Submission of Aegent Energy Advisors Inc.

Transcription

1 Submission of Aegent Energy Advisors Inc. Ministry of Energy s Consultation Paper Action Plan to Lower Hydro Bills: Enhancing Supply and Competition in the Ontario Electricity Marketplace January 22, 2003

2 Introduction On December 23, 2002, the Minister invited large commercial and industrial electricity users and stakeholders to submit comments and recommendations on steps that could be taken to enhance competition and increase supply in Ontario s electricity market. Aegent Energy Advisors Inc. welcomes the opportunity to make this submission. Aegent Energy Advisors Inc. is a consulting firm providing objective analysis and advice to assist large energy users to reduce the cost, manage the risk, and resolve the complexities of their energy purchases. Aegent does not produce or sell energy. Aegent has worked with industrial, commercial, and institutional electricity consumers during the years leading up to market opening, and throughout the period since market opening. Aegent s involvement has included price risk analysis, supply portfolio development, supplier evaluation and selection, contract negotiation, and settlement support, for both wholesale market participants and embedded loads. Aegent is well-familiar with the operation of the market, and the strategies available to large volume power users. In addition, Aegent s experience includes involvement in the deregulated natural gas market since its inception in Canada. The natural gas market has evolved over the last 17 years, and is now a wellfunctioning commodity market that has demonstrated the efficacy of market forces in ensuring the competitiveness and adequacy of supply of an essential energy commodity. Basic Principles In his letter inviting comments from interested parties, the Minister indicates the government s commitment to a competitive electricity market: The government is committed to the view that by enhancing competition and incenting the creation of new supply, Ontario consumers will benefit from lower prices than could have been achieved under the old monopoly regime. Aegent shares the view that a competitive market in generation provides the model for ensuring the long term adequacy of Ontario s power supply at the lowest possible price. A market open to competition is one where private capital is at risk in developing new generation (and other products and services) to meet the demand for power. A competitive market is one where the perspectives, ideas, and innovations of many organizations are brought to bear to satisfy the needs of consumers. A healthy, competitive market meets the needs of both buyers and sellers. Governments, legislators, and regulators must be mindful of two over-riding requirements for a healthy competitive market to develop and be sustained. The Requirement for Stable Government and Regulatory Policy The development of new generating capacity in Ontario is a capital-intensive proposition. To build 2500 MW of incremental generation capacity (about 10% of Ontario s peak demand) could require $3 billion of capital investment, and this capital simply will not be committed by private investors if they perceive that the government is less than committed to a competitive market, or if the basic rules of that market are seen to be in a state of flux. Aegent ENERGY ADVISORS INC

3 This was evident in the period prior to market opening, when postponement of the market opening date was interpreted by some as uncertainty that the market would open. The result was a delay in investment by potential market participants in establishing generation or marketing resources. The government s policy announcement of November 11, 2002 has significantly damaged the prospect of enhancing competition and increasing supply in the wholesale power market, by demonstrating that it lacks commitment to the principles of the competitive market. In Aegent s analysis, the weighted average price of power for the first year of market operation to April 30, 2003 (net of the projected rebate under the Market Power Mitigation Agreement) can be expected to fall in the range of 4.5 to 4.8 per kwh. This represents a premium of about 10% over the price implemented by Bill 210. To put this price premium in context, it arises in a year in which new record demand peaks were set owing to extreme summer weather, and significant low marginal cost nuclear generation was out of service. On balance, a 10% price increase seems relatively moderate under the circumstances. Some market participants faced prices higher than this average price (based on their actual or deemed usage pattern), and some consumers were threatened by a higher cost of power, even a 10% increase. Many power consumers, especially residential and commercial users whose demand for power soared with the temperatures, did not realize the degree to which higher usage (and not just higher prices) was contributing to bigger power bills. Finally, of course, bills were higher because non-energy charges had risen substantially, based on the changes in capital structure and rate design undertaken by the utilities in order to comply with the requirements of the Electricity Act, If it was necessary, in the government s view, to ease the cost of the transition for these market participants, the government could have developed a program of targeted subsidies or rebates to defray the cost increases for vulnerable consumers. Such a program would have cost less than subsidizing all small volume and designated consumers, and, just as importantly, would have signaled the government s commitment to the principle that competitive markets should set the price for power. The government s willingness essentially to close the competitive market as it applies to as much as 40% of the province s power demand has hurt the effort to achieve a better supply/demand balance, by removing price as an indicator to these consumers of the relative tightness of supply. This will discourage conservation or load management initiatives among these users (for example, by removing the economic justification for these consumers to convert from energy meters to interval meters). By closing the market for this market sector, the government destroyed the economic value of significant investments made by a number of market participants in developing organizations and systems to meet the needs of the consumers in this sector. These investments were undertaken on the basis of a set of market rules and regulations that had been developed over four years by the Market Design Committee, the Independent Electricity Market Operator s Technical Panel and Technical Advisory Teams, proceedings of the Ontario Energy Board and various industry working groups. The government s willingness to set all this aside with its policy announcement of November 11, 2002, creates the realization and the apprehension that it could do so again. It will not be easy to restore confidence in the stability and durability of the government s commitment to the competitive power market. Private investors, once burned, will be twice shy. The government must demonstrate a willingness to withstand some political pressure in defence of its policy position, essentially risking political capital, if it is to expect investors to risk their economic capital in furtherance of the government s policy objectives. Aegent ENERGY ADVISORS INC

4 Transparency of Information After stability of government policy, the second principle for promoting investment in Ontario s power market is the principle of transparency of information. The government must take all possible steps to ensure that relevant information that will affect the behaviour of market participants (buyers, generators, marketers, and potential generation developers) is disclosed in a timely way. For example, lack of reliable information about the status of the Pickering A nuclear units creates considerable uncertainty about the future supply/demand balance in Ontario. Ontario Power Generation may argue that full disclosure of the status and progress of the Pickering rehabilitation compromises OPG s competitive position. The government, as energy policy maker and owner of OPG, is clearly in the position to realize that OPG s position in the market must be balanced against the overall health of the market. In the present stage of development of the new market, a trade-off that encourages new entrants and increased competition and enables buyers to better manage their price risk is a trade-off that is well warranted. Other examples of how application of the principle of transparency of information will help to develop a more competitive market are elaborated in the sections of this submission that follow. Issues for Discussion The Ministry s paper invites discussion on a number of issues and questions. Aegent s views on these questions are provided below. 1. What changes can be made to the Market Power Mitigation Agreement that will enhance its usefulness to large customers? In Aegent s view, there are three principal flaws in the operation of the Market Power Mitigation Agreement (MPMA). It lacks transparency. Changes to the MPMA calculation are retroactive, rather than timely. Cash flow under the MPMA is delayed. Since the MPMA will provide a rebate that is a function of market prices, the MPMA acts as a partial hedge on the consumer s electricity costs. To date, the quantity of the rebate is not known to market participants. To the extent the MPMA rebate is a hedge, it is a far less than perfect hedge in this respect. Buyers who are price risk averse are unable to accurately assess the degree to which the MPMA protects them, in order to determine what further protection they require (in the form of financial or physical bilateral contracts). The information needed to make this determination is known to Ontario Power Generation, and is also subject to determinations by the Ontario Energy Board (OEB or Board) as to whether certain decontrol arrangements entered into by OPG satisfy the requirements of the MPMA in order to reduce the Q-values in the rebate calculation. The MPMA impacts of OPG s agreements concerning the capacity at Bruce and the Mississagi hydroelectric capacity have not yet been decided by the Ontario Energy Board. The decision, when it comes, will in effect be retroactive. Power consumers will, in essence, receive either more or less of a rebate of the historical cost of power since May 1, depending on the OEB decision in this matter. If the OEB determination is counter to what a market participant expected, there is no opportunity for the market participant to take action to adjust for the impact (by hedging more or less of its power costs on its own). Aegent ENERGY ADVISORS INC

5 Power costs play a significant role in the cost of production for many large industrial users. The lack of knowledge on a real time basis of the value of the MPMA rebate means that these power users do not have an accurate picture of the true cost of the power they are using, or the true cost of their production. While they might accrue an estimated MPMA value, their decision-making ability is hampered by the uncertainty of the estimate. When the MPMA value is ultimately determined, these buyers may find that the decisions they made were wrong, even though they were based on the best information available to them at the time. Finally, market participants are expected to wait until after the end of each year of market operation before receiving their MPMA rebates. The size of the potential rebates to some large volume users means that the timing of this cash flow is an issue. Some, in the interests of getting the cash sooner, have entered into agreements with OPG under which OPG essentially buys back the rebate, and in exchange discounts the buyer s cost of power under a physical bilateral agreement. In a market with information transparency, where all participants have equal access to information about the factors that will affect the value of the MPMA, this might be a reasonable solution. But clearly, OPG has vastly more knowledge than any power buyer or any other power seller about the variables that will ultimately affect the value of the MPMA rebate (most notably, only OPG knows its plans with respect to decontrol). This means there is not a good market solution that will substitute for more timely distribution of MPMA rebates. In our view, the application of the MPMA should be modified as follows: OPG would get credit for decontrol agreements only after the Ontario Energy Board had reviewed the agreement and approved the Q-value change on a prospective basis from a date established by the Board. This avoids retroactive impacts of Board decisions concerning decontrol arrangements. (In the interest of fairness, the Board s determination on Bruce and Mississagi should be allowed to take effect as of the effective date of those agreements). The Ontario Energy Board would allow Q-values to change only at reasonable intervals say 3 to 6 months in much the same way as gas distributors re-establish their gas supply commodity charges using a Quarterly Rate Adjustment Mechanism. This allows consumers to make decisions about contracting for power over the next 3 to 6 months armed with knowledge of how the MPMA rebate will affect their price risk. A mechanism should be established under which OPG will clear through the IMO to market participants, the OEB-established MPMA rebate on a monthly, or at least quarterly basis. This puts the cash in the hands of consumers in real time, and provides a better indication of the true cost of power. Implementing Q-value changes prospectively will enable all consumers to know with certainty the impact of any decontrol agreement, take action that is appropriate for their business to protect themselves going forward by further hedging if required, and they will be able to book reasonably accurate values for the cost of power in real time. Distributing the rebate in real time will allow consumers to see their net cost of power and will reduce the perception that power is costlier than it really is (once the MPMA is taken into consideration). Aegent ENERGY ADVISORS INC

6 2. Do large electricity consumers have an incentive to conserve and rationally use electricity at critical times of the day, month and year? High spot market prices and the prospect of high forward market prices provide incentives for all large volume electricity users to conserve electricity, shave peak usage, and shift usage to lower cost periods, to the extent their operations allow them to do so. High prices also encourage large users to evaluate capital projects that will enable them to increase their operating flexibility in order to achieve power cost savings. These are the fundamental benefits of a market structure in which supply scarcity is communicated to all participants through price signals. To the extent a large volume user has the ability to shed load (or incrementally displace load with its own generation) during periods of high price, the user avoids the cost of buying high priced power. It must be noted, however, that this end user is also creating a benefit for other market participants. Since market demand is lower as a result of the large user s demand displacement, the market clearing price will be lower, and all market participants will pay a lower price as a result. As an illustration, consider an hour where the total expected load is 25,000 MW and the price response of 500 MW of load reduces the hourly price from a pre-dispatch value of $1,000 / MWh to a real-time or dispatch value of $250 / MWh (the demand curve is steep at high demand levels). While the uplift to compensate the hourly dispatchable load could cost up to $375,000, the cost of power to the rest of the market would be reduced by over $18 million in that hour. In developing mechanisms to promote price responsive loads, a key difference between generation and load must be recognized. The generator, by-and-large, is in business to deliver power to the market, and can customize its operations to meet the operational requirements of the market. A load, on the other hand, is in some business other than the power business, and its processes are designed to that end. Load which can be managed in response to price, nevertheless must be managed in light of the requirements of the manufacturing process that creates the demand. For this reason, there may be a large element of price responsive load that cannot meet the requirements of 5-minute dispatchability, but which could be dispatched on an hour-ahead basis. The fact that displacement of demand is of value to the market in reducing prices indicates the need for the market rules to be modified to facilitate a greater degree of participation by price responsive loads. Aegent supports the concept of Hour-Ahead Dispatchable Loads as being developed by the Independent Market Operator. Where the use of Hour-Ahead Dispatchable Load competes with and reduces the need for imports and Intertie Offer Guarantee (IOG) payments, an added positive impact on the provincial economy results as payments made to domestic loads would stay in-province rather than go to out-of-province generators. 3. On the demand side, are current pricing arrangements effective in linking consumption to the supply of electricity available at any given time? As discussed under point 5 below, the very high level of power demand experienced in the summer of 2002 (and the high prices and uplifts that resulted) were a consequence primarily of the effect of extreme temperatures. The demand for power from residential, commercial and institutional power consumers tends to be linked to ambient temperatures, and the demand for air conditioning. Aegent ENERGY ADVISORS INC

7 The preponderance of energy meters (as opposed to interval meters) among smaller residential and commercial power users and the use of the Net System Load Shape as a means of allocating prices, resulted in a disconnect between price and demand in this segment. These customers did not know what the price was in any given hour, and because of the Net System Load Shape methodology, no effective load shifting strategy was available to these users. Regrettably, instead of introducing measures to overcome this impediment (for example, by promoting the widespread deployment of small volume interval meters), the government has exacerbated the price/demand disconnection by insulating a large part of this market from any price signal at all. Thus, current pricing arrangements (namely the price freeze under Bill 210) run directly counter to the objective of linking consumption behaviour to supply conditions in real time, as signaled by price. All of this underscores the fact that with only a price freeze in place, continuing efforts to promote interval meters to those protected by Bill 210 is moot. The recent announcement made by the Commissioner of Alternative Energy concerning price response payments for residential customers is interesting, but such a program will run into many challenges, including the complexity and cost to administer and implement and arriving at a benefit-sharing proposition that is attractive to homeowners. If such a program does go ahead, the incentive principles (or a proxy for them) related to Hour-Ahead Dispatchable Load should be followed. 4. Many large users of electricity have very complex contract arrangements. What choices would be effective for them in terms of fixed or variable prices for future electricity contracts? A stable policy environment that encouraged entry by power generators and marketers would produce an energy marketplace where innovation and competition encouraged the offering of a variety of contract terms and provisions to meet buyers needs. At present, the most complex contract offering is the Transitional Rate Option contract. While exceedingly complex, these contracts offer valuable benefits to certain large end users during the transition to the competitive market. These contracts will be phased out in due course, and there is no need to interfere in these agreements at this stage in the transition. 5. How should the import offer guarantee / IMO uplift be dealt with, given that large users of electricity contribute greatly to the need for imports? This question proceeds from a flawed assumption, or at least a significant imprecision, about the driving force behind imports. Demonstrably, the need for a high level of imports this past summer was directly linked to the extreme temperatures that were experienced, and the resultant demand for power from temperature-sensitive loads. While some large users are temperature sensitive loads (large commercial or institutional buildings, for example), industrial users generally are not. Most industrial demand is tied to production levels, rather than ambient temperature. Applying forecasting rules of thumb published by the IMO, it can be seen that the magnitude of the average net imports during the months of June 2002 through September 2002 bore a direct relationship to the excess of the average daily temperature over historical average temperatures. Put another way, if Ontario had experienced normal weather during this period, there would have been little or no need for imports. (Please refer to the Appendix for details). Aegent ENERGY ADVISORS INC

8 The fact is so important, it bears repeating: Peak electricity demand in Ontario is driven by the demand of temperature-sensitive loads which are concentrated in the residential, commercial, and institutional sectors. The price freeze that has been applied to most consumers in these sectors will make their electricity demand less responsive to price signals, and exacerbate the tightness of supply and the extreme prices that arise in hot weather conditions. Industrial loads generally present opportunities for developing greater price responsiveness, and in that respect, represent a sector of the market that, given the right incentives, can help to offset the damaging effect of the price freeze, and reduce the need for imports. When imports are required, the Intertie Offer Guarantee appears to deal with the dynamics of pre-dispatch scheduling and real time dispatch requirements in the most economic way possible. Having these costs appear in the Hourly Ontario Energy Price (HOEP) instead of uplifts has some superficial appeal the costs would seem to be avoidable by end users if they hedge their power costs, and domestic generators would see higher revenues, which would motivate investment in generation. However, on inspection, these perceived benefits are false. If the risk of IOG costs were to be borne by the sellers of fixed price power, that risk would be reflected in an increase in the forward price for power. While the costs might be distributed differently, they would not be avoided any more effectively than they are now. Even if the cost of IOG s was to be included in the HOEP recovered from power buyers, it could not also be included in the HOEP paid to domestic generators (without collecting even more from buyers). If so, buyers would be paying twice. Allowing the offer price of the import seller to set the market clearing price for the hour would lead to unnecessarily high prices at great cost to all consumers. The best solution to high IOG s lies in a better domestic supply/demand balance, and reduced reliance on imports. There are large power users whose load characteristics (namely, the ability to develop price responsive load) is part of the solution, not part of the problem. Developing market rules that facilitate greater participation by price responsive loads is the best strategy to pursue. 6. On the supply side, what steps should be taken to increase competition in the Ontario marketplace and to encourage new suppliers to enter Ontario s market? What other steps should be taken to address the long-term supply of electrical generation. As discussed, the government s policy changes of November 11, 2002 have created the perception that the government s commitment to a competitive electricity market is tenuous. This perception must be reversed if new suppliers are to determine that entering the Ontario market is a reasonable business risk. Changing this perception will not be easy, and will not be achieved quickly. Other factors discouraging entry by new suppliers include the uncertainty surrounding the return to service of nuclear capacity at Pickering. Since this project is being carried out by a Crown agency, the government must commit to timely disclosure of new information about the timing of this return to service, and the capacity that ultimately will be returned to service, so that new suppliers will know as much as possible about the market environment they are entering. Failing this disclosure, investors will simply wait until better information becomes available, and seeing them wait is not in the interest of a competitive market. Finally, while new suppliers may be willing to enter a competitive market, they are less enthusiastic about entering a market that continues to be dominated by OPG. The government should revisit recommendations for mechanisms to accelerate the divestiture or decontrol of OPG generation assets to speed the Aegent ENERGY ADVISORS INC

9 development of a competitive market, and to signal commitment to moving forward with the policy of competitive electricity markets. The market for generation assets suggests that a sale of assets may not be timely, but options exist for restructuring OPG to reduce market power and enhance competition in the market, without necessarily selling assets at this time. 7. Are the government s efforts to retain and strengthen the wholesale market the proper approach? What additional efforts should the government undertake to retain and strengthen the wholesale market? The government most certainly should act (as outlined above) to retain and strengthen the wholesale market. However, the government may be unaware that many market participants are unsure of the government s intention to do so. Bill 210 created the possibility that all power consumers, including wholesale market participants and large embedded loads, could receive some type of price freeze, with the price to be determined by regulation (section 12 which added section 79.5 to the Ontario Energy Board Act, 1998). Further, the legislation provided that anyone entering into a power contract after December 9, 2002, would be ineligible for the price provisions contained in Bill 210 (section 12 which added subsection (6) of a new section 79.4 to the Ontario Energy Board Act, 1998). In our experience working with participants in the wholesale market, the consequence has been an unwillingness for large volume users to contract for power in the wholesale market, for fear of disqualifying themselves from eligibility for the frozen prices that may come from the government at some time in the future. The government s intervention has created a tendency for some large users to look to the government for price protection, rather than looking out for themselves through contracting and hedging activity. Unless rectified, this situation could prove disastrous if these large users experience high prices that they could have avoided had they understood that government intervention was not forthcoming. This is a situation where the principle of transparency is key. If the government intends to provide some form of price relief to segments of the market that do not now have such relief under Bill 210 and its regulations, then the government should clarify that protection. If the government is not going to provide price freezes or other protection to this segment of the market, then that should be clearly communicated so that these consumers can make hedging and power contracting decisions and re-enter the wholesale market. Summary Competitive markets provide the best opportunity for Ontario s electricity needs to be met reliably and costeffectively. The challenges that have presented themselves in the short time since market opening are challenges of the transition to competitive markets, and not failures of the market. These challenges can be overcome, by modifying the methods and the mechanisms of the market if necessary, and moving ahead. For a healthy competitive market to develop and be sustained, two over-riding requirements must be met. Government and regulatory policy must be stable and relevant information that will affect the behaviour of market participants must be transparent and timely. Aegent ENERGY ADVISORS INC

10 APPENDIX: Effect of Temperature on Imports The Independent Electricity Market Operator publishes forecasting rules of thumb, including factors for demand and consumption increases when temperatures rise during summer months. Generally, these increases result from increased space cooling / air conditioning loads. One of the IMO s energy rules of thumb is a 6,370 MWh / day increase in power demand for each 1 C increase in temperature. Air conditioning load generally derives from residential, commercial and institutional buildings, so the temperature extremes that drive increased space cooling requirements ultimately increase commercial and residential loads, not industrial loads. Comparing actual consumption during June 2002 to September 2002 against the IMO s April 2002 load forecast for the June to September period, actual consumption averaged 500 1,700 MW more than the forecasted loads. June July August September Temperature Increase C Based on 6,370 MWh per 1 C MWh / day 7,644 21,658 17,199 31,213 temperature increase MW ,300 Forecast MW 16,400 17,403 17,220 15,810 Actual MW 16,934 18,862 18,480 17,490 Excess MW 534 1,459 1,260 1,680 % 3.3% 8.4% 7.3% 10.6% Import, actual, average MW ,438 1,359 Import, adjusted by IMO rule of thumb MW Import, adjusted by IMO forecast error MW During the months of June 2002 through September 2002, the temperature averaged 1 5 C above normal levels. Using the IMO s rule of thumb, one would expect these elevated temperatures to have added an average 300 1,300 MW to the Ontario load. During the June to September period, the average net import to Ontario ranged from less than 100 MW to over 1,400 MW. Allowing for forecasting error, using the IMO s rule of thumb is a conservative method of estimating the effect of extreme temperature on load. If average net imports had been reduced by normal weather (i.e., lower by 300 1,300 MW as suggested by the IMO s rule of thumb), Ontario could have instead seen exports of almost 300 MW in June 2002 and a peak import of just over 700 MW in August In the final analysis one can only conclude that extreme weather (and its impact on demand) was the major contributor to the need for imports. Aegent ENERGY ADVISORS INC

11 For smaller customers, both commercial and residential, the Net System Load Shape and a lack of interval metering meant these customers were largely disconnected from pricing signals. With Bill 210 in place, the price responsiveness of these customers will be further reduced as they realize that they will pay the same unit price for (the energy portion of their) electricity, regardless of how expensive it is when they consume it. Aegent ENERGY ADVISORS INC