In the Generic Electric Restructuring Docket
E-00000A-02-0051
March 22,2002
These are "clips" or "snippets" from a 234 page Report. No editing of words have been done, but no effort has been made to maintain total contextual relevance. My highlighting of a thread "red" for my emphasis and direction.
In the small customer market, the profitability of retail market entry has generally not been sufficient to over come the acquisition and aggregation costs for new suppliers, who have had to compete with the incumbent utility or other designated standard offer provider. Few suppliers have entered the small retail market aggressively, and retail customers have tended to remain with standard offer service.
As noted above, much depends on the relative prices of standard offer and market suppliers. The general problem is that shopping credits have been inadequate to make competitive service attractive. Putting it another way, commissions have made every effort to keep standard offer service prices down, and this has made the market un attractive to alternative suppliers and has given customers little incentive to switch.
It is now being recognized that the shopping credit must be significantly higher than the wholesale energy price if it is to be sufficient to attract customers to the competitive market and provide suppliers a margin of profitability. First, it needs to take into account the (often low) load factor of small customers, i.e., needs to include a cost to account for peak period usage and installed generating capacity. Second, a retail adder is required to cover marketing and other retailing costs.
Even in the states where retail competition has been deemed a success, stranded cost recovery has sometimes undermined customer migration to the competitive market. In Connecticut, for example, a stranded cost charge which is in effect an "exit fee" reduces the effective shopping credit.
For customers, is the cost associated with learning how to shop and actually shopping sufficiently small, relative to the expected benefits, that customers would want to shop.
The pro-competition view ignored this issue, assuming that customers would be eager and willing to shop for a good deal or for innovative services. However, states had doubts about customers’ ability and willingness to shop, and put standard offer service in place to provide customers with a reliable and reasonably priced fallback for electricity as an essential service. In practice, the continuation of full utility service by the incumbent utility, including standard offer service at favorable prices negotiated by state commissions, has thus far proved fatal to retail competition for residential and small commercial customers in most states. In addition, many small customers do not have the time, wherewithal, or interest to shop for a product that never captured much of their attention in the first place.
The Federal Energy Regulatory Commission is only gradually coming to grips with the
two principal features that are needed to make a wholesale generation market workably
competitive and reliable. The first is willingness and ability to root out horizontal market power by breaking up suppliers and removing barriers to entry. …
The second principal feature that must be put in place under the aegis of FERC before thegeneration market can be competitive is a well-designed RTO that can effectively monitor the wholesale markets, monitor and control transmission, price transmission services fairly and in such a manner as to broaden the market, design the expansion of the transmission system in coordination with power plant construction to avoid bottlenecks and supply disruptions, and ensure non-discriminatory transmission access to new generators.
The Commission’s Environmental Portfolio Standard (EPS) acts to promote the use of Renewable energy sources such as solar. Without the EPS, it is doubtful that these sources of generation could compete (based on cost) with traditional generation sources.
In order for distributed generation to become a significant source of generation, interconnection standards and processes need to be established. Over the years, the Commission has approved various cost recovery mechanisms and other procedures for demand-side management (DSM) as an incentive for utilities to consider cost-effective DSM instead of additional supply sources.
We see two major defects in Arizona's current wholesale market structure. One is that incumbent utilities have large shares of the generation (and transmission) market and, if that market is restructured, they would likely be in a position to exercise market power, by raising prices above competitive levels and/or discouraging new entrants. In such a situation the incumbent utilities would be reluctant to work towards relieving the transmission constraints that enhance their market power. Second, transmission constraints limit generator access to Arizona load centers.
Third, we believe that the ISO/RTO arrangements at this time are inadequately developed to ensure an open, competitive, and stable wholesale market. The cure lies primarily with the FERC, which is attempting to move forward on these matters. The development of WestConnect under the aegis of FERC will be critical in this respect.
In light of these three defects, we believe it would be prudent for the Commission to wait before requiring jurisdictional utilities to place substantial reliance on the wholesale generation market.
There are transmission constraints both inside and outside Arizona that currently impede competitors reaching Arizona customers during summer peak hours. These constraints were reported in Staff’s Biennial Transmission Assessment revised July 2001and adopted by the Commission. The report established that three geographical load zones (Phoenix, Tucson and Yuma) are transmission import constrained at peak load conditions. Generation internal to these load zones "must run" at peak load conditions to avoid system overloads and voltage problems for outage of critical lines.
Firm regional transmission capacity for competitive Electric Service Providers to import power to Arizona retail customers is also very limited and only available on selected transmission paths.
Is the natural gas pipeline infrastructure adequate to support all proposed new gas-fired generation plants? How many plants can it support?
The natural gas infrastructure in Arizona at this time largely consists of El Paso Natural Gas Company’s (El Paso) northern and southern interstate pipeline systems and associated laterals. The Transwestern pipeline in northern Arizona also serves a small amount of Arizona’s natural gas needs. Currently there are no appreciable instate natural gas production, natural gas storage, or liquid natural gas facilities in Arizona. Therefore, natural gas consumers in Arizona, whether residential or power generating in nature, rely on the on-going flow of natural gas on the interstate pipeline system to meet their service needs.
There is a general uncertainty regarding pipeline capacity availability for ship person the El Paso pipeline system. The rights, obligations, and needs of shippers and El Paso are being disputed in a number of proceedings at the Federal Energy Regulatory Commission (FERC). At this time it is unclear how or when the disputes regarding pipeline capacity will be resolved. However, it is clear at this time that during periods of high demand, the El Paso system is unable to fully meet the needs ofits existing shippers. During periods of relatively low demand on the interstate pipeline system, it appears that the system is generally able to meet the needs of its shippers. This situation exists at a time when few of the new natural gas-fired generating units are yet operational. As additional gas-fired generating units come on-line in Arizona and other southwestern states that utilize the same pipeline systems, the inability of the existing pipeline system to serve all customer demands will become increasingly apparent.
El Paso has failed to address the growing demands for natural gas transportation in Arizona and the Southwest. New generating facilities appear to be relying on a number of possible sources of pipeline capacity for their facilities, including: use of existing contract rights, acquiring released pipeline capacity from other shippers, purchasing rights on new pipelines or pipeline expansions, and swapping of gas supplies on different pipeline systems. In the longterm, market players are likely to build additional pipeline capacity and/or natural gas storage capacity to serve additional demand for natural gas in Arizona and the Southwest. However, it is unclear at this time how well the availability of additional pipeline capacity in the future will coincide with the additional natural gas demand of the new generating facilities in the next few years. The on-going uncertainty regarding existing shippers rights on the El Paso system has made it difficult for both shippers and potential capacity expansion developers to accurately gauge what the demand/need is for additional capacity. Most new gas-fired generating units in Arizona are located near ElPaso’s southern pipeline system, and this is likely to be the area of greatest concern regarding the shortfall of interstate pipeline capacity, although several recently announced pipeline projects may at least partially address the shortfall.
Does the transmission and distribution system facilitate or deter --
a. the development of renewable energy technologies?
Current transmission and distribution system structures deter the development of renewable energy technologies in three significant ways. First, on the local level, the small size and often remote locations of renewable generators mean that they are not directly connected to the regional bulk power system and often have to pay a distribution utility tariff in addition to the regional transmission tariff. Second, interconnection procedures in many regions do not provide streamlined procedures for interconnecting small generation units that have virtually no impact on the bulk power system. Third, the wholesale markets administered through tight powerpools do not accommodate the small size and often intermittent production output associated with most renewable generation, such as wind, hydro, and solar. Until these barriers are addressed and a level playing field is created, renewable generation technologies will be at a competitive disadvantage.
b. the development of distributed generation?
The same issues discussed above regarding renewable generation also apply to distributed generation. In addition, local distribution utilities have difficulty integrating and accommodating the power flows of distributed generation that may operate only during peak load periods. One solution to this difficulty is to require the distribution utility to purchase, through bids, distributed generation resources that it then operates.
c. the development of demand-side management and energy efficiency?
Although integrated resource planning in the 1990s quantified the significant benefits that energy efficiency, conservation, and load management can provide to distribution and transmission systems, there are very few mechanisms developed that capture these benefits. As mentioned earlier, Vermont has implemented a statewide efficiency utility that is supported through a systems benefit, or wires, charge. Alternatively, the RTO entity could provide incentives for demand-side programs based on the benefits to the bulk power system; however, the RTO may not be in a position to offer incentives for the distribution system benefits associated with DSM measures.
In a vertically integrated utility model, what incentives (regulatory, financial and ratemaking) exist for the expanded use of renewable energies?
In the simplest terms, in a vertically integrated utility model the incentives to expand the use of renewable energy exist in the form of approved generation plants that qualify for rate base treatment. If a renewable generator is easier to site and easier to include in rate base than a fossil-fueled plant, then the utility will favor the renewable generator even if its production costs are higher.
In many states, there are standards or goals (some voluntary, some mandatory) for expanding the use of renewable resources. To the extent that these standards and goals can only be met through the addition of new renewable generation units, then an incentive is in place that will encourage the expanded use of renewable resources.
There are currently only a few explicit incentives for use of renewables in the vertically integrated utility model. Some of the most commonly adopted explicit incentives in the nation are portfolio standards for renewables, system benefits charges, and renewable energy funds.
However, the Commission, in Decision No. 57589, the Commission's 1991 Integrated Resource Planning decision,found that environmental costs and other externalities must be considered by resourceplanners in making informed decisions about new electric energy resources and services. The Commission established a Task Force to identify and quantify environmental costs and externalities. The Externalities Task Force met during 1992 and published the "Report of the Externalities Task Force" in December 1992 (Docket No.U-0000-92-035). For the purposes of the Commission’s efforts, an externality was considered an impact on society not accounted for by the producers or consumers of electricity in the course of production or consumption of electricity.
In 1994, Staff commenced development of draft rule amendments to include externalities in the Commission's Resource Planning rules (R14-2-701 through705). Later in 1994, after California published its Blue Book on Restructuring and Arizona decided to move toward consideration of electric competition, the rule-making effort ended. The Commission later suspended portions of the Resource Planning rules.
If Arizona were to decide to continue with a vertically integrated utility model, the externality effort could be included in Resource Planning rules. Alternatively, the PowerPlant and Transmission Line Siting Committee could use externalities as a way to evaluate potential power plants before making recommendations on Certificates of Environmental Compatibility.
Since many renewables are generally less environmentally damaging than conventional, fossil fuel generators, the consideration of externalities could act as an incentive for renewables.
There are two commonly mentioned "incentives" for the development of renewable energy resources in acompetitive market: special retail products and renewable portfolio standards.
Special retail products refer to efforts by retail competitive suppliers to market products specifically tailored to consumer preferences. For example, Green Mountain Energy Resources (GMER) provided three distinct products to California consumers: a 60%, 75%, and90% renewable-based retail electric service. As consumers signed up, GMER committed to expand its contracts with renewable energy generators to maintain the advertised percentage of renewables.
Another approach to special retail products is a disclosure label that states, among other information, the resource mix of fuels that were purchased by the retail supplier. The thought is that consumers may want to switch to a supplier who provides a greater percentage of renewable resources in its fuel mix, thereby encouraging the development of renewable resources.
The second general incentive program for renewable resources is a renewable portfolio standard (RPS). Enacted either through state legislation or by commission rule, an RPS requires each retail supplier to have a minimum percentage of renewable resources in each product that it provides to consumers. Some RPS programs, such as the Environmental Portfolio Standard in
Arizona, also mandate a specific percentage of "new" renewables or specific types of renewables. There are also some federal and state tax credits that are available. One potential incentive would be the standardization of distributed generation interconnection procedures and agreements. Simplification of procedures and streamlining of interconnection hurdles could significantly improve the potential for new renewables development. Netmetering (or net billing) laws or rules would encourage customers to buy and install renewables on their own property. Renewable leasing programs or lease-to-buy programs would allow customers to utilize renewable systems even if the customer did not have the capital to install his/her own system.
One disincentive for expanding the use of renewable resources in the traditional model is the generally higher production costs currently associated with many renewable energy resources. In a regulatory climate that focuses on just low cost, the higher prices of renewable energy resources will often act to exclude them from consideration. While there are well-documented case studies to the effect that traditional low-cost resources are receiving significant subsidies or cause significant collateral cost impacts that are shifted to society as a whole (such as air pollution), traditional regulatory and ratemaking policies tend to discount or completely ignore these "societal costs."
There are financial disincentives for cooperatives that might be interested in incorporating renewables in their generation mix. Since cooperatives rely on RUS and CFC for financing, which require the least-cost generation resources, renewables that are more expensive than fossil fuel generators do not even get considered.
In a competitive electric market model, the lowest delivered cost per kWh is the driving force in decisions to add new generators. If renewables appear, in the short run, to be more expensive, they will not be considered, even though over the long-run, when considering potential fuel cost increases or fuel availability risks, the renewables may be a better long run choice. Many renewables are very capital intensive, but have little, if any, ongoing fuel costs. (The wind and sun are free.) On the other hand, many conventional generators, such as gas turbines, have extremely low capital costs, but also have the potential for extremely high-cost fuel impacts over time.
Under the vertically integrated utility model, what incentives exist to build newer plants that are less damaging to the environment to replace older, dirtier plants?
Very few incentives exist. Least-cost dispatch has always been the key in a vertically integrated utility model. Rate-basing of plants by the state regulatory commission provides the financial incentive for building new facilities. The commission may be able to mandate the construction of cleaner new plants, or at least can agree to rate-basing of those newer, cleaner plants. The new plants may render the older facilities uneconomic, but a further financial incentive may be needed, namely an agreement by the commission to allow continued recovery of any remaining depreciated book value of the older facilities.
Under the competitive electric market model, what incentives exist to build newer plants that are less damaging to the environment to replace older, dirtier plants?
Very few incentives exist. Similar to the response to Question #2 above, special retail products or a portfolio standard -- in this case related to low pollution or minimal environmental impact specifically -- could provide an incentive.
Although some would say that the next generation plants will be more efficient and cleaner than the older plants, this isn’t necessarily true. At the same time that a dozen or more gas-fired turbine plants are being built or proposed in Arizona, Tucson Electric proposes to build two new coal plants. It is entirely possible that the two new plants could partly or completely displace older, simple cycle gas plants that are "cleaner" than the new coal plants, at least in terms of the volume of air pollutants. There are no explicit incentives for "clean" plants, only incentives for the operator who can operate his plant at a lower cost than his competitors.
Under the vertically integrated utility model, what disincentives (regulatory, financial and ratemaking) exist to build newer plants that are less damaging to the environment to replace older, dirtier plants?
If older, dirtier plants are already receiving cost recovery in rate base, and there is uncertainty about the rate-basing of new facilities that may constitute "excess capacity, "a utility would have a financial disincentive to build the newer facilities without a green light from the legislature or commission. Likewise, if reliance on energy from newer plants involved departure from least-cost dispatch, a utility would have a financial disincentive, unless it received regulatory approval.
If older, dirtier plants are still operational and the plants’ fixed costs have essentially been "paid off," they can still continue to operate and compete against newer, cleaner plants that need to charge prices to reflect fixed costs, variable costs, today’s financing costs, and a competitive profit margin. In a state, such as Arizona, where the older plants have such an advantage, new competitors will not voluntarily install any pollution improvement if it will make their electricity less competitive.
Under the competitive electric market model, what disincentives exist to build newer plants that are less damaging to the environment to replace older, dirtier plants?
The disincentive is that the owners of the existing, dirtier plants, which may already be fully depreciated, will have no reason to build newer, cleaner plants, unless those plants are significantly less costly to operate than the older plants of their competitors. Since the environmental costs of the older, dirtier plants are not paid directly by the plant operators, as far as the operator is concerned, those environmental costs don't exist. Since price is king in the competitive model, any pollution-reducing extra costs would be seen by plant operators as making their product more costly, and, therefore, less competitive.
While a state may set rates for retail transactions, it may not set rates for wholesale transactions. Narragansett Elec. Co. v. Burke, 119 R.I. 559, 381 A.2d 1358 (1977),cert. denied, 435 U.S. 972 (1978). The task of setting wholesale rates belongs to the Federal Energy Regulatory Commission (FERC). The rates set by FERC can either be preemptive or nonpreemptive. When the transaction is nonpreemptive, the courts have recognized the authority of states to limit a utility's ability to recover FERC-approved rates. When the wholesale transaction is preemptive, FERC approval of the wholesale rate preempts the States from taking any action that limits the pass through of the wholesale costs. The crucial differences between the two lines of cases involve the factual circumstances of the transactions.
The second line of cases involves "trapped costs." Although the Supreme Court has not defined the phrase explicitly, its decisions indicate that a "trapped cost" occurs when (1) FERC issues a decision requiring the purchasing utility to take a particular action, while (2) the state sets the utility's rates as if the utility had made a different choice
Staff understands that, as a general matter, the divestiture or transfer of assets of vertically integrated utilities would result in loss of jurisdiction by the Commission over the divested entities and a loss of jurisdiction over wholesale contracts between the utility and the divested entity. The transfer of assets to a functionally separated division of the utility within the same corporation, as provided for by the Virginia commission, would not appear to result in a loss of jurisdiction by the Commission.
Yes, the generation price is likely to fluctuate with the price of natural gas. An orderly, competitive gas market would contribute to electricity price stability. So would fuel diversification by electricity generators. Price volatility and inflation are significant risks associated with a competitive market/
Residential choice is probably not a real option at the present time, given the lack of suppliers willing to service small customers.
It is conceivable that the small customer market could open up in time, and bring some benefits to those customers. Factors that could favor customer choice include the development of lower-cost advanced meters and interactive load controls for small customers, and greater seasonal and daily variations in wholesale market prices, which could together make real-time pricing economical. Another factor could be the development of customer aggregation, which would reduce customer acquisition costs for marketers.
Staff must consider what is in the best interest of Arizona’s consumers while affirming that we support a properly functioning competitive market. In doing so Staff recognizes that competition potentially could afford three principal benefits to Arizona’s consumers: price, choice, and innovation. Staff believes that, if the Commission chooses to remain committed to competition, the Commission should structure the transition to maximize these three potential benefits and to recognize an appropriate balance between them. Specifically, Staff does not believe that price benefits should be sacrificed in order to encourage consumer choice.
Adjustor mechanisms for standard offer service. At least one Arizona utility will be implementing an adjustor mechanism for its standard offer rates in the near future. In light of the problems with the development of a competitive wholesale market discussed in this Staff Report and in APS’ request for a variance, Staff believes it would be appropriate to reassess the need for such an adjustor mechanism.
Shopping credits and unbundling generally. The adequacy of the shopping credit (the cost a customer would not pay to their UDC if they take generation service from a competitor) has been identified as being highly significant in the development of a competitive retail market. Staff is opposed to imposing artificially high shopping credits in order to give an artificial boost to competitors. However, the shopping credits and unbundled rates now in effect, such as they are, should be examined in order to determine whether they are set at levels that are artificially low...
For customers, is the cost associated with learning how to shop and actually shopping sufficiently small, relative to the expected benefits, that customers would want to shop.
APS states that it largely depends upon the individual customer, although for large customers it is more likely that the costs of shopping are outweighed by the benefits. For small customers, because electricity bills have been declining in recent years, it is less likely that small customers will want to shop for electricity.
TEP states that it believes the cost of shopping for residential and small commercial customers has been an impediment to their participation in the competitive market. Large commercial and industrial customers have more resources to evaluate the benefits they would receive from participating in the competitive market.
AUIA states that unless customers are upset and dissatisfied, few will shop for alternative providers. An AUIA survey found that no customers will switch for less than 10 percent savings and many would not switch for less than 20 percent savings AES states that the potential savings from competition have been limited for Arizona customers because of the requirement for customers to pay off the utilities' stranded costs from past investments in power plants through a competition transition charge (CTC). The primary reason for the failing retail market in Arizona is that administratively set shopping credits are not calibrated to the market price for electricity. But in TEP's area, it is difficult for customers to make a price comparison because of the way the shopping credit is recalculated quarterly.
Electric Cooperatives
AEPCO, Southwest, and Sierra state that the Commission's legal workgroup had authored a volume of work which in large part answers these questions. AEPCO, Southwest, and Sierra further state that the Commission cannot authorize market-based rates and individually negotiated outcomes without amendments to Article 15 of the Arizona Constitution.
Environmental/Energy Efficiency Advocates
The LAW Fund states that current Commission regulation promotes the development of renewable energy resources through the EPS. This policy is or should be independent of retail electric competition. Several aspects of the Commission's regulations do deter renewable energy, such as inappropriately low buy-back rates paid to qualifying facilities because buy-back rates are set on avoided conventional generation costs. Also, the Commission should ensure that the utilities have uniform net metering tariffs and implement them properly. To promote distributed generation, the Commission may need to start a rulemaking process on interconnection. The Commission currently does not emphasize demand-side management and energy efficiency (DSM/EE) programs. The Commission could promote cost-effective DSM/EE by requiring utilities to implement installation, rebate, and market transformation programs.
How have the interim rate reductions for customers receiving standard service affected the ability or desire of generation suppliers to compete in Arizona retail markets?
Investor-Owned Utilities
APS does not believe that the rate reductions have had any long-term impact on the competitive retail market for ESPs. APS further states that the rate reductions have not impacted the wholesale generation market because a wholesale supplier in an efficient market would be indifferent as to whether it sold to APS, an ESP, or another participant. TEP believes that the interim rate reductions had a negligible effect on the entrance of new generation suppliers into Arizona because potential competitors react to market price signals not to the utility's cost-based rates.
Wholesale Power Producers
Panda states that it is not the standard offer rates that dictate whether wholesale competition is viable, although a competitive wholesale market will have a positive impact on retail rates. PG&E states that the rate reductions have not had any effect on its incentive and desire to supply the utilities affected by the rate reduction agreements. Reliant states that a competitive wholesale market can exist with or without a competitive retail market. Interim rate reductions make it more difficult for ESPs to compete against the incumbent.
Electric Service Providers
AES states that the interim rate reductions have negatively impacted the retail market because the rate reduction serves to further separate the shopping credit from the market price for electricity.
ElectricCooperatives
AEPCO, Southwest, and Sierra believe that interim rate reductions are not the cause for the failure of generation suppliers to compete in Arizona retail markets. Competitive generators could realize greater profits for far less effort by selling exclusively in the wholesale market.
Many still refuse to provide any product but hour ahead and other short-term sales in the wholesale market. The REDCs state that Navopache is the only REDC which has a stranded cost settlement, and this settlement resulted in permanent rate reductions.
Residential Consumer Advocates
Arizona Consumers' Council states that it is unknown what market decisions any one company makes and why. Several have left the Arizona market. RUCO states that the rate reductions probably have had some effect. The difference between current cost-of-service rates and market rates under perfect competition is probably minimal. Few retail providers could compete for even the largest retail customers under such circumstances, where the retail margin might be only 1-2 mills per kWh.
Industrial Consumers
AECC supports the standard offer rate reductions in the Settlement Agreements and opposes keeping standard offer rates artificially high to induce competition. Given the high wholesale prices in 2000 and early 2001, the rate reductions had no material impact on whether a customer opted to remain on the standard offer.
Utility Investors
AUIA states that it is doubtful that the rate reductions have had a material effecton competitive retail offerings.
Do Commission policies or legal requirements ensuring that utilities recover investments from ratepayers affect the prospects for competition in any market for which competition otherwise would be possible?
Investor-Owned Utilities
APS states that the regulated utilities' opportunity to recover non-competitive investments would not affect the provision of competitive services by ESPs. The prospects for new entry into a competitive market are more affected by the rate-regulated utility being the lowest-cost supplier because of economies of scale or scope.
TEP responds "no" because stranded cost recovery is based on above-market generation costs.
Wholesale Power Producers
AzCPA states that it depends on the structure of the recovery of the investments. For example, if stranded costs recovery were charged to all customers as a flat fee, then there would be little impact on the market. Panda states that stranded cost recovery under the rules can become an impediment to a fully competitive market, to the extent such recovery reduces a party's incentive to seek competitive supply.
PG&E states that stranded cost recovery can impact the robustness of short-term retail competition. In the case ofAPS, both the accelerated amortization of regulatory assets and the low level of the generation credit are contributing factors to the inability of ESPs to offer significant savings to customers. This situation has contributed to several potential ESPs withdrawing from Arizona.
Reliant states that a policy that ensures recovery of past utility generation investments from ratepayers does not necessarily impact the prospects for wholesale competition. Depending on the design of the CTC mechanism, recovery of past utility generation investments can impede the functioning of the competitive retail market. Commission policies should be designed to foster reliance on competitive wholesale markets so that future investment risks are borne by shareholders and not ratepayers.
Does continuing utility control of depreciated generation assets affect the ability of competing suppliers to enter retail markets?
Investor-Owned Utilities
APS and TEP state that utility control of depreciated assets does not affect the ability of competing suppliers to enter retail markets. APS further states that the presence of those generating assets in the marketplace, regardless of ownership, will affect the decisions of potential competitors with respect to market entry.
Wholesale Power Producers
The AzCPA states that it does. Allowing utilities to recover investments from ratepayers through a rate base mechanism will adversely skew the market in favor of the utility generation and will not result in the lowest costs to customers. Panda states that the problem would be..
mitigated if the assets are taken out of rate base; the utility is required to procure all of its needs at arm's-length in the competitive market or through bilateral, negotiated agreements; and the transmission system is made available on an equal basis to the utility generators. PG&E responds that it may, depending on how that control is exercised. Reliant states that the ability of competing suppliers would be negatively impacted if generation assets remain in the regulated utility. The preferable market structure is where competitive aspects of electric service are separated from monopoly services.
Electric Service Providers
AES responds "yes" and believes that if utilities are allowed to retain their depreciated generating assets, they should only be used to serve core customers (residential, small commercial and industrial customers having less than 50 kW demand), because these small customers deserve a known, fixed default electricity price. AES further believes that larger customers should be required to procure their electricity supply from the open market, because those customers have the sophistication and resources to look after their own supply requirements.
How does current Commission regulation promote or deter the ability of(1) renewables,(2) distributed generation, and (3) energy efficiency and demand side management to compete with traditional generation resources?
Investor-Owned Utilities
APS and TEP state that the Environmental Portfolio Standard (EPS) promotes the ability of renewable energy resources to compete with traditional resources.
APS states that the Commission is working on interconnection standards and processes for distributed generation, which may aid the deployment of distributed generation resources.
TEP states that current regulatory orders will not affect the decision of customers to select distributed generation options, but that appropriate tariffs for distributed generation are needed.
APS also states that when the EPS was passed, the Commission elected to cease significant funding for DSM programs. TEP states that Commission mandates for DSM spending promote competition between DSM technologies and traditional generation resources, but that DSM has evolved into a competitive service provided by energy service companies.
Wholesale Power Producers
Reliant states that the Environmental Portfolio Standard promotes investment in renewables. Reliant is not aware of any action to implement the suggestions provided in the Final Report from the 1999docket on distributed generation. The Commission should promote competitive wholesale and retail markets so that demand-side management can compete with traditional resources.
Electric Cooperatives
The REDCs state that the Environmental Portfolio Standard and corresponding surcharge promote the ability of renewable and distributed generation to compete with traditional generation resources. The REDCs believe in the value of allowing customers to choose these programs rather than mandating subsidies. The market place will determine which energy efficiency and DSM programs compete with traditional generation resources.
Residential Consumer Advocates
Arizona Consumers Council states that if the Commission does not encourage renewables, etc., those energy sources will not be able to compete with traditional sources that are already not paying their fair share. The Commission must work with these producers to insure that all new energy sources become part of the mix and pricing moves to cost.
Industrial Consumers
AECC states that with regard to distributed generation, the Commission should ensure
that standby service rates and interconnection requirements are reasonable.
Environmental/Energy Efficiency Advocates
SWEEP states that current Commission regulation promotes renewables through the Environmental Portfolio Standard. The EPS should remain in place even if the Commission decides to suspend or abandon retail electric competition. In addition, the Commission should review buy-back rates and ensure consistent and effective net metering tariffs. The Commission should increase support for distributed generation with interconnection rules to ensure a reliable and safe grid without erecting undue barriers to distributed generation. The Commission should require a distributed resources plan as part of the Ten-Year Plans. Current Commission regulation provides little support for DSM and energy efficiency programs. Energy efficiency programs supported by ratepayer funding are needed for reduced societal costs for electric energy services, reduced electricity market prices, reduced customer bills, less environmental damage, and a more reliable electric system.
Utility Investors
AUIA states that widespread use of distributed generation would require rulemaking and tariff filings to clarify numerous issues like planning and notification, access to the grid, security, standby pricing, and potential stranded costs.
Renewable Energy/Cogeneration Providers
ACEIA states that the EPS balances the need for sound environmental policy with sensitivity to energy users' concerns, but that the rule should be applied to all Arizona utilities. The EPS should be retained regardless of actions on the overall issue of electricity restructuring.
The Commission should proceed with distributed energy rulemaking, including rate reform that reflects time and day usage, interconnection, net metering, and reasonable transmission service fees. ACEIA believes that the Commission's lack of access to utility planning information under competition limits the Commission's ability to carry out a planning oversight function.
What are the risks of moving to a regime of retail competition for each product or service and what are the methods for managing those risks?
PG&E states that there is sufficient generation coming on-line to meet supply. This competition will encourage the competitive purchase of generation for which consumers will be the ultimate beneficiaries. Reliant states that the competition rules form a sound basis for the transition to fully competitive electric markets, and therefore the risks of a California-style meltdown have been effectively managed. The Commission should proceed with the competitive resource procurement process to ensure a well-functioning wholesale market. With respect to retail services, the Commission should ensure that the shopping credit is sufficient, require utilities to provide better information related to retail competition, and require utilities to unbundle their standard offer tariffs.
AEPCO, Southwest, and Sierra and the REDCs state that rural areas are at particular risk because they are not desirable markets generally. The loss of certain desirable loads drives up costs for remaining customers. AEPCO, Southwest, and Sierra further state that managing those
risks requires a recognition of these issues and special treatment concerning rural areas. The REDCs believe that retail electric competition will not benefit rural Arizona and will only bring rate instability to these areas. There is little that the Commission can do to minimize these risks without re-regulation.
Arizona Consumers Council states that risks are higher prices, less reliability, safety concerns, and dropping certain consumers from the market. Bankruptcy of certain companies will put the system and consumers at risk. Without a regulated back-up system, we could all be in trouble.
RUCO states that a power pool might be one way to manage risks, but the West is not ready for such a concept. Another method for managing the risks is to maintain a regulated price cap in the form of the standard offer, at least for small customers. A price cap should be re-done periodically on a cost-of-service basis.
All competitors should be on a level playing field. Panda stated that, specifically, APS and TEP have requested that they be freed of their obligation to competitively procure power to serve standard offer customers. Panda further states that the Commission should deny the requests. Reliant responds that the APS variance request would undermine both wholesale and retail competition. The Commission should deny the request and proceed with implementation of the current competition rules. Sempra states that the APS variance request appears to be trying to lock in some high prices before competition hits. The Commission should deny the request.
Identify with particularity any defects in the wholesale market structure affecting Arizona.
APS states that there is insufficient competing generation not already committed to other loads, there are load pockets where local generation must run, and there is not yet an RTO. TEP states that there are some transmission constraints that restrict some generation transfers.
AzCPA and PG&E state thatthe primary problem facing the wholesale market today is the lack of a functioning RTO. Panda states that the wholesale market structure in Arizona would be competitive both in theory and in fact if allowed to develop in accordance with Commission and FERC rules Current AISA protocols require the price for must-run generation to be cost-based.
Is the natural gas pipeline infrastructure adequate to support all proposed new gas-fired generation plants? How many plants can it support?
APS and TEP do not believe that the current gas pipeline infrastructure is adequate to support all of the current and proposed gas-fired generation.
Panda states that nearly all major interstate gas pipelines in the WSCC have strategic long-term plans to increase deliverability to match expected increases in power and non-power sector gas sales. Reliant states that proposed pipeline additions, if all built, would add 1.5 Bcfd in capacity, and proposed storage projects are estimated to total 1.7 Bcfd in capacity. The proposed projects would support an additional 16, 500 MW power plants.
The Law Fund states that current transmission and distribution system conditions facilitate development of renewable energy technologies in the sense that congestion on transmission lines increase the value of generation located near load centers. Because of the environmental and other difficulties of siting new conventional power plants in metropolitan areas, distributed renewable energy resources can play an important role in serving metropolitan area consumers. The Commission's review of proposed transmission investments should include a comparison of the costs of such investments with the cost of renewable energy generation distributed within load centers. The Commission should ensure that distribution system planning seeks out cost-effective use of renewable energy as an alternative to system upgrades. Uncertain future transmission planning and pricing policies adversely affect generation from large scale renewable energy projects.
b. the development of distributed generation?
Investor-Owned Utilities
APS states that utility delivery systems have not been planned to interconnect with distributed generation (DG), thus requiring investments that should be recovered from those who impose the costs to deter unsound investments. TEP does not believe that the transmission and distribution system either facilities or deters the development of DG.
AECC states that the transmission and distribution system neither facilitates nor deters the development of distributed generation. The greatest institutional barrier to distributed generation is the structure and pricing of utility standby service tariffs and demand ratchets.
Environmental/Energy Efficiency Advocates
The LAW Fund states that current transmission and distribution system conditions facilitate development of distributed generation in the sense that congestion on transmission lines increase the value of generation located near load centers. SWEEP states that transmission and distribution system planning and operations do not adequately consider distributed resources as cost-effective alternatives to transmission or distribution investments.
Arizona Consumers Council states that if we have a truly robust market and new technology is available and in use, competition should keep prices down. A bottleneck transmission system and rising spot prices could lead to higher prices, less reliability, and less choice. If utilities purchase all or most of their energy from their affiliates, would they get the lowest price? RUCO states that retail customers probably would not be adversely affected by such a variance, provided that power remains available to customers on a cost basis.
RUCO states that if customers receive cost-based rates, then competition will have to produce a price that is below marginal cost...
RUCO states that if the contract provides power at cost, then consumers would have an advantage because market prices are likely to be higher in the long run than cost-based prices. A long-term contract would better protect consumers from price volatility.
ACEIA discusses two Congressional acts. The Securing America's Future Energy Act H.R. 4 impacts Arizona's treatment of renewables and distributed generation by encouraging these methods. The Renewable Energy and Energy Efficiency Act of 2001 (S. 1333) focuses on a nationwide renewable portfolio standard.
APS states that the Arizonawholesale market is reasonably competitive. In the near term, improvement in supplyand demand balances will continue to take pressure off of prices and supply adequacy. Arizona transmission owners and users will be part of WestConnect.In the near term, there will be excess generation supply. Competitive wholesale prices in Arizona will continue to be driven by prices in California. Mass-market retail access may not take root if customers can remain on standard offer service at prices at or below market.
TEP believes that unless factors that are beyond the control of regulators, utilities, ESPs and customers are properly accounted for or controlled, the Arizona competitive retail market will develop slowly. TEP further states that one of the most critical of those factors is generation price volatility in the wholesale market. The art of balancing regional supply and demand without a regulatory mandate and delivery infrastructure issues must be addressed before a robust competitive retail market can exist in Arizona. TEP suggests that Arizona should encourage the development of additional generating resources and/or load management and encourage the development of additional transmission, new gas pipeline, or railroad infrastructure. TEP also states that price volatility must be balanced between shareholders and customers.
Wholesale Power Producers
Panda states that the Commission's Rules and the 1999 Settlement Agreements offera well-constructed framework for wholesale and retail competition. There is no reason for the Commission to back track in any way from the Rules. Competitive generators stand ready to bid for the right to serve standard offer customers or to negotiate bilateral contracts with Arizona utilities to supply reliable power at competitive rates. If the Commission bows to pressure and removes the significant capacity represented by standard offer service from the competitive market, the competitive wholesale market will be irreparably damaged, driving some participants from the market and driving up future prices by reducing supply. There is little hope for effective retail competition without a competitive wholesale market. PG&E supports competitive bidding of standard offer retail service as the cornerstone of retail electric competition in Arizona. The Commission can measure the program's success by the MW and MWh competitively procured annually and the price(s) associated with them. The Commission has an important market-monitoring role and should respond negatively to APS' request to allow Pinnacle West to become its full requirements provider. PG&E hopes that the Commission will allow Arizona's retail customers to remain eligible for direct access service.
The possibility that retail customers in large numbers might one day choose alternative providers is a powerful incentive for both incumbent utilities and competitive suppliers to moderate prices.
Reliant states that it supports the vision statement contained in FERC staff's recent concept paper and believes that Arizona's electricity markets are likely to develop in a manner.. consistent with that vision. The FERC staff vision statement states that by 2006-2011, electricity will be purchased and sold in both wholesale and eligible retail markets by any willing creditworthy participant. Wholesale markets will have the following characteristics: energy-related products will be fully unbundled, there will be few barriers to entry and exit, market participants will not be able to exercise market power, market institutions will exist that maintain market transparency and keep transaction costs low, good market-driven price signals will exist to support generation and transmission investment, buyers will receive accurate and timely price signals, non-investor-owned entities will be allowed to join regional organizations, there will be wholesale competition in states that do not have retail choice, and the wholesale market structure in states with retail choice will not prevent anyone from purchasing the products and services necessary to buy or sell delivered electricity.
AEPCO, Southwest, and Sierra and the REDCs state that they have grave doubts as to whether retail competition will develop and benefit rural Arizona. Experience in the airline, banking, and telecommunications fields demonstrates that such initiatives usually leave rural areas unserved or underserved. Wholesale competition may offer new opportunities to acquire, through various means, least cost resources throughout the state. The REDCs believe that the focus of competition should be on the service areas of APS, SRP, and TEP where conditions are more favorable to competition. The REDCs should be exempted from the Retail Electric Competition rules at least in the near term.
Environmental/Energy Efficiency Advocates
The LAW Fund believes that wholesale competition is viable in Arizona as numerous independent power plants currently and will in the future sell electricity to retail utilities. Retail competition is not very viable. The LAW Fund believes that society would be better off with greater deployment of renewable energy, distributed generation, and demand-side management. Benefits include lower long-run costs of meeting the demand for electric energy services and improved environmental quality. The Commission should continue to pursue policies in these areas regardless of whether the market is open to competition.
SWEEP states that markets should have both a supply side and a demand side, markets should provide options for all customers, markets should be diverse and resilient, markets should value geographic-specific and time-specific nature of energy use, markets should consider options, there should be protections against market power. Energy efficiency and other demand-side and distributed resources can help meet the needs of Arizona customers in a cost-effective, reliable, and clean manner.
Renewable Energy/Cogeneration Producers
ACEIA states that by furthering the EPS and implementing new rules for distributed generation, utilities will have to modify their long term planning. ACEIA envisions an expansion in renewables and distributed generation in Arizona...
Environmental/Energy Efficiency Advocates
The LAW Fund stated that the incentives for expanding the use of renewable energy in a vertically integrated utility model are: renewable portfolio standards, reasonable assurances of cost recovery, requirements for utilities to purchase energy from qualifying facilities at the utility's avoided cost, tax incentives, financial incentives, consumer demand for green energy, and public relations benefits.
Utility Investors
AUIA states that the Commission can authorize funding and/or a pass-through mechanism to encourage the use of renewables either on the utility's system or for the end user.
Renewable Energy/Cogeneration Producers
ACEIA states that the key incentive is that there is reasonable assurance of cost recovery of investments in renewable energy. Other incentives include system benefit charges, voluntary green pricing programs, federal and state tax incentive programs, and Federal cost-shared research and development.
2. In a competitive electric market model, what incentives exist for the expanded use of renewable energies?
Investor-Owned Utilities
APS and TEP state that profitability is the primary incentive in a competitive energy model. APS adds that instates where the free market has been considered inadequate, regulators have developed programs to encourage green power. TEP adds that financial incentives, such as federal production tax credits and renewable portfolio requirements, have driven the development of renewable generation resources in the competitive marketplace.
Wholesale Power Producers
Panda states that a competitive electric market model may promote the use of renewable energies more than a vertically integrated utility model. Electric providers have the opportunity to differentiate a commodity product by marketing green energy. In states with retail electric competition, consumers have been willing to pay a premium for green power. In Arizona, studies have shown that a significant number of customers are willing to pay a premium for renewable energy resources...
PG&E states that mechanisms to encourage the use of renewable energy include:a renewable portfolio standard, a system benefits charge to collect money for grants, and incentives such as low-interest loans and tax credits. It is important to have a balance between encouraging the development of new sources and taking advantage of renewable resources that currently exist. In the long term, a highly competitive market will encourage the development of renewable resources.
Reliant states that in competitive markets, green tariffs have been replaced with specialized customer product offerings that often contain premiums for the portion of energy use derived from renewable sources. Competition motivates retailers to offer a diverse portfolio of renewable products and related marketing to attract consumers.
Electric Cooperatives
AEPCO, Southwest, and Sierra and the REDCs state that there generally are no incentives, but competitors may seek out niche markets for renewable applications.
Residential Consumer Advocates
Arizona Consumers Council states that there are incentives only to the degree that renewable sources can compete monetarily with what is in place today. Incumbent utilities have a guaranteed rate of return on investment, and renewable energy cannot compete with it. Renewable energy technology has not yet reduced its cost sufficiently to compete without incentives.
IndustrialConsumers
AECC states that the first incentive power producers will look for is economic.
The surcharge/subsidy approach may also be used in a competitive model.
Environmental/Energy Efficiency Advocates
The LAW Fund stated that the same incentives are applicable in a competitive electric market model, assuming that electricity derived from renewable energy costs more than conventionally generated electricity.
Utility Investors
AUIA states that the situation remains the same for the UDC. Retail competition in some jurisdictions has indicated that there may be a market among residential customers for green power.
RenewableEnergy/Cogeneration Producers
ACEIA states that minimizing costs drives decisions in a competitive model..
In a vertically integrated utility model, what disincentives (regulatory, financial, and ratemaking) exist for the expanded use of renewable energies?
Investor-Owned Utilities
APS states that regulatory disincentives include requiring least cost resources and disallowing the higher cost of renewable energy resources in rates. TEP states that the high costs of developing renewable energy technologies and reliability questions are the primary constraints to renewable generation. Investment risk is better managed under a vertically integrated utility model.
Wholesale Power Producers
PG&E and Sempra state that the incentives or disincentives a vertically integrated utility has to provide renewable power are dependent on the regulatory parameters in which the utility operates. Some of the same mechanisms are available under both models. PG&E further states that it is unlikely that a significant supply of renewable power will develop under a vertically integrated utility model until the state decides that it is in the public interest for ratepayers to have access to renewable power. A competitive retail market is the best means to encourage consumers to purchase renewable power.
Reliant states that green tariffs provide minimal incentive compared to that of the competitive model. Unless instructed to do so, vertically integrated utilities do not have the incentive to execute long-term power purchase agreements required to stimulate investment in renewables.
Electric Cooperatives
AEPCO, Southwest, and Sierra and the REDCs state that renewables often cannot meet the regulatory goal to deliver power to the consumer at least cost. A regulator may mandate renewable requirements but not provide a revenue stream sufficient to support them.
Residential Consumer Advocates
Arizona Consumers Council states that the only disincentives are those which regulatory commissions place if requests are made to use higher than average costs. On-site renewable energy does not bring income to the utility, so they are reluctant to use it.
Industrial Consumers
AECC states that the primary disincentive is economic. For some technologies, there is a disincentive with respect to unit availability. Another disincentive is concern that investments made on the basis of a subsidy will lead to additional stranded cost in the future if the subsidy is removed...
Environmental/EnergyEfficiency Advocates
The LAW Fund states that disincentives are: the high cost of renewable energy, lack of information about cost-effective applications, failure to consider the value of stable prices, and utility perceptions that renewable energy technologies should not be used because they are not dispatchable.
Utility Investors
AUIA states that cost is the major disincentive, although the Commission has greater ability to provide subsidies under the integrated model.
Renewable Energy/Cogeneration Producers
ACEIA states that disincentives are the higher capital cost and the higher risk of renewable energy technologies. Another disincentive is a utility bias for business as usual.
In a competitive electric market model, what disincentives exist for the expanded use of renewable energies?
Investor-Owned Utilities
APS states that most competitive firms have higher required rates of return than do
Panda states that no inherent disincentives exist in a competitive electric market model for the expanded use of renewable energies. Product differentiation is a cornerstone of effective product marketing, and product choice will expand in competitive marketplaces.
PG&E states that disincentives are often the lack of a market for the output of renewable generation and the lack of recognition of the benefits of renewable energy. Some transmission-related issues at the wholesale level must be addressed for intermittent generation sources. State air quality programs are away to communicate and reward the contribution of renewable energy.
Reliant states that in competitive markets, protocols on scheduling and settlement can create a disincentive for intermittent renewable energy such as wind power.
Electric Cooperatives
AEPCO, Southwest, and Sierra and the REDCs state that renewable energies are normally more expensive...
Residential Consumer Advocates
Arizona Consumers Council responds that a disincentive is the cost of producing renewable energy versus the existing cost of energy. New technologies must be able to produce energy cheaper to be useful in such a market.
Environmental/Energy Efficiency Advocates
The LAW Fund states that disincentives are: the high cost of renewable energy, lack of information about cost-effective applications, failure to consider the value of stable prices, risk that the utility will not recover costs, and utility perceptions that renewable energy technologies should not be used because they are not dispatchable.
Utility Investors
AUIA states that cost is a disincentive. Except for niche marketing, generators have no incentive to use renewables.
Renewable Energy/Cogeneration Producers
ACA states that very few distributed generation plants have been constructed in Arizona in the last five years because of well established barriers to grid interconnection and the uncertainty regarding deregulation and electric rates. The Commission needs to adopt standard interconnection requirements and an application process, and put in place DG tariffs, including partial requirements and standby rates.
ACEIA states that utilities meeting the EPS requirements by purchasing power from an independent power producer are unwilling to make the contractual time period long enough to reduce the cost. The lack of information in competitive markets is onerous.
Under the vertically integrated utility model, what incentives exist to build newer plants that are less damaging to the environment to replace older, dirtier plants?
Investor-Owned Utilities
APS states that over time a utility will build new capacity to meet growing demand, and newer plants generally operate cleaner than older plants. Incentives are economic and regulatory. TEP states that new generating plants are traditionally built only when there is a.. need and owners believe that they will be able to earn a reasonable rate of return. Existing plants are removed from service when they no longer operate efficiently or are no longer needed.
Wholesale Power Producers
PG&E states that it is not aware of any past, present, or future plans by incumbent Arizona utilities to replace older, dirtier plants. Since most of the capital costs of these plants have already been recouped, the plant owners have every incentive to keep them on-line. Reliant states that there are none, unless mandated to do so by the Commission.
Electric Cooperatives
AEPCO, Southwest, and Sierra and the REDCs state that an incentive may exist to
remain with installed, depreciated resources under either regulation or competition. On the other hand, newer more efficient plants may be constructed if they are economically beneficial.
Residential Consumer Advocates
Arizona Consumers Council states that the Commission has authority, under the Constitution and Commission rules, to insist on compliance with environmental programs and to start shifting use to plants which are cleaner and comply with environmental orders. RUCO states that the competitive electric market and the vertically integrated utility models do not necessarily cause utilities to replace older, more polluting plants with cleaner plants. In either environment, the older coal-fired plants will have lower variable costs and lower fixed costs due to substantial depreciation.
Industrial Consumers
AECC states that there is not a lot of incentive to do this unless the new plant can be put into rate base.
Environmental/Energy Efficiency Advocates
The LAW Fund states that there are no incentives under either model for generator owners to replace older, dirtier plants. Under the regulated model, SRP and the co-owners of the Navajo generating plants agreed to retrofit the plants to reduce sulfur dioxide emissions. It is uncertain whether they would be as willing to do so in a competitive market since their costs would increase. Recovery of the capital costs of traditional base load plants (coal-fired or nuclear) has been sufficient to keep regulated utilities in business.
Utility Investors
AUIA states that if any plant is in compliance with environmental standards, there is no incentive to replace it unless it has reached the end of its useful life or major efficiency improvements can be achieved...
APS states that the incentives are the same as under the vertically integrated model.
Stricter environmental regulation raises the costs of older units and reduces the costs of newer units. TEP states that the primary incentive to build a new plant in the competitive marketplace would be that it has an economic advantage over competing plants.
Wholesale Power Producers
Panda and Reliant state that new cleaner plants will replace older dirtier plants under the competitive electric market model because the older plants are more costly to operate. Without competitive pricing of generation, there is little incentive to build new plants to replace older, dirtier, less efficient, more expensive plants.
PG&E states that the siting process under the competitive model results in proposed plants conforming to today's environmental requirements as compared to the existing vintage plants that have not been required to meet current environmental requirements.
Electric Cooperatives
AEPCO, Southwest, and Sierra and the REDCs state that an incentive may exist to remain with installed, depreciated resources under either regulation or competition. On the other hand, newer more efficient plants may be constructed if they are economically beneficial.
Residential Consumer Advocates
Arizona Consumers Council states that if newer plants can be built that are less damaging to the environment and produce energy for less than existing plants, they will sell energy as long as competition is on a level playing field.
Industrial Consumers
AECC states that competitive generators would not build new plants for the express purpose of replacing older, dirtier plants. However, as generation supply increases, inefficient plants are likely to be "out of the money" on an increasingly frequent basis, except in must-run
conditions.
Environmental/Energy Efficiency Advocates
The LAW Fund states that in a competitive market, investment decisions are motivated by expected financial returns...
Industrial Consumers
AECC states that older plants have the advantage of being heavily depreciated and therefore cost little in rate base. In addition, their typically higher operating costs are fully recovered as an operating expense in rates. An older plant may have a locational advantage where it provides voltage support and/or relief from load pocket congestion...
Utility Investors
AUIA states that if the older plants are in compliance, the ratemaking regime does not contemplate removing plants from service that are used and useful and adding new facilities that are not needed to rate base. It could be dangerous to sacrifice fuel diversity for a marginal environmental gain.
Under the competitive electric market model, what disincentives exist to build newer plants that are less damaging to the environment to replace older, dirtier plants?
Currently, is residential choice a real option? If not now, when?
Investor-Owned Utilities
APS and TEP comment that residential retail choice is not currently an option. APS states that the wholesale market must become less volatile or ESPs must garner enough non-residential business to allow them to hedge a volatile wholesale market to the point where they can offer residential customers price stability and predictability.
Wholesale Power Producers
Reliant comments that given the current state of the Arizona market, a competitive retail market is unlikely to develop for several years.
Electric Cooperatives
The REDCs comments that residential choice is not currently an option and a prediction of when it would be a viable market is to far into the future. The REDCs states that Navopache's service area is the only service area of the REDC that has been open to competition since June of 2000. REDC also states that since the territory has been open to competition there has never been any interest expressed by an ESP to provide competitive electric services and none of Navopache's customers has expressed interest in receiving competitive electric service.
Residential Consumer Advocates
Arizona Consumers Council comments that residential choice will not be an option for many years, if ever.
Industrial Consumer Advocates
AECC comments that residential retail choice does not appear to be an economic option in Arizona but it may become more viable once stranded charges are paid off...
Utility Investors
The AUIA states that there is no retail choice today, but no one is buying or selling. The AUIA comments that we don't know when retail choice will make sense but, continue to doubt that retailers will overcome the transaction costs involved in residential service particularly as long as the gap between wholesale and retail prices continues to shrink.
What provisions, if any, are necessary to effectuate a gradual replacement of those existing plants in Arizona which are older, more polluting and less efficient than the newer combined cycle plants currently being built?
Investor-Owned Utilities
APS suggest that the Commission should pursue an energy policy that recognizes the value of the older coal-burning plants instead of prematurely decommissioning and replacing them. APS further comments that a policy that allows continued operation of the older plants avoids the need to reimburse APS and other utilities for sunk costs and investments in new plants. APS further states that retaining the existing plants and ensuring that they run efficiently and cleanly makes sense because retaining coal burning and nuclear units will provide diverse fuel sources. APS states that its coal burning units employ clean and efficient technologies, the location of these plants are in remote locations with a low population density, and replacement of these units would cause an economic disruption to the Navajo and Hopi reservations in northeastern Arizona. TEP states that new plants will be built if the owners believe that new generation plants will be built if the owners believe that they will earn an acceptable rate of return on their investment. TEP also states that owners of existing facilities will remove existing facilities from service if they do not believe that additional expenditures for capital costs and operating costs will earn an acceptable rate of return. TEP comments that regulators provide the incentives to the regulated entity through the recovery of cost for the new asset and stranded cost of the old asset. TEP also comments that if newer more efficient generating units can generate electricity at a lower incremental cost than older units they will be dispatched before the older unit, thereby decreasing the output of the older unit.
Wholesale Power Producers
Panda states that the most effective way to determine which plants should be retired is by establishing a level playing field through applying regulatory policy such as environmental policies to all market participants. Panda further states that the older plants should be responsible for the additional cost associated with meeting environmental restrictions as would any merchant generating facility. Panda comments that the older dirtier plants will continue to be cross-subsidized by ratepayers and their owners will have no incentive to remove them from service.
PG&E and Sempra Energy Resources comments that incentives to decrease transmission constraints and increase the import capability into the Phoenix metro area will accelerate the.. retirement of these older, less efficient polluting units. PG&E also states that a functioning RTO would facilitate the process.
Electric Cooperatives
AEPCO, Southwest, Sierra and the REDCs state that no regulatory provisions are necessary to replace older plants with newer ones because it will happen on its own over the next few years as the plants will require major replacements to remain useful.
Residential Consumer Advocates
Arizona Consumers Council comments that the older plants will stay in service as long as they are profitable and meet minimum pollution standards. Arizona Consumer Council suggests that the Commission should provide incentives for generators to increase technology and utilize assets that are low polluting.
Industrial ConsumerAdvocates
AECC comments that inefficient plants are generally more costly to operate than modern, energy efficient plants and as generation supply increases due to competition, inefficient plants are likely to be "out of the money".
Utility Investors
The AUIA states that fuel diversity is essential to price stability and reliability. The AUIA comments that coal burning units are only less efficient than combined cycle plants when the price of gas is low and when they are located outside the load centers, they may have no negative effect on the environment.