Règie de l'énergie Modalités d'établissement et d'implantation des tarifs de fourniture No: R- 3398 - 98 Evidence of Michael Margolick, Ph.D. Prepared for L'association québécoise des consommateurs industriels d'électricité (AQCIE) May 5 1998 AQCIE-2 1. INTRODUCTION 1 2. CANADIAN HYDRO UTILITIES AND ELECTRICITY MARKET REFORM 2 2.1. Similar physical characteristics 3 2.2. Similar policy environments 5 3. PRINCIPAL PRICING MODELS 9 3.1. Full competition 9 3.2. Performance-based regulation (PBR) 12 3.3. Allocated cost of service 15 3.4. Unbundled costs versus unbundled tariffs 18 3.5. Characteristics of market-sensitive pricing 20 4. EXAMPLES OF MARKET-SENSITIVE SUPPLY RATES 23 5. THE HYDRO- QUÉBEC PROPOSAL 27 6. CONCLUSIONS 30 -1- 1 1. Introduction 2 This first hearing by the Régie of Hydro-Québec may set important precedents for 3 electricity regulation in Québec for many years. The focus of the hearing is the principles 4 and methods to be used in determining the rate for supply of electricity by Hydro-Québec. 5 "Supply" in this context means the provision of electricity, but not its transmission or 6 distribution. 7 At present, Hydro-Québec has a retail monopoly for approximately 97% of electricity 8 sales in the Province. It also has a wholesale transmission tariff to which the remaining 9 3% of load has access. Under this structure, the proposed rates would therefore apply to 10 offers of sale from Hydro-Québec to, and only to this small proportion of customers. All 11 others would continue to be served by Hydro-Québec at bundled retail rates for 12 generation, transmission and, where applicable, distribution. While retail tariffs are not 13 under review in this proceeding, the results may nevertheless be significant for the 14 majority of customers for two reasons: 15 for setting definitions and precedents for future retail rate design; and 16 information for investment planning through an Integrated Resource Planning process. 17 This report has been prepared by Dr. Michael Margolick at the request of L'association 18 québécoise des consommateurs industriels d'électricité (AQCIE). It covers four areas: 19 1. A review of Hydro-Québec's position within the context of electricity industry reform 20 in North America, and in relation to other utilities with common characteristics, 21 specifically BC Hydro and Manitoba Hydro 22 23 2. A discussion of basic options for setting the supply rate, including price-based regulation, cost-based regulation and open competition 24 3. A critical analysis of Hydro-Québec's proposal 25 4. General conclusions and advice to the Régie concerning principles to be applied in 26 determining the supply rate. -21 This report attempts to abstract the most important features of existing policies and 2 emerging market environments and to suggest rate structure ideas are compatible with 3 both. 4 These ideas are fully consistent with, and support the government's policy concerning 5 rates under the mandate of the Régie: 6 "Pour le gouvernement, les tarifs autorisés pour la vente de gaz naturel et 7 d'électricitié doivent tout à la fois refléter les coûts, respecter la capacité de payer 8 de la clientèle, avoir des effets équitables et être simples dans leur définition. Ces 9 principes ont plusieurs implications: il faut que les tarifs du gaz naturel et de 10 l'électricité se rapprochent le plus possible du coût de desservir chaque catégorie 11 de consommateur. Bien que le niveau des tarifs soit basé sur les coûts moyens, les 12 tarifs devraient ainsi évoluer vers une meilleure intégration des coûts marginaux, 13 les tarifs de base traduisant plus directement la valeur de l'énergie 14 consommée….La Régie ne devrait pas hésiter à intégrer, dans ses pratiques de 15 régulation, des mécanismes incitant les fournisseurs d'énergie à améliorer leur 16 performance."1 (emphasis added). 17 This is understood to mean that rates should recover average, or embedded costs in total, 18 but should also evolve towards reflecting marginal costs. Specifically, these marginal cost 19 elements should be reflected in the prices paid by customers. 20 2. 21 The three "Hydros" of Québec, Manitoba and BC share characteristics that provide them 22 with distinctive challenges and opportunities within the context of electricity restructuring 23 in North America. A description of these characteristics provides useful context for the 24 pricing discussion that follows. Some of the characteristics are inherent in the physical 25 systems themselves, while others are government policy. Government policies include 26 long-standing policies and those arising more recently from restructuring. 1 Canadian hydro utilities and electricity market reform L'Energie au service du Québec, 1996, p.25 -32.1. 1 Similar physical characteristics 2 3 First, generation is based almost entirely on hydroelectric plants. By contrast, in Canada, 4 all other provinces, except Newfoundland, are primarily nuclear and/or 5 thermally-sourced. In the US, by State, only Idaho, Oregon and Washington have 6 comparable concentrations of hydropower2 and this resource lies largely within the 7 domain of the Bonneville Power Administration, an agency with substantial nuclear 8 liabilities, if not operations.3 9 Second, the concentration of generation capacity in individual plants or river systems is 10 also high: Approximately 80% of total energy generation by BC Hydro is on the Peace 11 and Columbia Rivers4; in Manitoba approximately 80% of hydro generation capacity lies 12 on the Nelson River5, and the collectivity of the La Grande, Manic-Outardes and 13 Churchill systems in Québec also supplies approximately 85% of the generation of 14 Hydro-Québec.6 15 Third, the utilities have transmission links to neighbouring utilities and are part of a 16 continental electricity market that is undergoing reform. Export transmission capacity, as 17 a proportion of generation capacity, varies among the three utilities. Manitoba's 18 transmission export capacity is over 50% of the utility's generation capacity7, while the 19 corresponding number for BC is approximately one third and Québec is more constrained 2 Idaho at 100%, Oregon: 93%, Washington: 88%, South Dakota: 79%. Next is Montana with 53% Data are for 1996. http://www.eia.doe.gov/cneaf/electricity/epm/epmt11.dat [US Dept. of Energy, Energy Information Administration] 3 BPA is mostly hydro-based, but in 1995 approximately 25% of its costs related to debt service, operations and mothballing costs on nuclear plants [Source: Clearing Up, Mar 6, 1995, #663 p. 5]. The three Canadian hydro utilities discused here are not so encumbered. 4 Making the Connection: the BC Hydro Electric System and How it is Operated; BC Hydro;1993, p. 3: 5 A Powerful Future: Manitoba and the Evolving Power Industry; April 1997 Manitoba Hydro, Fig. 2.2 6 Ouverture des marchés de l'électricité au Québec; Options, impératifs d'une réelle concurrence et conséquences pour les prix; Centre Hélios, Montréal, octobre 1997; note 67 7 A Powerful Future: Manitoba and the Evolving Power Industry; April 1997 Manitoba Hydro; p. 9 -41 (about 18%)8. Current export revenues derive from assets that cost very little to operate 2 and are therefore quite profitable. The profitability of future hydroelectric development 3 for the export market is not as clear, as the cost of construction of the facilities, rather 4 than only their operation, would have to be taken into account. 5 Amounts exported depend on streamflow, domestic load and market conditions. In 1995, 6 for example, Manitoba Hydro exported about 40% of its total energy sold, while the 7 corresponding figures for BC and Québec were approximately 8% and 15%, 8 respectively.9 Hydro-Québec sold 17.7 TwH on the export market in 1996, which is 9 about the same as the average for the 1993-96 time period.10 The value of these export 10 sales in 1996 was $601 million, a significant amount of money by any standard.11 11 Fourth, their reservoirs can be used to store energy for later sale. This is a valuable 12 capability that is not available in the primarily thermal and nuclear systems with which 13 Hydro-Québec, in particular, trades. BC Hydro has good multi-year storage in Williston 14 and Mica reservoirs. A 10-year average of total system monthly energy storage ranges 15 from 10 to 25 TwH, which is 20 - 50% of annual sales.12 Hydro-Québec also has very 16 substantial storage and multi-year capability. Manitoba's Lake Winnipeg has good 17 seasonal, but not multi-year storage. 18 19 20 8 If Hydro-Québec generation capacity is 31,000 MW [http://www.hydroquebec.com/en/deco.html] and export capacity is 5515 MW [Strategic Plan 1998, p. 35] the ratio is 18%. 9 A Powerful Future: Manitoba and the Evolving Power Industry; April 1997 Manitoba Hydro, Fig. 2.10 10 Hydro-Québec has built a solid reputation for quality and reliability in the Northeastern U.S. (Hydro's Web Page); Exports of 14.1, 18.0, 23.5, and 17.7 TwH are shown for 1993 - 1996. 11 An attractive market (Hydro's Web Page); " Just last year, Hydro-Québec sold electricity outside Québec worth $601 million" 12 BC Hydro Annual Report, 1996, p. 4. -52.2. 1 Similar policy environments 2 3 The three utilities are under three different governments. However, the governments share 4 important policy directions in response to the challenges and opportunities raised by 5 liberalization of the generation market in North America. 6 No privatization 7 First, all utilities are state-owned and no jurisdiction is considering privatization. For 8 example, the proposal of Hydro-Québec states: 9 "La politique du gouvernement du Québec à ce sujet est très clair: il n'est 10 aucunement question pour le moment, de privatisation, partielle ou totale, 11 d'Hydro-Québec…" (p.4) 12 Wholesale transmission rates 13 Second, all three governments have formally implemented wholesale transmission rates. 14 The implementation of these rates has been primarily to secure access to US markets 15 under wholesale reciprocity conditions imposed by FERC and/or Regional Transmission 16 Groups (RTGs). BC Hydro and Hydro-Québec have FERC-approved "market-based rate 17 authority" required for access to wholesale buyers beyond the US border. Manitoba is 18 considering applying for market-based rate authority.13 19 Near-monopolies for retail sales 20 Third, the three utilities have near-monopolies for retail electricity sales in their 21 respective provinces. BC Hydro has about 94% of GwH sales; Hydro-Québec: 97%; and 22 Manitoba Hydro effectively has 100% share of retail sales.14 End-users not served by the 13 It may not yet have applied, either because it feels satisfactory deals can be made at the border, and/or because it has some unexpired long term firm contracts. 14 Although Winnipeg is a distinct distributor in Manitoba, its rates are required by the City of Winnipeg Act to be the same as those of Manitoba Hydro. In addition, Winnipeg Hydro's costs are determined through a cost-sharing agreement with Manitoba Hydro. It may be formally possible for Winnipeg to access the existing wholesale transmission tariff of Manitoba Hydro, but true competitive conditions for supply to Winnipeg cannot be said to exist under the current structure. -61 utility are typically large industrial facilities with independent water rights, such as Alcan, 2 or small municipalities that remain separate for historic reasons. 3 There does not appear to be government interest in greater domestic wholesale 4 competition. There is no apparent government interest in either creating additional 5 wholesale buyers (through the offer of sale of distribution assets to municipalities or 6 others), nor in breaking up the existing generation systems into competing entities to 7 serve domestic wholesale markets competitively. 8 Government policies with respect to retail access are as follows: 9 In Manitoba, Sec. 15.2 of the 1997 Manitoba Hydro Amendment Act restricts retail 10 11 supply to Manitoba Hydro and the City of Winnipeg. In BC, the January 1998 Report of the Electricity Market Reform Task Force did 12 recommend phased-in retail access for industrial customers (half of industrial load in 13 Phase 1, the remainder in Phase 2), after the 1995 BC Utilities Commission's 14 Electricity Market Structure Review, rejected it "at this time". 15 However the Task 15 Force report was not based on consensus, or even general agreement of the 16 participating stakeholders, and the government appears to prefer providing industrial 17 concession rates to providing customer access to multiple suppliers. 18 In Québec, paragraph 3 of Article 167 of the Act (Bill 50) assigns responsibility for 19 advising the Québec government on market liberalization to the Régie, "within the 20 time determined by the Government". To date no such process has been initiated. 21 Hydro-Québec also "does not intend to promote the opening of the Province's retail 22 electricity market".16 23 If neither retail nor expanded wholesale competition are to be placed into effect, then, for 24 almost all retail customers, prices will continue to be set by provincial regulators and/or 25 governments. 15 Reforming British Columbia's Electricity Market: A Way Forward, January 1998; and The British Columbia Electricity Market Review, September 1995, BC Utilities Commission, p. xi. 16 Strategic Plan 1998 - 2002, p. 11 -71 Domestic rates at embedded cost 2 Fourth, revenues from tariffed sales are approximately equal to average, or embedded 3 costs – return on rate base, operating expenses and interest payments. Utility rates and 4 costs have been reviewed by regulators in BC and Manitoba. Hydro-Québec stated in 5 1993: 6 "Costs of supply include all expenses required to meet the electricity requirements 7 of a given market or rate category. For customers in Québec, these expenses 8 reflect the average cost of new and existing facilities. For the export market, the 9 rates reflect anticipated costs for new facilities. Export costs are therefore 10 established first, in order to exclude them from Québec market costs"17 (emphasis 11 added) 12 Contributions to government 13 Fifth, each utility also pays dividends, or contributions to government that arise largely 14 from the profitability of exports. The dividends are not necessarily equal to export 15 earnings, either by policy or in practice. However, all else equal, increases in export 16 earnings increase the overall profitability of the enterprises and therefore the dividends 17 that can be paid in any given year. 18 Industrial concession rates 19 Sixth, BC Hydro and Hydro-Québec have adopted concession rates for industrial 20 customers – either to attract them to set up operations or to keep jobs when they might 21 otherwise close or move due to market conditions.18 22 Québec has, for some time, offered shared-risk and special contracts. In BC, a strong 23 orientation to concession pricing for industry has recently emerged: 24 The Economic Development Electricity Rate Act (1996) overrides the BC Utilities 25 Commission Act in providing the Lieutenant Governor in Council with the power to 17 18 Long-Term Rate Orientations, Development Plan 1993, Proposal p. 41. Manitoba has the lowest industrial electricity rates in North America and less than a half-dozen large industrial customers. -81 specify quantities to be made available at a lower rate than the regulated rate for new 2 plant construction or expansion. 3 The Power for Jobs Development Act, passed in 1997, makes available electricity, 4 including that being returned to the Province under the Columbia River Treaty, 5 available to businesses using more than 35 kW at a "development power rate" for the 6 purposes of creating new jobs and maintaining existing jobs. This Act also overrides 7 the ratemaking authority of the BC Utilities Commission. Phase I of Power for Jobs 8 offers 200 MW of power to new investors. Existing industries in distress may also 9 apply for discount prices. In both cases the prices will be set by the government on a 10 11 case-by-case basis. B.C. Hydro's real-time pricing (RTP) rate, discussed below, is in part a concession 12 (load retention) rate, arising from the terms of its provisions for reduction in 13 Customer-Based Load. 14 Concession rates are to be distinguished in concept from market-sensitive rates discussed 15 below. Market-sensitive rates may benefit the province, but the benefit arises from more 16 efficient use of equipment and hydro generation rather than from a specific policy to 17 attract or keep industrial activity. 18 The remainder of the paper works toward the development of supply pricing options in a 19 "Hydro" system that: 20 meet basic regulatory and policy requirements, specifically recover average costs in 21 total but provide price signals relating to marginal costs 22 reflect characteristics of the competitive market, and 23 exploit the advantages of hydroelectric power 24 Development of such supply pricing options would be fully consistent with the 25 government's policy as stated in the introduction. 26 First, it is necessary to consider different basic supply price models. The three considered 27 are deregulation, performance-based ratmaking (PBR), including regulation on the basis 28 of price, and cost of service regulation. Next, we explain the distinction betwen -91 unbundling costs versus unbundling tariffs. Then we describe characteristics of 2 market-sensitive pricing. The most important of these are the concept of "electricity" as a 3 commodity, as opposed to distinct generation energy and generation capacity, and the 4 high time-variance of prices for electricity. Examples of market-sensitive pricing in BC, 5 Québec and Manitoba are then briefly described. Then we critique the proposal of 6 Hydro-Québec, given the perspectives developed here. This is followed by general 7 conclusions. 8 3. 9 Principal pricing models 3.1. Full competition 10 The principal markets with which Hydro-Québec trades are becoming increasingly 11 competitive, and any pricing model used in Québec must take this into account. In 12 general, competition reduces commodity prices because it reduces costs of production. 13 Electricity is no exception, and on average across North America, the price of generation 14 is expected to go down. However, in a perfectly competitive market, all producers 15 receive, and can only receive, a price equal to the marginal cost of production (the 16 "one-price" law). Producers whose average cost is below the marginal cost of production 17 will therefore see an increase in price and in profitability when the market moves from 18 (average-cost-based) regulation to competition. 19 "Moving from regulated cost of service pricing to competitive pricing does not, in 20 and of itself guarantee that prices will fall for everyone. In general, if marginal 21 costs are lower than the historical average embedded costs (or increased 22 competitive pressures leads to falling production costs), as is the case in most 23 parts of the U.S. market today, prices will fall with increasing competition. For 24 example, in many areas, the combination of low-cost new generating technologies 25 and low fossil fuel prices has made power from new plants less expensive than 26 power from some older plants or from old power supply contracts. On the other 27 hand, the operating and capital-related costs for some existing power plants and 28 utilities are very low, and absent other cost saving induced by competition, their - 10 1 prices could rise in a competitive market. Thus regions of the country that are 2 largely dependent on older, low-cost plants may see higher end-use electricity 3 prices when the prices are set by the marginal, rather than average, cost of 4 generation."19 (emphasis added) 5 Although prices in the East Coast market with which Hydro-Québec trades are falling, the 6 current average cost of production in Québec is expected to continue to be below 7 competitive generation prices in the external market.20 Therefore, if it were given a 8 competitive pricing mandate and if it were fully integrated with the much larger East 9 Coast market, Québec's prices would approximate those in the East Coast market, which 10 are expected to be higher than today's rates. 11 However, there are two important factors that act together to complicate matters: 12 generation market power and transmission constraints (also called transmission market 13 power). The existence of transmission constraints indicates, in particular, that Québec is 14 not fully integrated within the larger East Coast market. The combined effects of 15 generation market power and transmission market power on prices under competition in 16 Québec are now discussed. 17 Generation market power is the ability of suppliers to control prices or discriminate 18 among customers at will. It exists when a large enough market share belongs to a small 19 enough number of suppliers. If one were to consider Québec as a physically isolated 20 market, Hydro-Québec would have generation market power due to its overwhelming 21 share of the generation market. Attempts to control market power by creating competing 22 generation systems in Québec would be unlikely to be reasonable or successful.21 Buyers 19 Electricity Pricing in a Competitive Environment: Marginal Cost Pricing of Generation Services and Financial Status of Electric Utilities; August 1997, Energy Information Administration, US Department of Energy, p. 2-2. 20 For example, the report Electricity Pricing in a Competitive Environment: Marginal Cost Pricing of Generation Services and Financial Status of Electric Utilities; (August 1997, Energy Information Administration, US Department of Energy) shows estimated prices based primarily on short run marginal costs for different regions in the U.S. 21 First, there are only a small number of hydroelectric plants in total. Second, a competitive market requires that suppliers are able to independently set their volumes and prices offered for sale. Generators sharing a single river system cannot do so because their water supplies cannot be set independent of each other. Therefore disaggregation of the generation market would be further limited to distinct river systems. - 11 1 would be captive to the dominant player(s) who could raise prices greatly, even above 2 East Coast market prices. This represents the "classic" case of monopoly power. 3 Alternatively, if there were no transmission constraints on imported electricity, competing 4 suppliers from the larger market outside the province could control potential generation 5 market power in Québec, as there would be no constraint on access by them to buyers 6 within the province. Hydro-Québec would have to compete for customers. It could not 7 command a price above the market price. 8 The reality is between these two extremes of near-absolute generation market power and 9 no generation market power. The existence of a very large constraint on import of 10 electricity – i.e. near-isolation of the market – would mean that the hydro generators 11 would continue to have domestic market power because domestic buyers' purchase 12 options would be limited to supply from within the province once further imports were 13 not physically available. With nowhere else to turn, buyers would continue to be captive 14 and prices could be forced above the market price, as in the monopoly case. 15 For these reasons, introduction of unrestricted competition in Québec would not make 16 economic sense. The conditions necessary for unrestricted competition to be efficient do 17 not exist. 18 The benefit of hydro costs below competitive prices is described as an "entitlement", 19 "endowment" or "acquis tarifaire". The entitlement is an inherent property of the hydro 20 dams. Setting rates at average cost allocates the entitlement to domestic customers. If, 21 alternatively prices were at competitive levels, the entitlement would belong to the 22 shareholder, rather than the customers. The entitlement can only be eliminated if 23 competitive prices go down, for example through the development of new generation 24 technologies, or if average costs of the hydro systems go up, for example through 25 uneconomic investment. 26 If the "Hydro" provinces do not implement fully competitive generation market 27 structures, prices of power for sale inside the provinces, whether to retail customers or to Finally transmission system load/generation balancing requirements further restrict the autonomy of dam operation decisions. - 12 1 the limited number of wholesale buyers, will necessarily continue to be regulated, or 2 controlled by governments. Below, the two principal models for regulation -- PBR and 3 Cost of Service -- are discussed. 4 5 3.2. 6 Performance-based regulation (PBR) 7 8 PBR was originally designed to reduce problems of over-capitalization and "managerial 9 slack"22 connected with cost-of-service regulation. PBR seeks to improve utility 10 efficiency by reducing profit where expenditure is not strictly required to provide service. 11 This may be achieved by extending the time between rate cases, (or equivalently, by 12 freezing rates), or by employing external measures of cost for the purposes of setting 13 rates. The latter case includes price caps and revenue caps. Price caps generally tie rate 14 increases to inflation, less a factor to account for productivity improvements ("CPI minus 15 X"). Revenue caps set a total revenue requirement in terms of specified revenue growth 16 allowances, which typically reflect growth in the customer base as well as productivity 17 gains. Revenue caps set revenue requirements in total, not rates. 18 A full discussion of PBR is beyond the scope of this report. PBR has been in existence for 19 many years and has strengths and weaknesses. Some specific concerns with its use in the 20 case of Québec are raised below. 21 However, there is one completely general issue regarding PBR in this, the initial stages of 22 regulation. Price and revenue caps pertain to growth rates applied to base year rates or 23 revenue requirements. The regulator may conclude that the growth rates are fair and 24 reasonable, but could not conclude that the proposed prices are fair and reasonable unless 25 it had also determined that the prices or revenues to which the increases apply were also 26 fair and reasonable. At this stage, the regulator has made no determination as to whether 22 Also called "X-inefficiency". - 13 1 the existing rates, especially the L-rate upon which Hydro-Québec's proposal is based, is 2 fair and reasonable. 3 The purpose of this proceeding may be to recommend methodologies as opposed to 4 numerical values. However, the above logic applies to both numerical values and 5 methodologies. In the latter case, the Régie could at most conditionally conclude that a 6 price/revenue cap methodology would produce a fair and reasonable outcome. The 7 conclusion would be subject to acceptance of the (un-reviewed) hypothesis that the 8 methodology used to generate the L-rate is also fair and reasonable. However, 9 Hydro-Québec appears to argue that the Régie should not independently investigate the 10 latter assumption at this stage.23 11 In any case, PBR has the following difficulties and complexities in Hydro-Québec's case: 12 1. Hydro-Québec is subject to wide and uncontrollable revenue and cost variations due to 13 streamflow variation and interest rates, respectively.24 Within PBR, these 14 uncontrollable events are typically taken care of by exogenous (so-called "Z-term") 15 changes to the cap formula. In Hydro-Québec's case they may be substantial enough to 16 render the "CPI - X" part of a price cap formula, or a revenue growth allowance of 17 relatively little effect. The intent of the (retail) price freeze is to isolate customers from 18 these effects, but the risk could easily fall onto customers after the freeze is removed, 19 for example through the use of additional borrowings during the freeze. 20 2. The reservoirs and generators themselves represent, by and large, fixed costs. The 21 controllable costs of generation service lie in relatively minor areas such as 22 maintenance and operation. The productivity gains available under the PBR incentive 23 would be small, compared to thermal systems with a higher proportion of controllable 24 generation costs. 23 Response to Régie Information Request #1 Question 1. The response appears to suggest that the Régie need not concern itself with either numbers or methodology and Hydro-Québec offers no evidence to suppport either. 24 The Strategic Plan also shows other uncontrollable risks in exchange rates, temperature and the price of aluminum (p. 51). - 14 1 3. A price freeze is not a price cap. In a hydro system with on-going debt amortization, 2 permanent reservoirs whose energy capability does not depreciate, few operating costs, 3 and no price risk relating to exhaustible fuels, the rates needed to recover embedded 4 costs could go down over time. The shareholder would then make profits in excess of a 5 reasonable return simply by staying at the cap.25 6 4. PBR requires an initial revenue requirement, based on the cost of service, from which 7 caps may be defined. As indicated above, this has yet to take place in a regulated 8 setting. 9 It should be noted that the Hydro-Québec proposal is not a price cap. For example, there 10 is no productivity factor brought forward (or defence of an implicit value of zero), no 11 proposed period until the next review and no regulator-approved cost base from which to 12 begin the growth-capping process. Hydro-Québec agrees that its proposal is not a price 25 Recent events in BC provide a cautionary story. The government capped the residential rates of BC Hydro in 1996, through the Tax and Consumer Rate Freeze Act. Despite the use of the word "freeze" in its title, nowhere in that Act does it state that rates must not go down. BC Hydro had a very profitable year in 1997/98, based on strong exports. However, Special Direction 8 to the BC Utilities Commission limits BC Hydro's rate of return on equity. On November 18, 1998, the industrial customers applied to the BC Utilities Commission for a rate reduction of 7.5%, based on a preliminary reading of financial results and in accordance with the Commission's powers to enforce the Special Direction. The residential customers filed for a rate review at the same time. Then, on November 25, the government amended Special Direction 8 to the BCUC, including, among others a provision that: "The Commission must determine any matter respecting B.C. Hydro in a manner that permits B.C. Hydro to undertake any construction, enter into any contract or modify its rates in a manner that complies with any government policy directive." On March 5, 1998, the residential customers commenced a court challenge to the amendment, arguing that it abrogated the statutory power of the Commission. The industrial customers and an association of environmental interests subsequently joined the challenge. Then, on March 13, the government re-amended the Special Direction, removing the above paragraph, among other changes. Finally, on March 27, it announced the British Columbia Hydro and Power Authority Rate Freeze and Profit Sharing Act, which states that "the rates and schedules that were in effect on December 10, 1997 and that are prescribed by the regulations are the only lawful, enforceable and collectable rates that the British Columbia Hydro and Power Authority may collect, charge or enforce from December 10, 1997 to March 31, 2000 for the services to which those rates apply". December 10, 1997 is one day before the Commission made Hydro's existing rates interim as part of the rate review process. In effect, the government appropriated the surplus revenue through legislation, converting a cap to a freeze, and, it would seem, after realizing that it might not have been successful through direction to the regulator. - 15 1 cap in the conventional sense. Furthermore it agrees that the starting point for price caps 2 is cost of service. 3 "La seule 4 de type “price cap” est que dans les deux cas, on retrouve une réglementation par 5 le prix et que ce prix est fixe pour une certaine période de temps. Mais 6 Hydro-Québec n'a jamais prétendu que sa proposition correspondait à un “price 7 cap” comme ceux que l'on retrouve typiquement dans la réglementation. 8 Généralement, le point de départ d'un “price cap” est le coût de service. Ensuite, 9 un “price cap” est généralement associé à divers paramètres tels un facteur de association qu'Hydro-Québec fait entre sa proposition et une approche 10 productivité, le taux d'inflation et des variables exogènes. On ne retrouve aucun 11 de ces paramètres dans la proposition d'Hydro-Québec."26 12 In sum, PBR is not the logical place to start in the context of this, the first regulatory 13 examination of supply rates. That process should focus initially on costs as a basis for 14 determining how much the utility should collect from tariff customers. Once revenue 15 requirements are set, they may be allocated to customer classes and rates evaluated on the 16 basis of revenue collection in relation to costs of service. PBR is also unlikely to be the 17 appropriate means of regulating the supply price in the future, for the first three reasons 18 discussed above. 3.3. 19 Allocated cost of service 20 As indicated above, any initial quantitative recommendations or decisions on rates should 21 be based on costs. In particular, if the energy supply price is to have economic meaning, it 22 must be based on costs to Hydro-Québec as a whole, or Québec as whole, and not internal 23 transfer prices as proposed. Even if the Régie wishes to consider a rate proposal that is 24 not based on costs, it is difficult to see how it could make judgements about the proposal's 25 effectiveness or fairness unless it had the appropriate cost information. 26 It is assumed here that "effective" means that retail rates recover, in total, the embedded 27 costs of generation, transmission and distribution prudently used to serve tariff customers, 26 Response to AQCIE Information Request 18 a) - 16 1 i.e. a revenue requirement based on total embedded costs. Rates must then be designed 2 and the revenue under each rate estimated. Collectively the rates should collect an amount 3 equal to the given revenue requirement. Determination of the fairness of the rates among 4 tariff classes would then be based on: 5 1. An allocation of embedded costs among the tariff classes, and 6 2. A comparison, for each tariff class, of revenue earned under the proposed tariffs with 7 the allocated costs of that class. 8 Fully-Allocated Cost of Service (FACOS) is a standard methodology for allocating 9 embedded costs. FACOS contains the following elements: 10 11 12 13 14 15 16 17 Identification: define the costs to be included and categorize them by rate base and expense items; Functionalization: categorize rate base and expense items into generation, transmission, distribution and other; Classification: Split the functionalized costs into "demand", "energy" and "customer" service parameters; Allocation: Allocate the functionalized and classified costs to the different rate classes. 18 This methodology could be adopted by the Régie, as is. It is used in regulatory 19 proceedings in BC and Manitoba. However, the Régie may also wish to re-think the 20 classification step to be consistent with concepts emerging from electricity industry 21 reforms. Traditional integrated utility planning considers "energy" and "capacity" (or its 22 billed analogue, "demand") as two distinct delivered products. These are jointly provided 23 by a single system that includes generation, transmission and distribution. This in turn 24 requires that functionalized costs be split into components corresponding to energy and 25 capacity. In some cases, this is straightforward: 100% of transmission capital cost 26 assigned to demand or 100% of fuel cost to energy, for example. However, allocating 27 hydro generation to demand versus energy is less straightforward. Various conventions - 17 1 have arisen, but, since they are divisions of common, sunk costs of assets that provide 2 both energy and capacity, classification is somewhat arbitrary.27 3 However, it may not be necessary to make those judgements. The requirement to classify 4 generation into demand and energy could be reconsidered, given the development of 5 electricity markets and utility de-integration. This would be consistent with 6 Hydro-Québec's view: 7 "L'ouverture des marchés et la concurrence qu'elle entraine nécessitent également 8 que le mode de réglementation de la production retenu pour le Québec soit adapté 9 à ce contexte et qu'il soit équitable par rapport à ce qui est exigé de la 10 concurrence" (Proposal p. 1) 11 A market-sensitive approach would consider electricity generation the way the market 12 does: as a single commodity measured in kwh. Generators produce the electricity 13 commodity while transmission and distribution systems simply deliver it, losing some 14 along the way. Wholesale buyers or customers purchase the commodity from electricity 15 suppliers and independently rent capacity on the wires needed to deliver it to them. Using 16 this model in a regulated context, generation costs would not need to be split into energy 17 and capacity components, nor would generation energy costs and generation capacity 18 costs need to be separately allocated across customer classes.28 Put another way 19 generation costs would be recovered through sales of kwh of electricity, not sales of the 20 capacity that allows kwh to be produced, in the same sense that there is no market in 21 which vegetable growers (electricity producers) sell rights to use their greenhouses and 22 tractors (production capacity) to grocery shoppers (electricity buyers). Allocation of 27 Hydro-Québec's response to AQCIE Information Request 39e) describes several methods. For example, the BC Hydro 1991/92 FACOS study classifies 100% of powerhouses, power equipment and switchgear to demand, and splits dam and reservoir facilities 27/73 between demand/energy. The overall split is 55/45 demand/energy. The 1995/96 and 1996/97 FACOS use 50/50 splits. Several other methods have been used in past studies. 28 Some portion of "pure" generation capacity costs may appear in the market as an ancillary service (e.g. generation reserves that can be bid into an ancillary services market). But in the competitive commodity market, a traditional (generation) capacity contract would be viewed in terms of a contract for the (future) right to buy kwh – an option contract for the commodity – and not the firm purchase of capacity. - 18 1 generation costs to different rate classes would then be on the basis of energy 2 consumption, plus losses. 3 The market value of a kwh of supply is different from the embedded unit cost of 4 electricity supply. Therefore pricing all generation at market value would not produce the 5 same result as assigning 100% of embedded generation costs to energy in a FACOS 6 process. Nevertheless it would be desirable to reflect properties of the market price in the 7 supply rate. The market price represents an opportunity value of electricity to 8 Hydro-Québec. Consideration of market price characteristics in domestic supply rates 9 would support the development of economically efficient price signals to domestic 10 customers, assisting Hydro-Québec to realize the greatest value from its operations. 11 Important characteristics of market prices and some options for rate design based on them 12 are discussed below. 3.4. 13 Unbundled costs versus unbundled tariffs 14 15 Once costs are split into electricity supply versus electricity transmssion and distribution, 16 tariffs can be split into components that reflect the costs of electricity supply separately 17 from the costs of transmitting and distributing it. It is not sufficient for these purposes to 18 simply have separate billing demand and energy charges within the tariff. 19 For example, the current L-rate structure charges separately for billing demand 20 (corresponding to capacity) and for energy consumed, but the proposed supply price (2.5 21 cents/kwh) does not appear in the tariff.29 It is also not clear, on the basis of the proposal, 22 whether or not any, or what portion of allocated generation capacity cost (if indeed it is 23 allocated) is included in the demand charge. In short, the tariff does not necessarily show 24 prices "PE" for electricity supply and "PT" for transmission such that the bill is the sum of 25 consumption of electricity at price PE and transmission at price PT. Customers may wish 29 For example, the energy charge is 2.38 cents/kwh (or 2.42 if the 1.6% general rate increase figure is applied [see Annexe D]). If the customer increases electricity consumption by 1 kwh, but does not increase billing demand, it pays 2.38 or 2.42 cents more, whereas the proposed rate would indicate that the cost of supply increased by 2.5 cents. - 19 1 to see these prices, which reflect costs of distinct enterprises within the context of vertical 2 de-integration of utilities. Hydro-Québec agrees that the current L-rate is a bundled tariff. 3 "Comme tous les tarifs d'Hydro-Québec, le tarif L est un tarif intégré qui ne 4 distingue pas le prix de la production du prix du transport." (proposal p.20) 5 It is important to note that tariff unbundling has financial consequences for customers and 6 is not simply the provision of additional information. Individual customers' bills may 7 change under tariff unbundling. Assuming that rates recover embedded costs for the given 8 rate class, total revenue collected from the rate class would not change. However some 9 customers' bills would go up, while others' bills would go down.30 10 Customers would require tariff unbundling in preparation for a competitive electricity 11 supply market. However, if competition is not an option, they may still wish to see 12 separate prices for electricity supply and transmission. Tariff unbundling would also help 13 simplify the development of market-sensitive rates because market-sensitivity applies 14 only to the electricity supply portion of costs. 15 In its proposal, Hydro-Québec argues that tariff unbundling would engender confusion 16 among customers.31 Most or all large customers are able to pay for expertise in 17 understanding and controlling electricity bills. Even a 5 MW load will pay approximately 18 $1 million per year for delivered electricity. In any case, most L-rate customers belong to 19 industries that now have ten or more years of experience in separately contracting for gas 20 commodity (with competing producers) and gas delivery (with competing shippers). It is 21 difficult to imagine this would be less complex than choosing consumption levels in 22 electricity commodity and electricity delivery from a single supplier. 23 30 For example, in the case of rate L, unbundling could preserve the rate structure as a "demand" [transmission] charge in $/kw-month and "energy" [electricity supply] charge in cents/kwh. However it could shift the proportions of a fixed total revenue requirement for the L-class between amounts recovered for energy/electricity supply versus demand/transmission. This would increase the average bills of some customers and reduce it for others, depending on load factor. 31 See AQCIE Information Request 35 b) and f), and responses. - 20 3.5. 1 Characteristics of market-sensitive pricing 2 3 The most significant characteristic of the market price is its variation over time. As 4 generation comes on the market in the U.S., the variance of prices over time has 5 increased, both daily and seasonally. The variance reflects variations in operating costs of 6 marginal, mostly thermal plant as the specific type of plant at the margin varies with 7 demand. 8 While price variability is characteristic of spot markets and power pools generally, many 9 buyers will enter into contracts that do not vary with the spot price, such as options and 10 contracts for differences. Nevertheless, it is expected that the market as a whole will 11 continue to show short term price variations significantly greater than prior to the 12 introduction of competition. 13 In view of its storage capability, Hydro-Québec may pay special attention to these 14 variations in market prices because it can use its unique (for the East Coast market) 15 storage capability to optimally time export sales. Estimating volumes and prices for these 16 opportunities may be complex. Variables to be taken into account may include 17 streamflow conditions, line loadings and forward price curves in the export market. 18 Congestion pricing for transmission constraints within the US may also need to be 19 considered. 20 Hydro-Québec might also use time-varying prices to reduce its own costs. 21 Hydro-Québec's own demand "spikes" on cold winter nights, possibly requiring 22 expensive purchases or thermal generation.32 In the long run, time-sensitive pricing could 23 be an option for reducing new generation capacity investments. At any given time, 24 therefore, the opportunity cost of electricity may be an export price, a domestic system 25 operating cost, or a domestic system investment cost.33 " .. For example, costs incurred during peak periods (winter)… will be higher because this period requires the use of costly thermal power plants and additional hydroelectric capacity" (Long-Term Rate Orientations, Development Plan, 1993, p.41). 32 33 Time-sensitive pricing can also defer transmission and distribution investment and is therefore a potential tool within transmission and distribution planning. - 21 1 Incorporation of the resulting time profile(s) of opportunity cost would then be reflected 2 in prices offered to domestic customers, subject to the constraint that total revenue 3 collected from each customer class approximate that class' allocated costs. Consideration 4 of the types of customers to whom such rates would be appropriate should take into 5 account the costs of metering and accumulating billing information at the required time 6 intervals and the customers' own flexibility in responding to price signals. 7 Time sensitive rates include traditional utility rates such as seasonal and time-of-day 8 rates. The development of a competitive market provides an opportunity for a greater 9 variety of price signals and perhaps greater customer interest in rate options. Competitive 10 electricity markets (outside of, as well as in the US) are also pushing the technology 11 frontier, perhaps making market-sensitive rates more acceptable and effective. 12 "In the long term, new technologies are likely to play a key role in determining the 13 level of consumer response to changing prices. Faced with more volatile prices, 14 equipment vendors will develop, and consumers will seek to purchase, equipment 15 that allows for better control of electricity use. For example, intelligent electricity 16 meters, which monitor the electricity use of a household or business minute by 17 minute are already entering the marketplace. Combining this equipment with a 18 real-time pricing signal and the ability to control key appliances or equipment may 19 enable consumers to reduce electricity usage during high cost periods. Many 20 residential customers participating in demand-side management programs are 21 already familiar with the boxes connected to their hot water heaters and/or air 22 conditioners that allow local utilities to shut them off during periods of high 23 demand. Similarly, some commercial establishments have cool storage systems 24 that make ice during low cost periods and then use it for space cooling when price 25 srae higher. Such systems may become more prevalent where competitive 26 electricity prices and time-of-use rates are implemented."34 34 Electricity Pricing in a Competitive Environment: Marginal Cost Pricing of Generation Services and Financial Status of Electric Utilities; August 1997, Energy Information Administration, US Department of Energy, p. 2-3. - 22 1 Examples of market-sensitive rates in Québec, BC and Manitoba are described below. 2 These are provided to illustrate potential options, in terms of tariff structure, time interval 3 (e.g. hourly spot price versus seasonal interruption) and customers eligible. Most of the 4 effort has been applied to large customers. However, small customers can also supply 5 price-responsiveness. In New Zealand, for example, retail suppliers rely on ripple 6 control35 of hot water heaters to provide load reductions that are then bid into the 7 quarter-hourly reserve market. One major retailer there is studying how to aggregate 8 different load reductions to create biddable demand-side "packages"36 9 Market-sensitive pricing and load factor adjustment 10 In a competitive market, load factor is irrelevant because capacity is not a traded 11 commodity. Any two purchasers buying at the same time pay the same amount per kwh, 12 after adjusting for line losses. The average price, per kwh, is the sum of the prices paid at 13 different times multiplied by the amounts bought at those times, divided by total 14 consumption.37 15 In a competitive market, low load factor (residential and small commercial) customers 16 would generally pay a higher average annual price per kwh than high load factor 17 customers because low load factor customers' energy consumption tends to be greatest 18 when demand, and therefore prices, are high. Conversely a flat (time-undifferentiated) 19 load would pay less than the average because, relative to the average of all customers, its 20 use is concentrated less on expensive (peak) times. 21 Time-sensitive pricing is a more finely-tuned instrument than load factor adjustment. For 22 example, if a particular customer were on time-sensitive pricing, and could self-generate 23 at some expensive times, or shift purchased consumption from expensive times to less 24 expensive times, its bill could go down even though its load factor might not increase. 35 Remote operation through signals over power lines 36 S. Terry, Simon Terry & Associates, Wellington, NZ, pers. comm. 37 If one bought 5 kwh at 3 cents/kwh and 2 kwh at 6 cents/kwh, the average cost would be [5 x 3 + 2 x 6]/[5 + 2] = 3.86 cents/kwh - 23 1 Differences between low- and high load factor customer costs also arise in the 2 transmission and distribution system. These would be determined through cost allocation 3 of transmission and distribution, which is independent of electricity supply cost. 4 5 4. Examples of market-sensitive supply rates 6 7 The theoretically best market sensitive rate would simply be an hourly spot market price, 8 scaled appropriately so that revenue equals embedded cost. However, this type of 9 volatility is unlikely to be attractive to most customers, and is not necessary for efficiency 10 objectives. An efficient rate design can still lead to total bills that do not vary too greatly, 11 while providing price signals that affect consumption at the margin. For example, a fixed 12 amount of load may be supplied at a standard tariff, with the increment subject to 13 market-sensitivity. Rate design should also identify the most probable types of beneficial 14 customer responses and adjust the frequency of price change accordingly – e.g. a seasonal 15 rate versus light/heavy load hours versus opportunistic pricing, such as interruptible 16 service or demand-side bidding. Market sensitive rates are more likely to be approved if 17 they are optional. This also reflects the market's characteristic of providing customers 18 with a range of choices. 19 Market sensitive rate options include: 20 1. Interruptible, seasonal and time of day rates 21 2. Real-time tariffs, generally taken to be a two-part rate in which incremental 22 consumption is billed at a market price or market-sensitive price. 23 3. Demand-side bidding, in which the buyer may offer to reduce load for a short time in 24 return for a payment from the supplier. The supplier can then sell the electricity in the 25 market. The supplier's price offers may be regularly posted 26 27 4. Long term wholesale contracts for energy from the major hydro plants. This option has greater scope. It essentially transfers a fixed block of energy, representing most, or all - 24 1 of the output (under specified streamflow conitions) of the large hydro assets providing 2 the entitlement, to transmission owners/distributors at embedded cost, while leaving 3 the remainder of generation (say the "top" 10 - 20%) to be sold fully competitively. 4 5 Examples at Hydro-Québec, BC Hydro and Manitoba Hydro 6 The rate structures of Canada's "Hydro" utilities presently contain many different 7 components that cause the average prices paid by customers to be different at different 8 times, such as inclining block rates for customers whose loads vary seasonally and excess 9 demand charges that vary by season. By way of illustration, some industrial/large 10 customer rates are described below. 11 BC has been experimenting with alternative industrial rates since the early 1990's when 12 BC Hydro produced an Industrial Rate Proposal. The tariff was brought forward at a time 13 of apparent tight supply. The rate was a two-part tariff, designed to collect embedded cost 14 in total, but such that customers would pay the long run marginal cost for approximately 15 half their consumption (the second "block" of the tariff).38 The proposal was theoretically 16 sound, but it was administratively complex and required predictions about long run 17 supply costs, which were seen as quite uncertain. The tariff was not well-received by 18 customers. In addition to its complexity and uncertainty, they were concerned about it 19 becoming mandatory and felt they were being "pushed" into self-generation. The proposal 20 was eventually rejected by the BC Utilities Commission.39 21 After a number of attempts to find satisfactory designs during the intervening years, BC 22 Hydro Tariff 1848 (Real time pricing) or RTP was approved in July 1997. It is an optional 23 rate for large industrial customers. It provides a pass-through of the Mid-Columbia price 24 index (split by heavy/light load hours) on consumption that is incremental to a 38 The proposal would produce a rate such that average revenue paid varies seasonally because the potential self-generation capability of some major customers (pulp mills) varies seasonally. See e.g. Optimal Electricity Generation in Pulp and Paper Mills with Seasonal Steam Requirements; Helliwell, J.F. and M. Margolick; Global Economics: Essays in Honour of Lawrence Klein; B. Hickman, ed. MIT Press, 1984. 39 Decision, April 24, 1992 - 25 1 pre-determined Customer-Based Load (CBL). CBL is charged at the standard industrial 2 rate. No transmission charge is applied to the Mid-Columbia price. 3 The default CBL is the average of the past three years' consumption. In this case, market 4 prices are available only to "new" load. However, the RTP tariff provides for reductions 5 in CBL for load retention purposes, under approval by the BC Utilities Commission. 6 Since its inception, approximately 18 customers have utilized the rate. The 7 Mid-Columbia price (which excludes transmission in BC) was, until recently, below the 8 standard rate (which includes generation and transmission within BC), making it 9 advantageous, independent of any value of time-sensitivity. However, recently the 10 Mid-Columbia price has gone up, eliminating most of the benefit of lower average price. 11 The majority of sales under the tariff have been as a result of reductions in CBL for load 12 retention purposes and it has generally been considered by observers to be a load retention 13 rate. 40 14 More recently, the government announced "virtual access" for load at each facility of an 15 industrial customer.41 The rate will provide a pass-through of a market price, to which a 16 rate for transmission in BC will be added, for up to 25% of total (not incremental) load. 17 The details are now being worked out. 18 The BC experience has not been successful in terms of utility/customer/government 19 relations. It suggests that it is essential to distinguish, in policy, between rate options for 20 load retention or economic development purposes versus rate options for 21 market-sensitive, optimal resource use. The following distinction might be useful: if the 22 rate reduces the customer's bill below what it would otherwise be, for a fixed level of 23 consumption and a fixed time-profile of consumption, the rate would be for load retention 24 or economic development purposes. A "pure", market-sensitive rate, in the sense used 25 here, would reduce bills when, and only when customers change consumption or its time "The Industrial Customers stated that Rate Schedule 1848 [RTP]… will only be attractive to customers whose CBL [Customer-Based Load] has been adjusted downward for load retention purposes…. Accordingly they characterized Rate Schedule 1848 as being primarily a load retention rate." BC Utilities Commission; Industrial Service Options Application; Decision, July 16, 1996, p. 8. 40 41 Ministry of Employment and Investment, March 27, 1998, Press Release and Backgrounder - 26 1 profile, relative to consumption or time-profile that would occur under the rate otherwise 2 in effect. 3 Among other offerings, Manitoba Hydro has had, since 1991, market-sensitive 4 interruptible rate programs, targeted to different customer groups.42 The rates are 5 designed to make energy available to Hydro for alternative sales for weeks, up to several 6 months, on a seasonal basis. The Dual Fuel Heating program applies to up to 100% of 7 new commercial/institutional heating loads. These must have long term alternative 8 supply, such as oil or propane. Typical eligible customers include agricultural enterprises, 9 schools and the Town of Churchill. The two-year-old Surplus Energy Service to 10 Self-Generators rate applies to those who can supply their own generation to defer supply 11 from Hydro on a longer term basis. It currently has no subscribers. Typical eligible firms 12 would include limestone and gravel quarries that have diesel generation back-up. 13 The third, the Industrial Surplus Energy (ISE) Rate, provides about 90% of sales under 14 the interruptible rate program. It applies to customers whose total load (firm and surplus) 15 exceeds 2000 kVA (approximately 2 MW). Except under certain conditions, eligibility is 16 limited to 25% of incremental load for existing customers and 25% of total load for new 17 customers. Hydro guarantees availability 60% of the time during summer months and 18 60% of the time during winter months, but may otherwise interrupt with appropriate 19 notice. The customer does not require back-up to be eligible. The price on the ISE rate is 20 designed to make Hydro revenue-neutral, on an expected value basis, relative to 21 alternative sales. The program also has a "Spot Market Replacement Energy" provision: 22 upon request, and if energy is available, Hydro will supply electricity (instead of 23 interrupting) at a price based on the utility's opportunity cost at that time. The price offer 24 is made weekly. 25 The total number of large industrial customers in Manitoba is small and there were no 26 interruptions in the first five years of the program. There were six weeks of interruption 27 last year. However, the three programs, as a package, appear to be successful. With 23 42 R. Wiens, Manager, Customer Rates and Policies, Power Smart Energy Services, Manitoba Hydro, pers. comm. - 27 1 existing customers and 11 potential new customers, Hydro anticipates that demand will 2 exceed the annual limit of 500 GwH and the Public Utilities Board approved an increase 3 in the limit to 1000 GwH in early 1988.43 4 Information about Hydro-Québec's real-time pricing options are contained in its tariff 5 book. They are considered experimental and apply to M-class and L-class customers. For 6 example, L-class customers on the rate are charged the standard rate for base 7 consumption (generally set at historic levels). Consumption above that is charged at the 8 real-time price; consumption below the base amount is credited at the real-time price. The 9 real-time price varies hourly and is an energy price only (i.e. contains no demand charge). 10 The real-time price is set at the marginal value of storage, if the current marginal source 11 of supply is a hydroelectric plant, and is set at the variable cost of the thermal plant or the 12 value of a purchase or foregone sale or the value of a management contract, if a thermal 13 plant/purchase/sale/management contract is at the margin of Hydro-Québec's supply. 14 5. 15 The Hydro-Québec proposal is unconventional. One would normally expect an initial 16 definition of an electricity supply price to be based on the costs of electricity supply to the 17 Applicant. However, the Hydro-Québec proposal anchors the supply price methodology 18 to a pre-existing retail tariff whose relation to costs has not been assessed by the 19 regulator. It is therefore difficult to see how a regulator could assess the current proposal 20 until it understands the basis for that retail tariff. In particular, if the L-tariff design does 21 not appropriately reflect the structure of costs to Hydro-Québec of delivered electricity for 22 that customer class, and the transmission rate design does appropriately reflect the 23 structure of costs of transmission for that customer class, then the proposed supply price, 24 being the difference of the two, would not reflect the costs to Hydro-Québec of electricity 25 supply for that customer class. 26 The proposed supply rate is not a retail rate. It would appear in a retail tariff schedule only 27 if Hydro-Québec unbundled its retail rates. Hydro-Québec does not propose unbundling 43 The Hydro- Québec proposal Manitoba Hydro Insights February 1998, Vol 7, Issue 4 - 28 1 its retail rates. Therefore, except for the small wholesale load, the proposed supply rate 2 has no effect on the prices customers pay. However, if the proposed supply rates were 3 used within unbundled rates, then the proposed supply rate would in no way contribute 4 towards reflecting marginal costs in the prices customers pay. 5 The proposal is not a price cap proposal, although it is regulation on the basis of price, as 6 opposed to cost. For reasons discussed in section 3.2 above, regulation on the basis of 7 price would not be appropriate for Hydro-Québec at this initial stage and appears to be of 8 dubious merit for the future. 9 Hydro-Québec's proposal adjusts for capacity on the basis of the average load factor for 10 the customer class. The proposed rate does not differentiate between customers with 11 different load factors within the same rate class and is therefore less refined than any 12 retail rate that charges for billing demand, such as today's Rate L. Differentiation on the 13 basis of load factor in retail rates is based in part on transmission, or transmission and 14 distribution system usage. This variation should not be reflected in the supply rate. 15 However, to the extent that a high ratio of peak to average use imposes higher unit costs 16 of electricity supply, such differentiation should be included in the supply rate on a 17 customer-by-customer basis wherever demand is metered or wherever energy is metered 18 sufficiently frequently. 19 Load factor considerations apply wherever demand/energy rates are used in preference to 20 pricing by time interval. As suggested above, pricing by time is more consistent with the 21 emerging market structure than is load factor adjustment, whether by customer class or by 22 individual customer. 23 The proposed formula for load factor and loss adjustments, used to determine different 24 supply rates for different customers classes, is directionally correct. However, it is 25 difficult to interpret. While many directionally correct possible formulas exist,44 26 Hydro-Québec cannot envisage alternative formulas that achieve correct directionality, 44 For example, the losses term (1+ Pertes)/1.083 could be applied only to the first term; or implicit demand/energy splits other than that based on system load factor could be used (see e.g. footnote 27); or the load factor adjustments could be replaced by numbers representing share of coincident peak, and so on. - 29 1 has no studies relating to the proposed formula and cannot provide the name of any other 2 utility that uses it. 45 3 The rates proposed in Annexe F are very unlikely to be "revenue-neutral", in the 4 following, necessarily restricted, sense. 46 Suppose, illustratively, that all retail rates in 5 1997 collected $7 billion in total. Suppose the cost of service for transmission, 6 distribution and any other services to be included in the cost of service, other than 7 electricity supply, was $3 billion in 1997. Then the rates in Annexe F would be revenue 8 neutral, in the sense used here, if they would have collected exactly $4 billion, based on 9 the consumption of each customer in 1997. The proposed supply rate for Class L is (by 10 definition) revenue-neutral, as long as the transmission rate used in the proposal collects 11 the cost of service of transmission and no other costs of service apply to L-rate 12 customers.47 But it is not evident that revenue neutrality, in the sense used here, applies to 13 the other rate classes individually, nor for the total of all rate classes. Given the 14 complexity, and highly varied design of the current portfolio of rates, it could only be true 15 by coincidence. 16 The formula defining the rates in Annexe F is not internally consistent. Suppose 17 Hydro-Québec sold only electricity supply – no transmission or distribution – and sold it 18 at the prices shown in Annexe F. Then, by definition, its average revenue would be total 19 revenue divided by the total quantity sold. Total revenue would be the sum of revenues 20 from all rates classes. The revenue from each rate class depends on the quantity sold to 21 that rate class. However, all the prices, including the average (2.81 cents/kwh) in Annexe 45 AQCIE Information Request 40 and response. 46 In general, revenue-neutrality may be defined for a given rate class or for tariff revenue in total. Revenue-neutrality occurs, by definition, when re-rating all bills according to a new rate or set of rates would not change total revenue. Tests for revenue neutrality may be done on the basis of consumption in a recent year, or on the basis of a forward test year. It is not possible to use the standard definition of revenue-neutrality in the context of the rates in Annexe F, because they would not actually collect any revenue, except from the municipalities. 47 This assumes there are no costs other than transmission and supply in the L-rate [See Response to Régie Information Request #1, Question 7.6] - 30 1 F are defined without reference to quantities. Therefore the actual average revenue and 2 the assumed average revenue of 2.81 cents/kwh could be equal only by coincidence.48 3 Finally, Hydro-Québec's competitive position would not be compromised by having to 4 make a FACOS (Fully-Allocated Cost of Service) study publicly available. FACOS 5 results pertain to embedded costs, while competitive price is set by marginal cost. Even 6 knowledge of current-period variable costs of hydro operation would have little impact. 7 Hydro plants' variable costs are so low that hydro would rarely if ever be competing at the 8 margin. In this case, competitors' knowledge of hydro plants' costs could not affect the 9 volumes the hydro plants could sell, nor the price received in the market. That price 10 would be based on another supplier's costs and not the costs of hydro plants. 11 6. 12 Hydro-Québec's proposal concerns hypothetical prices, not costs or rates, for 97% of the 13 its customer load. This is an unusual first step in the process of regulation. Accepted 14 regulatory practice would start with a revenue requirements hearing. A revenue 15 requirements hearing may occur in the near future. It would require the provision of cost 16 of service information. In this respect, the Régie's response to positions of Hydro-Québec 17 in this proceeding may affect the usefulness of a revenue requirements hearing. In 18 particular, Hydro-Québec does not wish to provide information about costs of service in 19 this proceeding. The reason provided, namely compromise of competitive position, is not 20 sound. But even if it were sound, the reason would apply in general, not just in the current 21 proceeding. Therefore if the Régie now accepts Hydro-Québec's reason for not wishing to 22 provide cost of service information, the Régie would also logically have to accept that 23 reason in a revenue requirements hearing, and not require the information then. This logic 24 applies even if the Régie does not see provision of the information itself as necessary in 25 this proceeding. 48 Conclusions SupposeQj is the number of kwh consumed by rate class "j"; Q is the sum of the Q j; Pj is the rate shown in Annexe F for rate class "j"; and P is the average rate of 2.81 cents/kwh. Then the equation P1Q1 + P2Q2 + … + P6Q6 = PQ is true for only specific combinations of Qj 's. - 31 1 Within the narrower confines of the current proceeding, the Hydro-Québec proposal is not 2 based on accepted principles of ratemaking – neither cost of service nor 3 performance-based. It does not reflect any element of marginal-cost pricing, which is 4 necessary for economic efficiency. It differentiates among customers with different usage 5 characteristics less than does the L-rate upon which it is based. And it is internally 6 inconsistent with respect to its formula for setting rates for the rate classes other than Rate 7 L. 8 Paradoxically, Hydro-Québec appears to have, within its portfolio, a number of retail 9 rates that contain elements of marginal cost pricing, such as real-time pricing. When it 10 comes to setting retail rates, the Régie should encourage Hydro-Québec to further develop 11 and expand this approach. The discussion above provides some information about options 12 but further specificity would depend on detailed knowledge of system and load 13 characteristics, and markets. While the examples discussed apply primarily to rates for 14 large customers, there may be substantial value for other customers, especially as 15 competitive forces elsewhere lead to new technologies appropriate to smaller loads. 16 Key principles for marginal-cost-based rates would be: 17 1. distinguishing clearly in policy between economic development rates and 18 19 20 marginal-cost-based rates (see last paragraph, p. 27) 2. consulting diligently with the relevant customers and obtaining support before going to the regulator for approval 21 3. developing options, rather than uniform, mandatory changes, and 22 4. employing time-sensitivity wherever practical, in preference to load factoring or 23 demand pricing.