|CHAPTER FIVE: CHANGES AND IMPACTS ON NEBRASKA'S ELECTRIC
INDUSTRY STRUCTURE AND OPERATIONS
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 achieve 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.
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 District, Omaha Public Power District, and Lincoln Electric System own most of the state's transmission 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 accommodated 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 may 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 proceeds, 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 focus more specifically, reasoning 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 needs to be assessed based on key issues and criteria.
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.
Additional criteria that may often be considered non-economic can translate into economic impaacts over time, or have a strong conditiong effect on economic issues. These are noted in Table 5-2. At a policy level, these criteria include recognition of federal pressures and regional market pressures, incompatibility of cost-based and profit-based systems, and impacts on local control. Transitional issues include having the necessary preconditions met and consideration of the extent of change in law and regulation. There are also a range of operational issues that include risk management, power price volatility, system reliablity, consumer protection and education, environmental protection, workforce training and safety, and multi-service delivery.
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.
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 MEAN and 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 by the Task Force 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 U.S. 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 U.S. 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.
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.
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. Tri-State Generation and Transmission Association, Inc. (Tri-State) of Denver, Colorado, also serves several rural systems in western Nebraska. Wholesale power costs are the generation and transmission component of electricity costs and must be kept low to keep retail rates low since wholesale power costs account for more than one-half of the retail costs.
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 5-4) 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 Cost per Kilowatt- Hour Purchased at Wholesale (Median)
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 method requiring the least changes 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.
18.104.22.168 Nebraska Power Optimization Center
One concept deserving study that could allow flexible participation in the regional market and offer Nebraska's low cost generation for use by Nebraska's customers for short term hour-to-hour, day-to-day and longer term type transactions could be the establishment of a Nebraska Power Optimization Center (NPOC). This concept is an administrative facility using an electronic bulletin board to post energy prices. This could be a real time system with minute-to-minute updates.
The NPOC could enhance the ability to purchase and sell Nebraska public power resources at cost plus an administrative fee 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 NPOC 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.
Study of the NPOC concept could include the following basic parameters:
The NPOC 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 NPOC 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 Organization.
22.214.171.124 Nebraska Generation Organization
Another concept deserving study that could help retain Nebraska's low cost generation for use by Nebraska customers is the formation of Nebraska Generation Organization (NGO). As noted in Chapter 4, this structural approach could be more advantageous than the administrative Optimization Center, or could be created in addition to, or as an alternative to the Optimization Center.
A large consolidated organization could provide the consumer-owned systems with a greater competitive presence to balance that of large holding companies. The NGO could also provide more options to stay competitive in an open retail access market, or to address competitive pressures in a Modified Current Structure.
Study and screening of all potential types of structure for the NGO should be made. These could include an NGO that 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 another form, the NGO 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 NGO, or an initial phase, could include only joint development and ownership of new generating resources.
For Study consideration, basic parameters of the NGO could include the following:
While providing the potential for greater market presence, the NGO would also require commitment from the Nebraska systems. This commitment may be less than a commitment to the Optimization Center if only future generation is developed and owned jointly, and greater if all resources were assigned to the NGO. That commitment could expand based upon achievement of specific milestones and judgements concerning regional market prices and conditions. The type of organization, i.e., Public Power District, Joint Action Agency, Interlocal Agreement, should also be studied.
Recommendation: The Task Force recommends that a working group be designated to examine all options to retain low wholesale power costs, including study of a Nebraska Power Optimization Center and a study of the formation of a Nebraska Generating Organization.
5.3.4 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 such as options, hedging and resulting 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.
126.96.36.199 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. To be competitive there could be a state requirement that all prices and terms of bilateral contracts be made public and 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 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.
188.8.131.52 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.
For example, the system scheduled demand (load) calls for a specified amount of generation to serve the load. The market clearing price is the bid price of the last unit bid selected to meet that load. All units with bid prices less than the bid price of the last unit bid selected would run and also receive the market clearing price of the last unit selected. 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 (e.g. 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 could 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 184.108.40.206 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 (see Chart 5-6). 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 2004 or as late as 2009. Per the statewide Nebraska Utilities Annual Load and Generating Capability information provided to the Nebraska Power Review Board, in 2005 the statewide generation surplus/deficit could range from 265 MW surplus to 510 MW deficit depending on the Cooper decision. Surpluses and deficits vary from utility to utility and each individual utility is currently responsible to meet its generation and reserve requirements.
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:
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.
Recommendation: 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 Optimization Center and a Nebraska Generation Organization.
Recommendation: 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.
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 adequate 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 currently is not 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 MAPP ISO proposal has been forwarded to the membership. In addition, a MAPP committee has been negiotiating with the Mid-West ISO for the provisions under which current MAPP members could join the Mid-West ISO. These two options are moving forward in parallel with the decision and vote currently set for March of 2000. A MAPP 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 former 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.
Recommendation: 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. Nebraska transmission owners are currently discussing an arrangement similar to this NTO concept.
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:
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:
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.
Recommendation: In order to accomplish this, the Task Force recommends continued participation of transmission-owning systems in efforts to become part of regional ISOs. Although Nebraska transmission owners are already discussing an NTO type structure, the Task Force also recommends that a workgroup be organized by the Nebraska Power Review Board to further explore the concepts of a Nebraska Transmission Organization and regional public power and consumer-owned ISO so that all stakeholders can be involved. The Task Force also recommends examination of all other methods to create greater efficiency for Nebraska's transmission network.
A third precondition for retail competition is the establishment of a statewide regulatory body along with rules and standards to augment local bodies in a competitive retail market. Although not within the category of day-to-day operations, the regulatory rules affect operations and structure of the Nebraska systems beginning with the state's 395 retail service territory agreements and ranging to the siting of generating plants. The role of a statewide body would be essential to oversee and guide the development and operations of a competitive retail market.
As discussed in Chapter 3, establishment of competition at the retail level will require new standards for consumer protection, consumer education programs, transparent costs and transparent pricing, rules for marketer certification and market power restrictions, rules for operational transactions, standard metering and billing policies, and regulated default and standard offer service. The types of rules and protocols needed to oversee and guide operations in a competitive market include:
Uniform oversight and enforcement of these rules, policies and services would provide the framework for a transition and augment local control in shaping the on-going development of the retail market. Contribution to the framework for a transition would occur through coordination of workgroups assigned to various studies, public hearings conducted on proposed findings or proposed rules, participation in development of implementation legislation, and assessment of whether specific preconditions for the market have been met to trigger a transistion.
Recommendation: The Task Force recommends that initial legislation be developed that first directs and authorizes the Power Review Board to coordinate workgroups and hold hearings regarding proposed rules, standards, protocols, studies, and other preparatory work. Second, implementation legislation, submitted if preconditions are met and retail competiton is to established, would designate a statewide regulatory body as a key part of the industry structure. (See Chapter 9 for a discussion of legislation and regulatory roles.) The Task Force also recommends that the existing role of the local boards be maintained and that the role of the statewide body augment the roles of local boards. Part of the local role would be a determination of whether or not to take part in a competitive retail market. This determination and alternative options at the local distribution level are described in the following sections.
The distribution level is clearly where retail competition, or alternatives to retail competition, could have the greatest impact on structure, utility functions, and principles of operation.
The core functions of the distribution system are the administrative and operational tasks associated with the delivery of electricity to consumers. As described in Chapter 4 (section 4.3.2) Nebraska's 163 municipal, public power district, and rural cooperative distribution systems carry out metering, billing and collection functions, and operation and maintenance of the poles, wires, substations, and related equipment. Some of the systems own generating and transmission facilities, but the majority rely on purchased wholesale power supply as indicated in Chart 4-1.
As noted earlier, 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 appropriate degree of change, and the conditions that change creates for present and future consumers need to be considered for the long term planning and financing horizons of the industry.
There are four options for the functions of distribution systems that can be considered (although these are not intended to be exclusive):
A transition to retail competition at the distribution level would need to be based on assured savings and benefits for consumers. The fundamental difference between the current system and a competitive market system at the distibution level is that structure and operations are presently organized to provide electricity as a universal non-profit "service." In a competitive market system, structure and operations require functions that are selectively transactional and market-based for delivery of electricity as a "commodity" with profit margins centered on market conditions.
If Nebraska distribution systems were to engage in competition among one another as well as among private competitive marketers, it is likely that the current basis for cooperation among the systems would erode. As a first step to establishing competition at the distribution level, exclusive service territories would be eliminated and determinations would be made to alter fundamental principles under which the Nebraska systems currently provide non-profit service. These principles include: "Universal Service"; "Obligation to Serve"; "Fair, reasonable, and non-discriminatory rates"; and policies for low income and public assistance consumers. Each of these principles is discussed below.
5.6.1 Universal Service
The term "universal service" describes a policy or goal of providing affordable electric service "to virtually all citizens regardless of their income." This policy is supported by common law requirements for public utilities, federal policies and programs, state statutory provisions, and local utility policies and programs.
Universal service requirements evolved from similar requirements for gas companies providing residential and commercial service prior to the advent of electric service. For electricity it took on particular significance for rural areas. In Nebraska, the push for universal service was largely a rural phenomenon which began in the early 1900s as rural residents began to undertake actions for access to the benefits of electricity which were being enjoyed by most residents of urban areas.
State policy requires: "Any supplier of electricity at retail shall furnish service, upon application, to any applicant within the service area of such supplier if it is economically feasible to service and supply the applicant." State law also provides authority to municipalities to establish requirements for service.
The modern-day application of "universal service" policy can best be gleaned from a review of the state's electric utilities' line extension policies. These are the policies adopted by the local utility's board of directors or a city council that lay out the conditions under which new electric service will be provided. Since the adoption of these policies are the responsibility of the local decision-makers, they can be tailored to fit the local conditions or the prevailing philosophy of the local board and considerable variation in them can be found.
Today, there are only a few rural electric systems in Nebraska that follow the old policy of "area coverage" where electric lines are extended to new customers at no cost to the consumer, wherever they may wish to locate. It is very difficult to generalize regarding electric utility line extension policies, because there is a wide variation in the approaches taken. However, they can be divided into three categories: facilities-related, cost-related and revenue-related.
Emergence of retail competition could raise significant questions regarding who is responsible for connecting customers, or for paying the costs for connecting customers.
5.6.2 Obligation to Serve
The term "obligation to serve" refers to a responsibility or duty imposed on electric utilities both at common law and by statute to provide sufficient electric generation and transmission capacity to be able to provide adequate and reliable electric service to all customers, both retail and wholesale, within the utility's assigned service area or with which it has contractual relationships. In Nebraska the public policy is clearly indicated by state statutes that stipulate it is state policy "to provide citizens of the state with adequate electric service at as low overall cost as possible" and to provide "dependable electric service at lowest possible cost." In a consumer-owned system it is assumed that adequate supplies will be purchased or planned. Further, reliability and reserve requirements of MAPP make it mandatory for members to have adequate reserves and contingency supplies.
At the wholesale level, statutes require any Nebraska generating agency to provide an interconnection with any distribution system desiring power. There is also a requirement to sell power to the distribution system at wholesale if surplus energy is available. Surplus transmission capacity must also be made available for such transactions.
In a competitive retail market, the requirement for adequate supplies and reserves would need to be assigned to a "default" provider. However, this default provider may not be able to maintain a competitive price if it is obligated to have enough generating capacity to serve all customers in an assigned area. Once a customer chooses to purchase power supply from another energy provider, that customer cannot be assured it can return to its former supplier at the same rate being charged to other customers. The default provider may be forced to purchase additional supply on the spot market at higher cost. There are also substantial concerns that retail competition will make planning for future load growth difficult and cause a loss of cooperation between utility systems that could result in a loss of reliability and dependable service.
5.6.3 Fair, Reasonable and Non-Discriminatory Rates
Electric rates are generally based on cost-of-service principles. As noted in Chapter 2, large users who are less expensive to serve generally enjoy lower kilowatt hour rates. Residential and rural consumers who are more expensive to serve face higher kilowatt hour rates. The process and requirements for setting rates varies by type of utility system.
For public power districts and public power and irrigation districts, Neb. Rev. Stat. § 70-655 (1996) requires the board of directors of a public power district or a public power and irrigation district to set rates which permit the district to operate in a successful and profitable manner. It further requires that the rates set be "fair, reasonable and nondiscriminatory, and so adjusted as in a fair and equitable manner to confer upon and distribute among the users and consumers of commodities and services furnished or sold by the district the benefits of a successful and profitable operation and conduct of the business of the district." In order to stimulate economic development, a PPD may provide discounted rates to large industrial customers for a period of five years under the Quality Jobs Act.27
Municipalities are not required by state statute to fix fair, reasonable and non-discriminatory rates for electrical services. However, as discussed in Chapter 7, they are subject to a similar standard by common law. In a number of cases, the city councils have adopted PURPA's section 133 rate making standards, which requires cost-of-service rate-making. In addition, the Nebraska Legislature recently adopted a provision, similar to the discretion given to the public power districts, which allows municipalities to negotiate economic development rates under limited circumstances. 28
A cooperative organized under Chapter 70, Article 7 is required to "be operated without profit to its members, but the rates, fees, rents, or other charges, for electric energy, and any other facilities, supplies, equipment, appliances or services furnished by the corporation, shall be sufficient at all times (1) to pay all operating and maintenance expenses necessary or desirable for the prudent conduct of its business, and the principal of and interest on the obligations issued or assumed by the corporation in the performance of the purpose for which it was organized, and (2) for the creation of reserves."29 There is no requirement in statute that the co-ops' rates be "fair, reasonable and non-discriminatory" as required for the public power districts although they would be under a similar common law requirement.
The rural distribution cooperatives organized under the Nebraska Nonprofit Corporation Act are not subject to the section quoted above or to the provisions which apply to public power districts and appear to have a great deal of flexibility in setting their rates, although they also appear subject to the non-discriminatory common law standard.
The setting of rates by any power supplier is subject to other provisions in Chapter 70 dealing with discrimination. This law permits a retail customer to petition the PRB for a determination of whether their power supplier is treating all customers fairly and without discrimination within the same class. An appeal of the PRB's decision may be taken to the Court of Appeals.30
The differences in requirements for service and rate policies are outlined in Table 5-7.
Source: LR 455, Phase I 31
Note: Local requirements vary depending upon the policy decisions of local boards. State requirements provide a common standard for each locality served. All PPDs are also required to meet the state standard for fair, reasonable and non-discriminatory rates for wholesale sales. Note (1) indicates that the PPDs may face a conflict with requirements for fair, reasonable, and non-discriminatory rates with the setting of special low-income or subsidized rates.
5.6.4 Low Income and Subsidized Rates
Most states require private investor-owned utilities to adhere to a set of standards and practices for those customers who qualify for low-income service. This typically includes: reduced rates, payment plans, and other services related to public assistance programs. Municipal and other public power systems in those states are usually considered non-jurisdictional and establish their own programs and policies regarding low-income customers.
In Nebraska, low-income policies are locally-determined and may vary. All systems have shut-off policies and moratoria regarding shutoff schedules, but there is no comprehensive set of standards. A competitive market system would require formulation of uniform policies for treatment of low-income and subsidized customers. A modified Current Structure could include this change as well.
5.6.5 Differing Authorities To Engage In Business Relationships
In addition to the differing requirements for service, public power districts, rural cooperatives, and municipal systems have varying levels of authority to engage in different business relationships as indicated in Chart 5-8. These authorities may need to be amended to create the necessary balance for either a modified current structure, or a competitive retail market structure.
Source: LR 455 Phase I 32
1 Under state law political subdivisions cannot do indirectly that which they are not authorized to dodirectly. (See State ex rel Johnson v. Consumers Public Power Dist., 143 Neb. 753, 10 N.W. 2nd 784, 152 A.L.R. 480.)
2 Activities cannot involve
lending of credit or actions that would risk tax-exempt status.
5.6.6 Differing Authorities To Provide Services To Consumers
The different types of systems also have varying authorities to provide different types of services to consumers. These are indicated by Table 5-9. These varying capabilities to provide a specific service, or combined service, may need to be amended to create the necessary balance for a modification of the current structure, or a competitive market structure.
As noted above, the current non-profit and consumer-owned industry structure delivering electricity as a "service" is very different from one organized to provide a selective transactional market system providing electricity at market rates as a "commodity." The current structure would need to be modified to co-exist with or prepare for a competitive system. Significant alteration in structure, operations, principles, and authorities would be needed to accommodate Limited Access or Open Access at the distribution level.
Decisions concerning whether to develop a Modified Current Structure, Limited Access or Open Access should be determined according to assurance of benefits and evaluation of economic and non-economic criteria such as that outlined in Tables 5-1 and 5-2.
5.6.7 Modified Current Structure
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.
Modification of the industry's Current Structure is described in Chapter 4 and outlined in Chart 4-3. It can be undertaken while the preconditions for wholesale markets, transmission and statewide regulation are being put in place. Modification would not open the systems to retail competition and would require the least amount of legislative and regulatory change. Cost-based principles would remain in place, and current distribution fuctions would continue largely unchanged, except to the extent that multi-services might be provided, or that functions are out-sourced.
In terms of policy changes, public power districts might undergo a loosening of retail rate and service requirements to create policy balance with municipal and cooperative systems. There could be alteration of authorities to provide multi-services and engage in business relationships to create greater policy balance among the systems. These changes could enhance the operations of the current systems and help to prepare for a possible competitive retail market.
However, the most signficant changes might occur in the structure of distribution systems to create greater efficiencies and prepare for a possible competitive retail market.
There are three primary forms of structural change for distribution systems: mergers, alliances, and divestiture or sale of the system or its assets to public or private entities.
With 163 systems providing retail service in the state, there is a general assumption that mergers may be warranted to bring about cost reductions.
During the past 30 years, several successful mergers at the distribution system level have occurred. For example, Eastern Rural Public Power District merged into Omaha Public Power District; Franklin County Rural Public Power District merged into Southern Nebraska Rural Public Power District; Gering Valley PPD merged into Roosevelt PPD, and Wayne County Public Power District and Northeast RPPD merged to form Northeast Nebraska PPD. In addition, several smaller municipalities operated by NPPD were transferred to the surrounding rural electric systems. Currently an additional significant number of smaller municipalities served by NPPD are being considered for transfer to the surrounding rural Public Power Districts.
However, it cannot be generally assumed that combining smaller systems will produce savings. Each merger needs to be assessed for cost savings for combination of system load factors, streamlining of personnel and operations, and savings on distribution system costs.
In regard to distribution costs, recent analysis was conducted to assess the impact of mergers on the operating expenses of rural electric systems in Nebraska.34 Various measures including size, consumer density, load density, and plant utilization factor were compared to see which was the best measure of distribution cost. The plant utilization factor (Total Utility Plant Investment per kWh Sold) was determined to be the best measure of potential distribution cost savings.
It is assumed that voluntary mergers among consumer-owned systems will continue to take place and may accelerate in the face of pressure for greater efficiencies.
There are two primary types of alliances. In one form Nebraska systems work together to enhance their operations or add to services without merging. In another form, Nebraska systems enter joint ventures with public and private parties to expand their marketing efforts for energy, or offer an additional service, such as telecommunications.
In the first form, distribution system operators in Nebraska have used alliances of many types to improve their operations and expand services. Some examples include a group of rural systems in northeast Nebraska that share underground fault finding equipment that would be too expensive for one system. Rural systems have formed a common credit union. The Nebraska Municipal Power Pool (NMPP) provides shared expertise for system operations, accounting software packages, and several other shared type services for their municipal members. The Nebraska Rural Electric Association has a range of services for its members. The Nebraska Power Association (NPA) offers a structure for Nebraska systems to enter into agreements to share equipment and manpower during storm and emergency situations. NPPD shares equipment, manpower, and technical expertise with its wholesale customer distributors. The Nebraska G & T recently formed the Midplains Energy Services Alliance to serve as a structure for its members and others to jointly perform distribution operating type functions and thereby gain efficiencies. These examples could be expanded or added to under current state statutes as the Nebraska electric utilities operating the distribution systems continue to evolve.
In the second form, consumer-owned electric systems may form alliances with public and private entities to provide a multi-service package for consumers. Putting together a partnership or joint venture between a system based on cost-of-service principles, and one dedicated to market-based pricing is difficult at best.35 The concern is that principles may give way to a bottom line that needs to maximize profits. This can cause not only the alliance to go awry, but may also draw the consumer-owned system into competitive conflicts with other consumer-owned systems. However, public-private alliances can also combine resources and expertise not otherwise available, and contribute to a successful service venture. Some major suppliers view alliances as a way of developing market position and information prior to a market opening up, and may end up competing with a former public partner. Nebraska and its many distribution systems could be viewed as such an environment.
220.127.116.11 Divestiture or "Privatization"
Divestiture, or sale of a distribution system or its assets, is a third option for altering the structure of the distribution systems.
Some proponents of retail competition believe that "privatization" of the industry-divestiture of consumer-owned facilities-would deliver greater benefits than non-profit consumer-owned systems.36 In December 1998, Utilicorp issued a white paper calling for a broad-based study on privatizing part or all of the Nebraska public power systems.37
"Privatization" is a broad category that includes the sale of assets, introduction of competition into a statutory monopoly, or contracting out for services. "Privatization" options including divestiture are restructuring options, but need to be analyzed on a system-by-system basis to evaluate economic and non-economic trade-offs.
Generally, consumer-owned distribution systems that have no stranded cost are viewed as a very attractive asset. As industry consolidations continue and energy holding companies seek a larger customer base, pressures are expected to grow for buyouts of consumer-owned systems.
The key issue in divestiture is the valuation process of the asset or system. Valuation needs to consider both short and long term perspectives, and the potential for cost-shifting or higher long term costs resulting from sale of a consumer-owned system.
There are three basic methodologies for valuation: income-based, cost-based, and market-based.
An "income valuation" approach considers either straight income replacement or income plus other considerations. It measures the present worth of the economic benefits to be received over the life of the system. This is usually the preferred method among municipalities because it can provide a long term value for the system, in addition to consideration of additional economic and non-economic elements. Among these are the in-lieu-of-tax payments anticipated for a specific period, free or low-cost services provided to the community, and other economic contributions. It can also include the economic benefit of lower rates (the system's rates may be compared to the private company's rates to determine this figure.)
A "cost-based" method seeks to measure future benefits of ownership by quantifying what would be required to replace the property that considers: reproduction less depreciation, original cost less depreciation, or other cost methods plus additional consideration. This method is often proposed by investor-owned utilities who may also offer to pay for the valuation.
The "market value" approach uses prices in other recent sales, or recent sale price plus specific differences and considerations. Although real estate markets utilize this approach it is not advisable for utlity sales because of the lack of comparable conditions and prices.
Proposals to study or produce valuation of consumer-owned systems on a statewide basis are impractical both because of the range of variables that cannot be accounted for, and the need to involve local government or local boards.
Sale of consumer-owned distribution assets is by statute and tradition, a decision to be made by each local jurisdiction. There are varying rules that govern this as indicated by Table 5-8. A public power district can divest or sell its distribution system to a consumer-owned electric utility such as another public power district, a cooperative, or a municipality. However, state statutes prohibit a public power district from selling distribution facilities to a for-profit organization. A cooperative or a municipality are permitted to sell their distribution system to a public power district, a cooperative, a municipality, or a for-profit electric utility. There are specific provisions and procedures required, however, such as public meetings or ballot requirements. A deterrent for purchase of a distribution system by a for-profit, investor-owned electric utility is the fact that the statutes would allow a public power district or municipality to condemn the investor-owned distribution system and take over the operation (See Chapter 7).
The Task Force recommends consumer-owned systems considering divestiture utilize an "income-based" 38 valuation methodology that will provide an indication of both short and long term impacts on rates, taxes and other issues. The Task Force also recommends that examination be undertaken of the possibility to create criteria to be incorporated into such valuation. For example, divestiture to another consumer-owned entity might be considered as preferential to retain consumer equity and consumer control of facilities
18.104.22.168 Summary and Recommendations Concerning Modified Current Structure
The Task Force recommends modification of the Current Structure to enhance system operations and to prepare for the pressures of retail competition. Modification of the Current Structure would provide several opportunities:
It would allow structural and operational changes to occur without alteration of fundamental principles of consumer-owned systems. At the structural level it opens opportunities for mergers, alliances, and divestiture of assets. Both mergers and alliances should be assessed on an individual basis for efficiency gains and exposure to risk. Although mergers and alliances should be voluntary, incentives might be put in place by the state such as payment for merger studies. Divestiture should be assessed on a similar case-by case basis, using an income-based methodology for valuation and possible criteria established by the state. Divestiture to another consumer-owned entity might be considered as preferential to retain consumer equity and consumer control of facilities. However, any divestiture meeting necessary criteria should be allowed.
With incentives and criteria in place, laws and regulations could be changed to allow greater equity and latitude of business relationships and services by local distribution systems. This would allow all Nebraska consumers to receive benefits of multi-service packages that include electricity.
Modification of the Current Structure could help to accommodate and enhance changes taking place at the generation and transmission levels. Most importantly, these changes could be undertaken while preconditions are being put in place.
Such modification is also consistent with industry evolution and could help to prepare for a competitive retail market, when conditions are such that it might be implemented.
Transition to a system of Limited Access or Open Access means moving from cost-based delivery of electricity as a "service" to establishment of structure and operations to support a selective transactional market delivering electricity as a "commodity." The core distribution functions of metering, billing, collection of payments and operation and maintenance of the poles, wires, and distribution facilities could remain the same. But changes in structure, operations and principles would be required.
The three major systems (NPPD, OPPD and LES) as well as other smaller generation- owning systems that participate in retail competition may 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.
The Limited Access model described in Chapter 4 and outlined on Chart 4-4 assumes that retail competition occurs for only a set of customers qualifed by certain characteristics or phasing of competition. In a Limited Access Structure, the local distribution company could function as a "partial aggregator" providing all retail services to all except for the class qualified for competition, or to all classes. As described in Chapter 4, limited access could be based on a class of customers designated by size of load (i.e. 1 megawatt or greater) or type of customer (residential or government accounts). It could also be part of an approach that phases competition in on a specific schedule set to milestone events, or specific dates. It may also be a mechanism that allows a "buy-through" or price reduction for customers who acquire a competitive supplier with the LDC as a partner in the transaction reducing transaction costs by keeping the customer within the system ("comprehensive aggregator").
While allowing for more orderly and manageable market development, the desegregation resulting from Limited Access can shift costs to customers left behind and make it more difficult for all consumers to participate in a competitive market at a later date. The "niche market" created by Limited Access can delay or erode equitable Open Access competition.
Open Access as described in Chapter 4 and outlined on Chart 4-5 would allow all customers to have access to a competitive retail supplier on a specific date. A market of this type is much more difficult to achieve. In states that have provided full Open Access on a set date, such as California, Pennsylvania and Massachusetts, the realities of the market have created Limited Access, with larger customers receiving the attention of competitive suppliers and smaller customers left without a competitive supplier. The hope is that these markets will mature and serve all consumers, however there are indications that these states may conduct bidding for consumers who are left behind on "default" status. Thus creating a stratified market with more permanent Limited Access for those larger customers, and state competitively-set rates for all others.
Both Limited Access and Open Access require changes the structure, operations, and principles of service to establish competition at the retail level. In addition they require new cost and pricing structures, as well as new distribution functions for consumer load and data exchange.
In a competitive retail market systems owning distribution, transmission and generation may be required to separate operations to prevent the appearance of cost-shifting. This could be accomplished by a functional separation, by divesting one of the functions, or by transferring generation operations to an entity such as a Generation Cooperative, and transmission to a Nebraska Transmission Organization.
There are a few key steps to be taken to prepare for a competitive market at the distribution level. These are described below.
5.7.1 Unbundling of Bills
The first preparatory step is the "unbundling" of electric bills to set out the energy portion of the bill as a separate "commodity" item that would be the target of competitive suppliers.
Electric bills for Nebraska consumers are presently structured such that a single price for service for the period is indicated. This price includes all components such as the generation and power supply component, transmission components, distribution component, administration component, and any other costs such as taxes, etc., which make up the total price of electric service. "Unbundling" of the bill would set out energy as a "commodity" and in addition it would accommodate customer understanding of electric costs and help the utility better identify its costs. New billing items to cover transitional and other costs would also be identified. Unbundling of the bill could occur prior to actual limited or open retail access implementation as part of a modified current structure.
5.7.2 Access Fees
The second preparatory step at the distribution level is establishing equitable "access fees" for competitive suppliers. These fees must be high enough to compensate the distribution provider and other facilities for their services, yet low enough to permit entry by a competitive supplier.
In an open access environment, customers can choose among several electricity suppliers or generators, but access to those suppliers is provided through facilities and services of the Local Distribution Company (LDC) and the local Control Area (CA). Access fees are charged to keep the transmission and distribution owner/operator whole from an incremental or embedded cost basis resulting from new market entrants gaining access to and using the network. Costs to operate will increase because more merchant generators will be selling into the transmission system and additional marketers will be making multiple transactions. The current systems and procedures (e.g., record keeping) are not designed to handle this increased volume and they will require expansion.
An Access Fee can also be used to recover taxes and public-benefits costs that are currently bundled as part of the Customer Demand and Energy charges. They can also be used to recover social costs imposed on third parties (i.e. covering compensation for inadvertant energy flows that pose a burden on the local control area operator). Access Pricing fees should be charged to keep the transmission and distribution owner/operator whole from an incremental or embedded cost basis resulting from new market entrants gaining access to and using the network. Access Fees should be structured so that they are economically efficient and do not distort the electric supply purchasing decisions. Access Fee design is necessary to insure all users of the system pay equitably for the use of the system.
In the event of retail choice, the customer who elects to choose an alternative supplier will receive a bill or bills consisting of the several services provided by one or more suppliers. The customer's bill may be unbundled into the service component prices or some services may be rebundled and shown with fewer line items.
There are 11 types of services to be recovered by Access Fees. Five must be included in access fees charged by the Control Area (CA) operator and passed on to the Local Distribution Company (LDC) to bill. Two must be billed directly by the LDC as part of its "wires" charge. These services must be provided by these local providers because (1) the physical properties of electricity dictate that they cannot be reliably imported from an outside source; (2) the practicalities of billing; and (3) to preserve an effective and low-cost collection of tax like fees for local agencies. The remaining four services can be provided by suppliers other than the CA operator and should be included only when the customer chooses to take those services from the CA operator.
The five services that can be supplied only by the CA are:
The two services provided by the LDC in addition to some "wires" use charge are:
The four services that can be at the customer's option are:
From the customer's point of view, the preferred form of the fee is to have all of these fees billed by one entity. The LDC is the logical entity. This should also result in lower costs in collection of local taxes and fees since local agencies would continue to deal with only one collecting entity for electric services.
A full accounting for access fees needs to be undertaken that will include both a generic fee at the state level and the variable elements at the local level.
5.7.3 Standard Offer/Default Service
The third step to prepare for retail competition is identifying a "provider of last resort."
If the model established by other states is followed, Nebraska's distribution systems would be the "provider of last resort" and retain the responsibility of serving the consumers who do not or cannot find a competitive supplier. The distribution systems would provide this service under the existing principles of universal service, obligation to serve, and fair, reasonable and non-discriminatory rates. Energy rates for Standard Offer/Default Service would be set by a local board based on energy costs which may be fixed or indexed to the spot market.
The problems with Standard Offer/Default Service experienced thus far in other states is related to the price being set below market prices and providing a chilling effect on the entrance of competitive suppliers. This could prove to be the case in Nebraska as well, unless there is an increase in wholesale prices.
In order to reduce duplicative services, the local distribution systems should be identified as the default service providers, with payment of approriate access charges to compensate fully for services and impacts of retail competition. Because small consumers will need to be aggregated, and a consumer-owned system provides the best leverage for such aggregation, the local distribution system should also be identified as the preferred aggregator for competitive retail services. Consumers who choose not to be served by the system and select a competitive supplier or aggregator would be able to do so with the appropriate access charge included in the billing.
5.7.4 Certification of Competitive Suppliers and Aggregators
A fourth step in preparation would be setting-up a certification process for competitive suppliers and aggregators that would assure fair treatment of customers, and efficient business interactions with the local distribution systems.
Those to be certified would include suppliers, brokers, marketers, and others who offer competitive power supply and other services. In all states that have implemented retail competition, certification is required for these parties before they can enroll retail customers. Certification would be carried out by the statewide regulatory agency.
Certification commonly includes the following:
Decertification and fines can take place if a supplier engages in behavior that is contrary to acceptable certification requirements or commits verified violations of operating procedures. Decertification occurs through a defined process with opportunity for appeal.
It is presumed that certain regulatory controls will be in place as part of the Certification Process to assure that contractual arrangements made by suppliers have provisions to protect customers from these events. Proper contracting for Ancillary reserves and load following services should take care of most short term and expected outage events.
A fifth preparatory step would be setting up appropriate systems for metering, billing and collection. Under the current structure, typically once a month the meter is read either by the customer in the self read methodology or by the LDC. When the meter is self read, the customer reads the meter, charts the reading on a card, and mails it to the LDC. In cases not self read, this is done by a meter reader, who is assigned a route that covers a certain geographical area of the service area. The reader visits each meter and records either on paper or on a hand held computer the meter register dial readings required for the account type. Most small accounts like residential and general service have a kWh meter, while larger accounts will have kWh, KW demand, and other electric load readings recorded. The largest commercial and industrial accounts (>500 kW) are typically metered with a time interval recording meter that records readings hourly for retrieval. These meters can be read remotely via a phone circuit or radio connection.
For open access , the frequency of meter reading will vary with the type of services provided. If hourly pricing or interruptible service is provided, then remote reading is likely to capture real time readings. Multiple register meters that record consumption at different times of the day in blocks of on- and off-peak pricing are likely. A different service fee is likely for the option of billing the customer on a cycle of their choice (i.e., 15th of each month, weekly, or prepaid at a discounted rate). These and other billing arrangements will be offered by the Metering, Billing, and Collecting (MBC) provider. The MBC may also provide real time readings from the meter to the customer for a charge via an Internet or other communication link. This allows the customer to monitor usage levels and costs, combine multiple accounts for internal reporting and perform what if analyses of future usage patterns and associated costs.
In an Open Access structure, the MBC may be provided by a third party. Four types of meter ownership and billing arrangements are possible for competitive retail structures
Cases (1) and (2) are similar to how telephone long distance charges are handled if the customers request that long distance charges be included on their local phone service bill. Case (3) is also done but less frequently in the billing of phone services, presumably because most customers don't want to pay multiple bills for phone services. Case (3) and (4) also result in the establishment of multiple billing, meter reading, and maintenance and collecting functions that are duplications of existing systems. Such duplications may not be necessary and the cost of such duplication will be ultimately borne by the customer.
5.7.6 Power Supply Coordination and Load Profiling Service
A sixth step would be making determinations concerning new functions for Power Supply Coordination (PSC) and Load Profiling necessary to balance load and provide data on a specific customer or group of customers to competitive suppliers. This is a function that may be undertaken by the local distribution system.
The control area requirements to carry generation reserves is specified under MAPP. The reserve requirement is based upon firm loads in the control area and will become the responsibility of the retail supplier. The Scheduling Coordinator (SC) could acquire reserves from the control area or other market entrants. A SC may self provide reserves to the control area by delivering firm power and energy on firm transmission to the boundary of the electric utility control area. The SC must ensure that each generator or wholesale supplier from which it schedules energy meets the reliability and scheduling requirements of MAPP and the local control area.
The electric utility control area or incumbent utility in performing PSC type functions might desire or be required to offer the following services to the SC:
The incumbent utility control area may sell to suppliers or SC load profiles developed from load research data. The profiles might be by class of service, typical days of the week, weather dependency, etc. For large customers it may be previously recorded actual data of the customer.Load profiling service is one that will evolve in a retail competition environment.
Load profiling is used to estimate the energy to be used by a group of customers where real time metering is not available. Currently some LDCs have installed metering on a scientifically selected sample of customers to represent a class of customers. Interval recording meters capable of recording hourly loads are installed on the sample at a cost several times the cost of standard metering. The data is collected, edited, and analyzed to estimate on average the load profile of customers by class and at various times of the day, month or season. Since many LDCs do not have systems to collect this type of data, it is possible that third party providers may evolve to fill the load profile needs. These providers can also use various techniques to estimate load profiles from borrowed existing data to avoid the considerable expense and lag time required to establishing a meaningful history of data in a specific area.
5.7.7 Integrated Data Exchange
A seventh determination concerns the exchange of data that would underlie the transactions between the local distribution company, a competitive supplier, transmission providers and others. That data would also be essential for costing and bidding functions.
Competitive suppliers and those LDCs that provide competitive functions will be competing not only for customers but also for power supply and transmission capacity in a market with many more players than under the existing structure. This increased competitive intensity requires that competitive suppliers increase their knowledge and processes in collecting, evaluating, and disseminating load, supply, and delivery path information. This data will also have risk management factors affecting the evaluation and resulting recommended actions. Risk management inputs can include real time Power Markets (e.g., commodity futures, NYMEX, Over-the-Counter Options (buy/sell) or SWAPS (contract for differences).
Information on the following will be required:
The information technology industry is likely to offer a variety of solutions to these individual functional needs, using a variety of technologies and design approaches. The competitive supplier and LDC will need to find ways to accommodate the variations and non standardized approaches. A strategy of integration of functionally like data set interfaces and calculations will need to be developed in order to allow all competitive players access to the same information. Without such a strategy and formulation of industry standards, presumably under state or regional regulation, it is likely that some players may have a substantial market advantage as a result of having information unavailable to their competitors.
Below is an example list of subsystems that will need to be integrated:
5.7.8 Services Other Than Retail Electric
In general, it has been recognized that markets are likely to evolve to allow "convergence" of certain "wires" and "energy" businesses. Providers of natural gas, telecommunications, cable television and other services are already poised in Nebraska to offer multi-service packages that include electricity. While consumers have not yet accepted "multi-service" packages as noted in Chapter 3, consideration must be given to the role the local distribution system might play in a competitive environment offering multi-service packages. Current policy-making has thus far taken a piecemeal approach to allow certain types of competition in some services but not others. This can preclude certain options for consumers. In a competitive market system, it would be essential to provide greater latitude of multi- service provision by all consumer-owned systems. A comprehensive policy approach to all services would be required in a competitive electric market.
5.7.9 Summary of Key Points and Recommendations for Distribution Operations in a Competitive Environment
Transition to a system of Limited Access or Open Access means moving from cost-based delivery of electricity as a "service" to establishment of structure and operations to support a selective transactional market delivering electricity as a "commodity." This would necessitate changes in structure, operations and principles of consumer-owned systems.
Recommendation: The Task Force recommends that such a change should be undertaken only when preconditions are in place, and benefits offset transition and transaction costs. Each local system should be allowed to make a determination on whether to opt-in through its own public proccess.
To the extent necessary or required, the Task Force recommends functional separation of distribution, transmission and generation.
In terms of specific preparation and functions, the Task Force recommends:
5.8.1 Work Force and Safety
Reliability and efficiency of Nebraska's electric systems are dependent on the quality of and training of the work force. Transition to a competitive retail environment in other states is placing stress on the work force and quality of service through down-sizing and reduction of training and certification programs.
Nebraska electric utilities reported approximately 6,700 full and part time employees. By employment sector, approximately 36 percent worked in the generation/production function, 46 percent in the transmission and distribution function, and 18 percent in administrative functions.
The Nebraska electric utility industry employs a wide spectrum and diverse mixture of employment classifications. Employment job classifications are generally categorized as skilled craft (power plant operators, line technicians, electricians, etc.), professional (engineers, accountants, managers, etc.), and administrative/office support (secretaries, clerks, account specialists, etc.)
The total payroll (1995) of the 49 reporting utilities exceeded $269 million. There are more than 2,000 employees in eleven utilities represented under collective bargaining agreements.
Most Nebraska utility employees work under safety policies and procedures which substantially mirror the OSHA regulations, but of the Nebraska systems, only rural cooperatives are required to operate under Federal OSHA requirements. Nebraska electric utilities are subject to the State Department of Labor (LB 757 1993) regulations on written injury prevention programs. Responding Nebraska utilities showed favorable OSHA Incident Rates compared to national statistics compiled by the Bureau of Labor Statistics.
There has been a national trend toward down-sizing of work force among private investor-owned utilities and large public power systems preparing for the pressures of competition. An emerging issue for the Nebraska work force will be the potential impact deregulation and competition might have on work force size, safety and service quality.
If vertically integrated utilities, or those that have more than the generation function, separate the various functions so that there is not an opportunity to shift costs between generation, transmission, and distribution; the safety, reliability, and other concerns should be minimize for the transmission and distribution functions. There would be no competitive advantage gained by unnecessarily reducing the work force if the transmission and distribution are cost-based, regulated and open for use to all providers. Rate unbundling would also help facilitate the separation. The competitive generation function, however, could be subject to the concerns mentioned.
The ability to generate and deliver electricity in a cost effective, reliable manner by taking advantage of advances in technology is critical to maintaining competitive rates, quality of service, customer satisfaction, and environmental compliance. The primary vehicle which electric utilities in the U.S. and in Nebraska use to conduct research and development of new technology is the Electric Power Research Institute (EPRI). Created in 1973 by the nation's electric utilities, EPRI is one of America's oldest and largest research consortia with about 700 utility members. By pooling resources, a wider spectrum of projects is possible than if each utility were funding research efforts individually.
Total EPRI funding for research, development and delivery in 1996 was $240.9 million. Nebraska electric utility members paid a total of $3,461,368 in 1995 dues. These utilities also have staff members (35) who serve on various EPRI business unit advisory and governing boards. In addition, they also contributed $607,410 for state and local research and $336,756 for other national research in 1995.
Research and development activities by EPRI included many projects. A few examples include renewable energy, superconductivity, electric and magnetic field effects, clean coal gasification, fuel cell, and acid rain.
Nebraska utilities are involved in utilization or active investigation of potential use or feasibility of use of many technologies, such as renewable generation, power quality, advanced metering, high efficiency HVAC, and ground source heat pumps.
If utilities are competing, there is less interest in joining efforts for advancing technology if it could result in loss of a competitive advantage. Large utilities may be able to justify spending money on technology, whereas small utilities may not. There is concern that advancement in some areas may be slowed with full retail competition.
5.8.3 Distributed Generation
Distributed generation is generation located at or near a customer or group of customers. It could be of a size to serve one or several customers. It could also provide energy other than electricity, such as steam, and be a cogeneration facility.
Many years ago, electricity generation was more distributed with many small units located at individual or groups of loads such as municipalities. As time went on, the economies of scale caused most generation to be of a large central station type and have transmission lines built to connect the plants to the loads and together for reliability.
In the future, distributed generation may once again play a more significant role in the electricity generation market. Consumer owned systems and individual consumers in rural areas could gain a significant advantage when distributed generation breaks through market-cost barriers. Efficiency gains, price reductions, and cogeneration could provide significant benefits. Public concern about adding transmission lines and siting of large generation plants could also play a role in favor of distributed generation as the need for additional generating capacity comes forward. Distributed generation today is primarily made up of diesel powered units or small combusion turbines. Fuel cells are also used and could gain significantly through efficiency gains and price reductions.
The potential for distributed generation must be given thorough consideration in long term plans for restructuring of the electric industry in Nebraska.
5.8.4 Renewable Energy
Contributions to Nebraska energy production from non-hydro renewable resources have been minimal to date. The non-hydro renewable energy generation option receiving the most attention at this time is wind energy generation. A joint Nebraska wind project of 1.5 MW was put into service in 1998 as part of an EPRI project and included KBR Rural Public Power District, NPPD, and Grand Island, LES, MEAN and Auburn. The Nebraska Power Association was involved in monitoring wind speed and solar data at eight sites across the state. The monitoring project was undertaken with the Nebraska Energy Office, the Nebraska Industrial Competitiveness Service, Nebraska Citizen Action and the Union of Concerned Scientists. (LES has installed one 660 KW wind turbine northeast of Lincoln and plans another.) Several utilities are also involved with installing solar powered stock watering systems.
Because most renewable technologies are not competitively priced, many states and federal restructuring proposals include various support mechanisms intended to promote renewable generation installations such that economies of scale might help to lower costs.
If portfolio standards are developed, it would be important to Nebraska to have hydro included as a renewable resource, particularly if hydro is included as "renewable" in federal legislation. Nebraska utilities have several hydro plants and WAPA provides significant hydro energy to Nebraska customers. (See Chapter 6 for more detail on renewables.)
As described in this chapter, Nebraska systems currently enjoy wholesale power rates below those of the region. It is important for Nebraska to accommodate expanded wholesale competiton in a manner that maintains low electric costs.
For the wholesale power supply level, the Task Force recommends methods to retain low cost wholesale power including examination of a Nebraska Power Transaction Center, a Nebraska Generation Cooperative Company, and mandatory participation in joint planning of generation. Additionally, the Task Force recommends on-going examination of the role of distributed generation and renewable energy resources.
At the Transmission level, the Task Force recommends: continued participation of transmission-owning systems in efforts to form a regional ISO, and also examination of a Nebraska Transmission Organization, and regional public power and consumer-owned ISO, as well as other methods to create greater efficiency for Nebraska's transmission network.
In terms of Regulation, the Task Force recommends that initial legislation be developed that includes the Nebraska Power Review Board as the initial regulatory body to coordinate work groups and hold hearings regarding proposed rules, standards, protocols, studies, and other preparatory work.The Power Review Board is urged to seek full membership status in the National Association of Regulatory Utility Commissioners (NARUC).41 The Task Force also recommends that the role of the ultimate statewide regulatory body to be authorized in implementation legislation augment the traditional roles of local boards overseeing delivery of electric service to consumers.
At the Distribution Level, the Task Force recommends modification of the Current Structure to enhance system operations and to prepare for the pressures of retail competition. Mergers and alliances should be voluntary, but incentives and criteria should be developed by the state. Divestiture should be assessed on a similar case-by case basis, using an income-based valuation methodology and criteria established by the state. Divestiture to another consumer-owned entity might be considered preferential to retain consumer equity and consumer control of facilities. However, any divestiture meeting necessary criteria should be allowed.
With specific incentives and criteria in place, laws and regulations could be changed to allow greater equity and latitude of business relationships and services by local distribution systems. This would allow all Nebraska consumers to receive benefits of multi-service packages that include electricity.
The Task Force recommends that a transition to retail competition should be undertaken only when preconditions are in place, and benefits offset transition and transaction costs. Each local system should be allowed to make a determination on whether to opt-in through its own public process. Competitive retail systems may be required to functionally separate distribution, transmission and generation operations.