are dispatched on an hourly basis. There are some power pooling agreements that exist today in certain regions of the U.S. (California, Pennsylvania, New Jersey, and New York) that are utilizing this function in conjunction with ISO operations.

Under the Power Exchange, all generation in the Nebraska market could be centrally dispatched on an hourly basis. Generation is dispatched based upon a "bid" price submitted by the generator owner. Bids received by the PX are ranked by bid price. The lowest price generators are selected until the level of generation matches the scheduled or projected load for each hour. The last generator selected to meet total load, which is the most expensive of the units selected, sets the price to be paid to all other selected generators. This also sets the Market Clearing Price (MCP) for the power exchange area or grid. Generators selected to run will make a contribution toward fixed costs if their bid price covers their actual operating cost by the amount MCP is higher than their bid price. Those units with bid prices greater than MCP will not run. Thus units will compete to run based upon market signals and conditions rather than by only production costs of the units themselves.

All transactions are between buyers and the PX. If the market were to allow wholesale competition only, the buyers would be the distribution companies who then resell at retail. If Nebraska allows retail choice, the buyers may be power marketers, aggregators, individual large customers, electric service companies and local distribution companies acting as aggregators.

For certain units like nuclear or "must run" hydro, they may submit hourly bid prices well below actual operating costs ($0.00 per MWh) to ensure they are selected to run. They will, of course, receive the MCP for power, not their bid price. During light load periods, the MCP will be fairly low, perhaps lower than variable cost of large base load units that don. t cycle or shut down. During high load periods, the MCP will be fairly high and bid prices for the units will be recovering lost revenues from light load periods and substantial portions of fixed costs.

In the above example, the system scheduled demand (load) calls for 1750 MW of generation to serve the load. The market clearing price is the bid price of the last unit bid selected or the Combined Cycle 1 (C/1) unit at 250 MW and $31/MWh. All units with bid prices less then $31/MWh would be selected to run and also receive the market clearing price or $31/MWh. This process would repeat the same hourly bid pricing mechanism for all hours of the year. The hourly MCP is set by the point where the sum of firm schedules intersects the merit order of the bid stack. The market would usually be conducted via day ahead bidding in part to allow ample time to generators to be assured of next day run status. The above example is a very simplistic representation of the PX concept. In practice, it would be much more complex, reflecting "must run" units for reliability/voltage support, transmission congestion pricing, risk minimization pricing schemes, possibly an ancillary services market, detailed financial settlement, and administrative processes, etc.

The PX concept may be characterized as a short-term or spot market approach which, although limited, can serve an important competitive function. Critics argue that while a PX can serve a spot market role, the only way to get true competition is to allow buyers and sellers to interact with each other. Some customers may use bilateral arrangements for long-term price stability and others may wish to buy power on the bilateral spot market and assume the risk of price fluctuations and hedge risk instruments or cross energy products (eg. gas contracts) with financial.

A characteristic of a PX is volatility in prices. The PX price is the method to signal generators that more or less power is needed and to the buyers that power is scarce or abundant. The PX market offers no guarantee of a long-term price stability or supply for electricity, which is a dramatic departure from today's practices. Most buyers prefer some stability with regard to prices and supplies.

The posting of spot market prices does provide a theoretical basis for the formulation of long-term contracts, however. These arrangements, known as Contract For Differences (CFD), guarantee a price and quantity between a buyer and seller. With CFD, the seller (a financial risk taker) agrees to sell to the buyer a specified schedule of power at a pre specified price over whatever time the two agree to . months or years. The buyer continues to purchase its needs through the PX, including the amount contracted for in the CFD. The CFD seller computes the difference between the price the seller has guaranteed the buyer and the price the buyer paid to the PX and pays the buyer the difference (if positive) or collects it (if the buyer paid less to the PX than contract price). A CFD is really the payment of the difference between the contract price and PX price. a financial amount. Through the Contract for Differences approach, some of the volatility of the PX could be minimized.

In all likelihood, a combination of bilateral contracts and PX spot markets would arise if the Power Exchange concept were developed. However, development of a PX in Nebraska would lack an existing "tight" power pooling arrangement, which would result in substantial developmental and infrastructure costs.

While the Task Force believes that a PX is preferable to bilateral contracts, the prospective costs indicate that the PX would need to be undertaken on a regional basis.

5.3.5 Divestiture of Generation/New Merchant Generators in Nebraska

Expanded competition at the wholesale level, and emerging competition, or anticipation of it at the retail level, will create pressures for divestiture of Nebraska electric facilities. generating plants in particular. Separation of generation, transmission and distribution by electric systems participating in retail competition could require divestiture of generating plants. Nebraska's generating plants are currently producing energy at a cost below that of the region and also most of the country. Part of the reason for these lower costs is that the plants are financed with low cost tax-exempt financing. If they were sold at market value or at book value, the cost of the new debt incurred to finance the purchase of the plants could significantly increase the cost of energy produced by the plants.

As noted in Chapter 7, certain restrictions currently exist for sale of consumer-owner facilities. Public power districts are prohibited from selling facilities to a for-profit entity. Municipal and rural cooperative systems do not face this restriction. Policies and evaluation criteria regarding divestiture need to be thoroughly considered by the legislature for their impact on wholesale power pricing. Decisions to divest would need to be based on case-by-case analysis for each system, and a local determination.

Such policies could be guided by a "no-net-harm" principle that would prevent cost increases from plants sold to other entities. A "no-net-harm" principle might also be applied to the siting of new plants by prospective merchant generators. Part of the siting requirement could require demonstration that the plant would not increase power costs in the state. If the plant were being constructed to utilize local resources and export power out-of-state, examination might be required to show that the benefits to the state outweigh costs to the environment, public convenience, or other factors. (Also see section 5.6.7.3 for discussion on divestiture of distribution and other facilities.)

5.3.6 Power Supply Planning

Greater efficiencies may also be possible from coordinated power supply planning. There are two levels to power supply planning: analysis by each individual system and analysis conducted by the Nebraska Power Association as part of the statewide Integrated Resource Plan. In the first level, each utility forecasts its electric sales requirements for 10-20 years, reviews its current power supply resources, and analyzes all reasonable alternatives to add to the resources to supply the future requirements. The forecast review is usually conducted annually, and becomes more extensive if resources are needed. The addition of new generation can take from three to eight years, depending on the type of plant and location.

The statewide Integrated Resource Plan has evolved from state statutes that require a statewide agency designated by the Power Review Board (the Nebraska Power Association) to perform a statewide study and when requested, submit the results to the Power Review Board for approval. This study is to include an examination of the transmission system. There is no requirement that individual electric systems follow this statewide plan. Each individual system can ask the Power Review Board for approval to add resources to meet its own needs.

According to current forecasts, MAPP will have insufficient reserve margins in 2005 unless additional units are added. The extent of reserves in Nebraska depends upon the status of NPPD's Cooper Nuclear Station. By 2004 the Mid American (Iowa) and LES (which has renewal options) purchase contracts expire. Whether Cooper continues to operate to 2014 when the operating license expires will be a key factor in a statewide generation reserves adequacy.

Depending upon the Cooper scenario, a statewide deficit could occur as early as 2005 or as late as 2010. Per the statewide Integrated Resource Plan Coordination Report (1997-2016), in 2005 the statewide generation surplus/deficit could range from 548 MW surplus to 226 MW deficit depending on the Cooper decision. For the three largest utilities, NPPD's 2005 range could vary from 558 MW surplus to 216 MW deficit; LES. 2005 range from 3 MW deficit to 100 MW deficit; OPPD is forecast to be 46 MW surplus in 2005. However, each individual utility is currently responsible to meet its generation and reserve requirements.

Chart 5-6

Intensified wholesale electricity competition will make forecasting and planning much more difficult as the amount of sales requirements becomes increasingly uncertain. With limited or open retail access and possible transition of customers, these sales requirements become significantly more uncertain.

To solidify Nebraska generating utility's planning process and improve joint efforts, several options should be considered:

• The Nebraska utilities would continue to jointly plan facilities but could be required to follow the statewide plan.
• The generating utilities would be required to purchase or utilize other Nebraska facilities with surpluses before expanding or adding to their own.
• The resources of the generating utilities could be consolidated as suggested for a generating cooperative.

5.3.6 Summary and Recommendations of Generation and Power Supply Level

Factors affecting wholesale power supply prices, and wholesale power markets, will continue to evolve. It is vital that Nebraska systems work together to address these changes in a manner that can retain current low wholesale prices and allow participation in regional markets.

Given the opportunities for Nebraska systems to work together, the Task Force recommends formation of a workgroup to examine all options for retaining low cost generation including the potential for a Nebraska Power Transaction Center and full study of a Nebraska Generation Cooperative.

The Task Force recommends standard wholesale contracts for Nebraska systems that include common pricing, rather than random bilateral contracts, and supports formation of a regional Power Exchange. The Task Force also recommends joint planning of generation according to a statewide plan.

Transmission

In addition to the need to have a viable wholesale power supply market in place, a second precondition for retail competition is the need for adeqate and accessible transmission facilities functioning at a regional level and at a statewide level.

The Nebraska high-voltage transmission system (115KV and above) is operated as a network and is interconnected to the MAPP region and the eastern interconnection. In the western part of the state, the system is owned primarily by Tri-State and Basin Electric and is interconnected to the Western Systems Coordinating Council Region and the western interconnection. The two interconnections are joined only through AC-DC-AC ties, located in Nebraska at Sidney and Stegall. Each of these entities has its own control/dispatch centers to monitor and operate its transmission systems. These centers do, however, communicate and coordinate activities with each other and the other interconnected system operators. The high-voltage transmission system is shown on Map M5-1.

The operation of the transmission system must be coordinated with the operation of the various generators throughout the state and region. Current state statutes allow these owner/operators to merge, form alliances, or to enter into various operating arrangements with each other.

The planning of the transmission system is done by each owner but is coordinated through the Midcontinent Area Power Pool (MAPP) or through the Western System Coordinating Council (WSCC) in the western part of the state.

MAPP is an association of more than 90 electric utilities and other electric industry participants serving: Minnesota, Iowa, Nebraska, North Dakota, Manitoba, and portions of Missouri, Kansas, Wisconsin, Montana, and South Dakota. Its three functions are to: ensure that electricity is transmitted in a reliable fashion throughout the region; help facilitate the voluntary wholesale buying and selling of bulk power; and oversee transmission service with and adjacent to the MAPP region to make sure service is provided in a comparable and efficient manner.

In Nebraska, the 34.5KV and 69KV sub-transmission system is owned primarily by the individual LDCs (see Map M5-2 ). Although most of the system can be backed-up or interconnected, most of the system is operated radially, not as a network with connected loop feeds.

The operation of the sub-transmission systems is coordinated between adjoining systems and/or through various dispatch centers located throughout the state. Since most of these systems operate radially, the coordination is important, but it is not as critical as with the interconnected high voltage transmission system. Most of the sub-transmission system in the areas operated by rural system wholesale customers of NPPD are operated in a joint fashion. These systems are jointly planned and used by NPPD and the wholesale rural systems.

To improve operating efficiencies, NPPD is currently working with their rural system wholesale customers to transfer ownership and operating responsibility of significant portions of the current NPPD-owned sub-transmission facilities to the rural systems. This transfer is being undertaken to improve operating efficiencies and to maximize the benefits of the distribution systems also being transferred.

Regardless of whether the Current Structure is modified, or the state moves to Limited Access, or Open Access, Nebraska electric utilities would continue to be responsible for planning, construction, maintenance, restorations, and operation of the transmission system. This includes system dispatch, line equipment monitoring for loading and voltage, system-wide switching in support of maintenance, and load control. The utilities would ensure compliance with all National Electric Safety Code (NESC) standards and requirements and be responsible for the physical reliability of their portion of the transmission facilities.

The Nebraska transmission-owning utilities would continue to be the contact point on safety and physical transmission system-related service quality issues. They would maintain nondiscriminatory service restoration policies and procedures. These procedures would be designed to restore service to the maximum number of customers as quickly and efficiently as possible, independent of who the electric energy provider is, or if the local electric utility acts as the aggregator or competitive supplier for the customer. The latter would also be the case if the LDC continues to serve that function.

Transmission power delivery would continue to be regulated through the local boards as a cost-based business similar to current operations, but the likelihood of more regulation at the state or federal level is apparent in a competitive environment.

Transmission structure and operations can assume a number of forms in a competitive retail market. At the regional level, it is likely to be some form of regional transmission organization. Other organizations may also emerge to serve Nebraska consumers. At the state level, there is a range of possible changes to consider.

5.4.1 Transmission for Wholesale Competitive Markets/ISOs/RTOs

As previously mentioned, the Nebraska transmission system (34.5KV and above) has been open to Nebraska LDCs for use in wholesale transactions since the 1960s. This is limited to available capacity at the transmission owner's rate. Although as part of non-jurisdictional systems Nebraska transmission may not be subject to the Federal Energy Regulatory Commission (FERC), that agency in its orders 888 and 889 required open access at the national level. These orders generally require that the transmission system be open to all wholesale transactions. They further require that the rate charged by the owner be the same rate it is charging itself for use of the system and that the systems be expanded to accommodate new requests for transmission transactions. These orders also encourage that the transmission systems be structured such that they are operated by an Independent System Operator (ISO).

According the FERC's definition: "The Independent System Operator is to provide reliable, efficient, nondiscriminatory and comparable access to the transmission system and, to the extent practicable, maximize the use of the transmission system."

While this definition appears straightforward, many variations have been established in FERC-approved ISOs. In view of the difficulty of forming voluntary ISOs, FERC's consideration has broadened to include various forms of Regional Transmission Organizations (RTO). The term "Regional Transmission Organization" is intended by FERC to include all types of organizational structures, including ISOs, Transcos, and Gridcos. FERC's stated objective is to encourage all transmission-owning entities to place their transmission facilities under the control of an RTO. FERC has stopped short of mandating participation in RTOs, or specifying regional boundaries, or a specific type of RTO, but has proposed minimum requirements for RTOs. FERC has also set December 15, 2001 as the date for RTOs to become operational.

The formation of ISO/RTOs and coincident development of unbundled transmission rates for open access is generally resulting in increased rates for transmission across the country, as evidenced by recent open access filings with FERC.

These increased rates reflect, in part, the cost of the ISO to provide operations, administration, information handling, accounting, billing, etc. The Midwest ISO indicates an initial capital cost of about $150 million. The preliminary estimates for the IndeGo ISO that could have included western Nebraska were as high as $164 million. The California ISO development costs were about $300 million with annual operating costs of about $150 million. MAPP currently has an annual budget of approximately $22 million, and estimates an additionl $20 million per year would be needed for an ISO.

Even though a MAPP ISO proposal was voted down by the membership in the fall of 1998, it was by a slim margin. Another proposal is expected to be to be forwarded to the membership. A Regional Open Access Transmission Tariff has been forwarded to FERC for approval and may be operational by early 2000.

MAPP currently has a FERC approved Regional Transmission Group (RTG). The RTG includes both transmission using and owning members and its governance involves approval by a majority of both users and owners. The RTG replaces the fomer MAPP organization and provides governance for the security center and oversight of various committees.

There are basically two types of RTO structures, a not-for-profit form and a for-profit form that are being debated at the national level. The debate concerns which would provide the best long term solution to the operation and expansion of a region's transmission systems. For purposes of discussion here the not-for-profit will be referred to as an ISO and the for-profit will be referred to as an Independent Transmission Company (ITC). The ITC could own all or at least some of the transmission under its operational control and it could have the ability to build and own new facilities, while an ISO would not own transmission but would have the authority to operate all transmission in the region and order transmission owners in the region to construct new facilities and expand the capabilities of existing facilities as necessary to maintain reliability and increase transfer capacity around constraints.

The arguments made by proponents of ITCs are that only ITC as for-profit entities can achieve business efficiencies because they have the profit incentive to maximize through put. Another suggested advantage is that ITCs can better focus on the needs of its customers because it is truly independent and not influenced by the political decision process typical of an ISO where the stakeholders have a say in the ISO governance. The third strength suggested for the ITC is its true independence from the generation side of the business, being a separate company with governing boards and employees with no connection to generation owners. ITC proponents believe this would lead to more expeditious solutions for facility expansion because of the ITC's incentive to construct and ability to use several finance alternatives. ITCs may also better handle rate dispute problems with performance-based rates thus resulting in a reduction of regulation. This meets with the FERC desired goal of a structure requiring only light-handed regulation.

The arguments made by the proponents of the not-for-profit ISO structure are that history has shown several large not-for-profit transmission owners have operated efficiently and continue to serve the needs of customers, through public power systems owned by federal, state and city governments and rural cooperatives owned by member/customers. The rates of these not-for-profit systems are cost-based and require minimal regulation because margins over cost are either reinvested in system facilities or used to reduce rates. ISO structure better addresses the FERC goal of RTOs that require minimal or light-handed regulation. The stakeholder governance structure generally applied to the ISO is in part self-regulating, relieving FERC from continually monitoring transactions and the potential for monopoly abuse of market power. ISO proponents say this is not the case with ITC because it is a monopoly with a profit motive, thus by design requires on-going regulatory oversight to assure that market power is not being abused and that decisions are in the best interest of the public and not solely driven by profit motive. ISO proponents believe an ISO can better serve the public interest in planning and expanding the transmission system because the boards don't have the conflict of the profit to the stock holder versus the interest of reliability and facilities maintenance.

Both ISOs and ITCs have the advantage of a single tariff that allows open access to all with nondiscriminatory pricing. Changes in the tariff for both would be subject to FERC approval but only after public input. Both are required to have independent scheduling and administration. There is a hybrid ISO/ITC concept that could blend the advantages of the structures. The advantage the for-profit independent company structure has for efficient decision-making and the not-for-profit advantage related to lower rates and attentions to reliability could be combined in a structure sometimes referred to as a Transco. This structure is similar to that of a member-owned cooperative established as a private not-for-profit corporation. Such a corporation could have an expert board of directors not affiliated with the transmission or generation owners, thus maintaining independence. A Transco would differ from the ISO in that it could own, lease, or contract for transmission assets.

The Task Force recommends a regional transmission organization large enough to provide greater compatibility with competitive markets. Public ownership would be preferred.

5.4.2 A Nebraska Transmission Organization (NTO) and Regional Consumer-Owned ISO

An alternative to a regional ISO would be a Nebraska Transmission Organization (NTO) involving potentially all high-voltage transmission (115KV and above) in the eastern part of the state. The NTO could establish a single control center that would operate around the clock. This center would have all necessary real time data inputs and communication links to the existing MAPP Security Center in Minneapolis. The NTO could become part of a large regional ISO/RTO overcoming the problem of Nebraska transmission alone not being large enough to allow sufficient access to regional markets. The NTO could be expanded to include a single Nebraska transmission rate zone to be applicable to a broader regional transmission tariff. This would involve NPPD, LES and OPPD negotiating a single statewide pro forma access tariff. The tariff could be administered by the regional ISO/RTO and the revenue generated by the tariff would be distributed among the transmission owners.

Another alternative is a concept involving development of a Midwest Region public power and consumer-owned ISO/RTO. This concept would involve potentially all eastern Nebraska transmission systems (NPPD, OPPD, LES) and out-of-state transmission owners such as WAPA, Basin Electric, and possibly other consumer-owned power cooperatives in North and South Dakota and other states adjacent to Nebraska.

This group could also become part of a larger regional ISO/RTO if it was found that it was not large enough for sufficient access to regional markets.

5.4.3 Additional Transmission-Related Functions in a Competitive Retail Market

If retail competition develops, the transmission system would be available for use by retail customers. This use could be on an individual customer basis or an aggregated customer basis. This increases significantly the number of organizations or agencies that can individually use the transmission system. The control or administrative functions required to accommodate these increased transactions will require a significantly expanded transmission control function by the operator of the transmission system. This development supports the concept of an NTO or regional consumer-owned RTO that would work in coordination with public control area operators on power supply coordination.

A new role opening up in competitive retail markets is that of Power Supply Coordination (PSC). The basic role is currently performed by the electric utility control area operators. Under a competitive retail environment this may continue to be an electric utility function but some portions of it may be "opened up." Today, the utility control area balances generation with load. In a competitive retail environment, not all loads will be served by the incumbent utility generators. There will need to be changes in how power and energy transactions are processed, booked and billed to maintain continuity of service.

Two primary power supply coordination functions will be energy scheduling and financial settlement. These functions will make it possible to provide power delivery services to an aggregator or competitive power supplier on behalf of contracted retail customers they serve.

The core responsibilities of PSC likely would include:

• Monitor resource schedules and match with load obligations and projections. This includes scheduling bilateral contracts between aggregators/suppliers and resource generators or wholesale power marketers.
• Form transmission and distribution grid services and comply with grid rules and processes.
• Meet current reliability standards for control area service.
• Account for losses.
• Provide financial services, including accounting reconciliation.

These are essentially the same responsibilities electric utilities and wholesale power marketers must comply with in today's wholesale competitive market. Products and services the PSC should make available to the aggregator or competitive supplier to purchase are:

• Schedule aggregator or supplier power delivery from multiple points of delivery.
• Confirm deliveries scheduled for aggregator or competitive power supplier.
• Acquire ancillary transmission and distribution support services for clients from various providers if not otherwise provided.
• Provide infrastructure and systems necessary to reconcile system energy imbalances, and determine penalties and bill aggregator or competitive power supplier for services rendered.

The aggregator or competitive power supplier will need to employ a Scheduling Coordinator (SC). The SC performs the daily pre-scheduling and scheduling functions of the competitive supplier and works with the electric utility control area operation in accordance with required services. The SC submits balanced schedules in the day-ahead market and provides a pre-scheduled forecast of the aggregate hourly requirements for the next 24-hour period. The utility control area will reconcile the energy scheduled with the SC's actual hourly load and bill any discrepancy via an energy imbalance tariff. The SC will contract with the utility control area that defines both parties. obligations. The competitive supplier might act as its own SC or an individual customer could act as its own SC provided it meets necessary state, MAPP/NERC certification requirements and rules and obligations governing system operations and reliability. The SC also will reserve transmission and distribution paths and services to deliver power from the source to the customer's point of delivery. The SC may also provide or purchase necessary ancillary services required for delivery.

The prevailing MAPP scheduling practices and reliability criteria include around-the-clock dispatch facilities. The NERC tagging requirements necessary for OASIS must also be included to insure firmness of schedules. The SC or competitive supplier will arrange for alternate energy deliveries to the load when a pre-scheduled energy becomes unavailable or undeliverable. In order for an energy schedule to be valid, the SC and competitive supplier, the source generator/marketer, the control area operations of the generator, and control areas of transmission paths must all have validated each transaction.

5.4.4 Summary and Recommendations of the Transmission Level

Nebraska's high voltage transmission system is interconnected with the surrounding region and the eastern interconnection. The western Nebraska systems are connected to the WSCC region and the western interconnection. This could place Nebraska systems in two different ISO/RTOs developing on different schedules. It is important that Nebraska distribution systems have access to the regional transmission system and therefore surrounding generation and power supply alternatives.

In order to accomplish this, the Task Force recommends continued participation of transmission-owning systems in efforts to become part of regional ISOs. However, the Task Force also recommends that a workgroup be organized by the legislature to further explore the concepts of a Nebraska Transmission Organization and regional public power and consumer-owned ISO. The Task Force also recommends examination of all other methods to create greater efficiency for Nebraska's transmission network.

Regulatory Changes and New Structure

A third