Hydro-Québec Distribution

Transcription

1 1. Références : Evidence of Mark Drazen, Tableau 4, note 2, page 8 Préambule : Dans sa note 2, l'expert de la Coalition fait référence à la disposition par le Distributeur du principe de passthrough appliqué aux coûts de fourniture post patrimoniale en ces termes : «$ 28.0 MWh is the average cost of supply for the year Although an additional 1,441 GWh of sales would exceed the remaining Heritage Energy pool amount of 165,000 GWh, HQD is allowed to recover any additional cost by a passthrough.» Question 1.1 : Veuillez nous indiquer la décision de la Régie selon laquelle le Distributeur est autorisé à se prévaloir du principe de «passthrough» appliqué aux coûts de fourniture de l'électricité post patrimoniale. Response 1.1 : In Decision D , the Régie accepted this for costs of supply beyond the Heritage Energy amount: Question 1.2 : Le Distributeur demande des transferts de coûts ou «pass-on» et la création de comptes de frais reportés pour les variations de certains coûts (fourniture d électricité, transport d électricité et faits du prince) non prévues lors de l établissement des tarifs et leur inclusion ultérieure à son coût de service. La Régie accepte ce traitement pour les coûts additionnels de fourniture d électricité. (Sommaire Exécutif, Page 2) Dans le contexte où le Distributeur ne dispose pas de ce principe et où le coût de la fourniture post patrimoniale est de 6 /kwh, l'expert maintient-il ses conclusions à l'effet que le Distributeur aurait intérêt à sous-estimer la prévision de la demande. Response 1.2 : 1

2 Additional sales, beyond the amount forecast, could require the purchase of some non-heritage Energy. HQD s forecast shows 2004 purchases of 164,120 GWh of Heritage Energy (HQD-1, Document 1, Page 16). Therefore, if the forecast were increased by 1,441 GWh (as suggested in the Coalition evidence), this would result in the purchase of an additional 880 GWh of Heritage Energy and 561 GWh of non-heritage Energy. Assuming that the non-heritage Energy costs 6.0 /kwh, the average cost would be about 4.05 /kwh. The additional sales would produce additional revenue that would exceed this average cost. The average forecast revenue under HQD s proposed rates is 5.5 /kwh. Transmission and Distribution costs would not increase proportionally to the volume of sales. (The total charge from TransÉnergie to HQD, for example, is expected to remain constant in total dollars. Hence, for additional sales the amount recovered in respect of the TransÉnergie cost would be available to offset other cost increases.) As a result, the total additional revenue would likely exceed the total additional cost. 2. Références : Evidence of Mark Drazen, Table 7 page 11 Préambule : Nombre de kilomètres de réseau Question 2.1 : Selon l'expert de la Coalition, les kilomètres de réseau considérés au tableau 7 devraient-ils inclure autant les kilomètres moyenne tension que ceux de la basse tension? Response 2.1 : The amounts shown are those listed by HQD as its distribution lines. Hydro- Québec also shows that it has about 32,300 kilometers of transmission line (Profil régional des activités d Hydro-Québec 2002). A distinction between low voltage and medium voltage distribution lines could be made for the purpose of refining any measures of performance. Question 2.2 : Considérant que : 2

3 les données de kilométrage du réseau inscrites au rapport annuel ne font état que du kilométrage associé à la moyenne tension; les données 2001 et 2002 figurant au tableau 7 de la Coalition ont été interverties; les données de kilométrage moyenne et basse tension figurent au rapport annuel du Distributeur pour 2001 et 2002 (disponible sur le site de la Régie); veuillez reproduire le tableau 7 en y apportant les corrections requises. Response 2.2 : Table 7a, below, shows the calculation with both distribution and transmission/sub-transmission lines included. Table 7a Relative Growth of Subscribers, Network, Employees and Inflation Base Projected Historic Years Year Year Growth Subscribers (000) % Distribution lines km * % Transmission lines km* % Total T&D lines - km % Number of employees % *Assumes growth in 2003 and 2004 similar to The comment in the second bullet that les données 2001 et 2002 figurant au tableau 7 de la Coalition ont été interverties is not clear. Hydro-Québec s 2002 Profil régional shows the amount of 107,106 km of lines. The 2002 annual report shows a lower figure of 106,830 km with the footnote that the data were revised in 2002 in order to more accurately reflect the kilometers belong to off-grid systems. Unless the data for 2001 are correspondingly revised, it would not be 3

4 consistent to use the 2002 revised data. 3. Références : Evidence of Mark Drazen, lignes 11 à 15, page 17 Préambule : «Consequently, it is recommended that the Régie consider reducing the shared services cost, as did the Alberta EUB. Given that B. C. Hydro (which is half the size of HQD) expects to realize an average of $25 million in annual savings, this could be a conservative estimate of HQD s savings.» Question 3.1 : En ce qui concerne la réduction des charges de services partagés décidée par l'alberta Energy and Utilities Board, veuillez produire les informations suivantes : Compagnie(s) visée(s) Nature des services Cadre réglementaire des services visés (à savoir, s'il s'agit d'une réglementation sur les prix ou sur les coûts, et si ces services rendus par l'entremise de filiale ou directement par la compagnie visée) Période de référence sur laquelle s'étale la réduction Niveau de départ des charges et montant de réduction (M$) Part des charges réduites (%) Response 3.1 : The requested information can be found in the decisions of the Alberta Energy and Utilities Board (accessible on the AEUB website, under the caption Decisions & Orders Utility Issues. The relevant decisions are: Decision : ATCO Electric, ATCO Gas, and ATCO Pipelines (the ATCO Utilities) ATCO I-Tek Information Technology Master Services Agreement (MSA Module) Decision : ATCO Group Affiliate Transactions and Code of Conduct Proceeding Part B: Code of Conduct Decision : ATCO Electric Ltd. Part A: Asset Transfer, Outsourcing Arrangements, and GRA Issues Second Compliance Filing 4

5 Decision : ATCO Electric Ltd. Part A: Asset Transfer, Outsourcing Arrangements, and GRA Issues Compliance Filing Decision : ATCO Group Affiliate Transactions and Code of Conduct Proceeding. Part A: Asset Transfer, Outsourcing Arrangements, and GRA Issues Question 3.2 : À quand remontent la dernière demande tarifaire et le dernier examen du coût de service de B.C. Hydro devant la British Columbia Utilities Commission? Response 3.2 : The latest comprehensive review was in The Decision of the B.C.U.C. is dated November 24, Question 3.3 : Veuillez fournir l'évolution sur 5 ans des charges d'exploitation de BC Hydro pour les domaines de la distribution et des services à la clientèle, en distinguant la part attribuable aux charges de services partagés et les charges directes. Response 3.3 : This information is not readily available. B.C. Hydro has not heretofore provided a breakdown of costs in this detail. 4. Références : Evidence of Mark Drazen, lignes 22 et 23, page 18 Préambule : Méthode d'imputation des frais corporatifs «Therefore, on the issue of corporate costs, we would recommend using primary charges and net assets as the allocation basis.» (notre souligné) Question 4.1 : 5

6 L'expert de la Coalition recommande d'utiliser la méthode des charges primaires et d'immobilisations nettes dans l'imputation des frais corporatifs. Veuillez fournir les méthodes de répartition des frais corporatifs en usage et appliquées par les autres organismes de réglementation. Response 4.1 : The allocation of corporate and overhead costs among functions is required for utilities that are: (1) corporately segregated but within a utility holding company (i.e., separate companies, but sharing some services of a parent and/or affiliate); (2) functionally segregated (i.e., divisions of a partly or wholly integrated utility company); or (3) integrated. In the cases of a separate corporation (#1) and an integrated utility (#2), the functional allocation is not needed to establish the revenue requirement, but is still necessary for a cost allocation study (to determine the cost of service for each customer class). The increasing importance was discussed in a report for the Edison Electric Institute, Cost Allocation and Affiliate Transactions A Survey and Analysis of State Cost Allocation Issues and Transfer Pricing Policies 1, which states: Restructuring of the electric industry is having profound effects on company structures through reorganizations, mergers and acquisitions and new methods of business operation. As competition develops in wholesale and retail markets, an increasing number of utilities are rapidly moving into non-regulated business operations which will have far-reaching accounting and economic implications for regulated utilities and their non-regulated affiliates. Administrative rules governing the allocation of costs for services and products transferred between regulated utility operations and non-regulated affiliate operations are currently being considered, debated and implemented in state proceedings. In national regulatory arenas, policy guidelines addressing these critical issues are being developed for consideration by state regulatory commissions and their staff. Because of concerns that regulated utilities will cross subsidize affiliate business operations at the expense of consumers of regulated services or harm competition, regulators and competitors seek to impose strict accounting procedures on utilities to ensure that only justified costs are attributed to regulated activities. (Page 3, emphasis added) 1 6

7 Appendices B and C of that report provide an overview (a bit dated now, as the report was written in 1999) of practices of various regulatory agencies in the United States and examples of cost allocation methods. Many regulatory agencies in the United States require utilities to prepare and file a cost accounting manual, which states the methods that are to be used to allocate costs among corporate entities. This is especially important when a regulated utility has unregulated affiliates. The cost allocation procedures are subject to review and must be approved. For example, the Iowa Administrative Code states 2 : (476) Cost allocation manuals. Every rate-regulated gas or electric public utility equaling or exceeding the filing threshold in any calendar year shall file with the board a cost allocation manual on or before September 1 of the following year. If the utility has not changed its cost allocation manual since the last filing on September 1, the utility shall file a letter with the board to that effect. Refer to subrule 33.5(3) for information on updating cost allocation manuals. In the event the utility has made only minor changes to its manual regarding new accounts or new affiliates, or has modified language, the utility may file only the pages affected. The filing shall include a cover letter explaining the pages being filed. 33.5(1) Contents of manuals. Each cost allocation manual must contain the following information: a. Nonutility activities. A list, the location, and description of all nonutility activities as defined in Iowa Code section (3). b. Incidental activities. A summary of activities that are incidental to the provision of utility services and minor in size. c. Resource identification. An identification of the assets and expenses involved directly or indirectly, in whole or in part, to the provision of nonutility services as identified in subrules 33.4(1) and 33.4(2). d. Assignment methodology. A description of the cost assignment methodology. This paragraph provides an overview, explanation, and justification of the details provided in paragraphs e through h. e. Assignment rationale. A list showing the cost assignment method for each account. The list shall show for each account and subaccount identified in subrules 33.4(1) and 33.4(2) the basis for assigning costs in the account to utility and nonutility operations

8 f. Accounts and records. A description of each account and record used by the utility for financial record keeping of nonutility services, including all subaccounts. g. Assignment basis. An explanation of each assignment basis. This paragraph shall contain, for each assignment basis contained in paragraph e, a definition of the basis, an explanation of how the allocation factor is calculated, a description of each study and analysis used in developing the allocation factor, and the frequency with which each allocation factor is recalculated. h. Time reporting methods. An explanation of the time reporting methods used. This paragraph shall indicate the type of time reporting (positive, exception, or study) used for each reporting organization (e.g., executive, residential sales, and external affairs), and a description of how the type of time reporting is done in that reporting organization. i. Training. A description of the training programs used by the utility to implement and maintain its cost allocation process. j. Update process. A description of the procedures used by the utility to (1) determine when an update is needed; (2) develop the update; and (3) provide the update to the board. The treatment of corporate and affiliate costs may have to be reviewed when generation is separated from the transmission and distribution functions, as noted in a Decision of the Connecticut Department of Public Utility Control : B. COST ACCOUNTING METHODOLOGY MANUAL [12, 13] As part of the corporate unbundling plan, UI has submitted its Cost Accounting Methodology Manual (CAMM), a detailed cost accounting and transfer pricing system, which it believes provides for proper assignment and allocation of costs among the activities within the restructured company. Unbundling Plan, p. 4 and Appendix One; Tr. 2/18/99, p. 12; UI Brief, p. 6. UI envisions that the regulated utility will continue to be the primary subsidiary of the holding company and that support and corporate services will continue to be provided out of the regulated utility company. Tr. 2/18/99, pp. 11 and 12. UI does not envision any changes to the CAMM in the immediate term; however, the Company will review the CAMM over time to see if any allocators need to change as it divests its generation. Tr. 2/18/99, p As UI sells off its generation, it will look at the overall support functions to see which ones could be downsized. The remaining costs would get allocated to the Company's other business units. Tr. 2/18/99, p. 157.(Re The United Illuminating Company, 193 PUR4th 391,397, emphasis added) 8

9 An example of the method used by a corporately segregated utility is provided by Aquila Networks Canada (Alberta) allocates both General & Administrative Expense and Corporate Expense on the basis of the sum of: 1. Direct operating expenses 2. Depreciation 3. Return and income taxes An example of a method used by a functionally segregated utility is provided by ATCO Electric (both Transmission and Distribution in the same corporate structure). ATCO Electric also has charges from affiliates. ATCO Electric uses various allocators. The cost components and allocators are summarized on the attached schedule, captioned Allocation of Corporate Administration and General, which was submitted to the Alberta EUB by ATCO Electric. The effect of changing the allocation basis is illustrated by an explanation of a shift of Insurance cost from the Distribution function to the Transmission function: The allocation to the Transmission Business Unit has increased from approximately 34% in 2002 to 40% in the GTA period of The reason for the increase in the allocation to the Transmission Business Unit with a corresponding decrease in the allocation to the Distribution Business Unit is the change in the allocation for Property Damage Insurance. Property Damage Insurance is now allocated on the basis of the insurable value of the assets. In the 2001 study the allocation was based on a weighted average of employees and revenues. This change has resulted in 59% of the insurance costs now being charged to Transmission compared with only 27% in 2001/2002. The change was required as the insurable values of assets is the driver for the insurance premiums being charged. An example of the method used by an integrated utility is from Newfoundland & Labrador Hydro. NLH apportions General Plant and Administrative & General (A&G) Expenses on the following bases: General Plant subtotal of operating expenses (excl. purchased power) General Plant Software subtotal of Production, Transmission, Distribution gross plant A&G Plant-related gross P,T,D plant A&G Expense-related subtotal P,T,D and Customer Accounting expenses 9

10 In summary, while different methods have been used, it is increasingly important that the methods be examined and appropriate ones be determined. 10