ALBERTA ENERGY AND UTILITIES BOARD

Transcription

1 ALBERTA ENERGY AND UTILITIES BOARD Edmonton, Alberta DECISION U96116 re: CENTRA GAS ALBERTA INC.

2 ALBERTA ENERGY AND UTILITIES BOARD Edmonton, Alberta CENTRA GAS ALBERTA INC. Decision U /1996 GENERAL RATE APPLICATION - PHASE II File TABLE OF CONTENTS TABLE OF CONTENTS...1 PARTIES PARTICIPATING IN THE PROCEEDING...4 ABBREVIATIONS...5 REFERENCES INTRODUCTION BACKGROUND PARTICULARS OF THE APPLICATION COST OF SERVICE STUDY...11 (a) General...11 (b) Modified Partial Plant Methodology...11 (c) Classification of Gas Supply Costs...16 (d) Classification of Services and Meter Related Costs...18 (f) Other Costs...21 (g) Production and Gathering (P&G) Costs...22 (h) Customer Accounting Costs...23 (i) Functionalized Computer Costs...24 (j) Penalty Revenues...25 (k) Storage Costs RATE DESIGN CRITERIA SPECIFIC PROPOSALS FOR RATES, TOLLS AND CHARGES...31 (a) General...31 (b) Rate 1 - Small General Service...32

3 2 Decision U96116 (c) Rate 2 - Large General Service...37 (d) Rate 3 (Demand/Commodity)/Rate 13 (Transportation-End Use)...39 (e) Rate 4 - Optional Irrigation Pumping Service...47 (f) Rate 6 - Standby, Peaking and Emergency Service...48 (g) Rate 10 - Transportation Service...50 (h) Rate 23 - Industrial Buy/Sell...51 (i) Core Market Rates...53 (j) Rate 11 - Core Market Transportation (Small General Service)...55 (k) Rate 12 - Core Market Transportation (Large General Service)...55 (l) Rate (m) Rate 21/22/23A - Core Market Buy/Sell...56 (n) Rate (o) Transition Costs (Rider ΑG ) AND 1996 REVENUE EXCESS/DEFICIENCY RIDER (Rider ΑF ) TERMS AND CONDITIONS OF SERVICE...67 (a) Natural Gas Service Rules for Sales Customers...67 (b) Transportation Service Regulations...72 (c) Terms and Conditions of Service for Core Market Customers SUMMARY OF DIRECTIONS ORDER...78

4 Decision U SCHEDULES ΑA ΑB ΑC ΑD ΑE ΑF ΑG ΑH RATES, TOLLS AND CHARGES pages NATURAL GAS SERVICE RULES pages TRANSPORTATION SERVICE REGULATIONS pages CORE MARKET GAS PURCHASE OPTION AGREEMENT... 7 pages CORE MARKET BUY/SELL CONTRACT pages CORE MARKET BUY/SELL REGULATIONS... 9 pages CORE MARKET TRANSPORTATION SERVICE CONTRACT pages CORE MARKET TRANSPORTATION SERVICE REGULATIONS pages

5 4 Decision U96116 APPENDICES 1 RECONCILIATION OF RATES TO REVENUE REQUIREMENT...1 page 2 REVENUE AT EXISTING RATES COMPARED TO APPROVED RATES...1 page 3 FUNCTIONALIZED REVENUE REQUIREMENT (SCHEDULE 3.1R)...1 page 4 COMPUTATION OF PROPOSED RATES... 2 pages 5 REVENUE AT PROPOSED RATES ANALYZED BY MONTH...1 page 6 CALCULATION OF RATE RIDER ΑF...1 page

6 Decision U PARTIES PARTICIPATING IN THE PROCEEDING Principals and Representatives Centra Gas Alberta Inc. (Centra) Mr. F. V. Martin Witnesses Mr. L. M. Heikkinen, President Mr. A. A. Mantei, Director, Controller Mr. E. Tuele, Director of Operations Mr. R. Bellin, Foster and Associates Urban Municipalities (UM) Mr. C. R. McCreary Municipal Gas Co-ops Intervenors (MGCI) Mr. P. G. Sully, Q.C. Energy Users Association of Alberta and Alberta Irrigation Projects Association (EUAA/AIPA) Mr. J. H. Unryn Consumers= Association of Canada Alberta Branch (CAC-Alta) Mr. J. A. Wachowich High Level Forest Products (HLFP) Mr. K. H. Davidson Public Institutional Consumers of Alberta (PICA) Mr. C. R. Retnanandan 1 Board Staff Mr. E. J. Gallagher, C.A. Mr. K. N. Dannacker, P.Eng. 1 This Intervenor did not appear but did supply Argument.

7 6 Decision U96116 ABBREVIATIONS AECO-C AIPA Board CAC-Alta Centra CP CWNG DGA EUAA FERC GCRR HLFP MGCI MPP NUL P&G PUB SGS T-Customer UM Alberta Energy Company's monthly weighted average gas price paid for gas purchased from their "C" Gas Storage Hub Alberta Irrigation Projects Association Alberta Energy and Utilities Board Consumers= Association of Canada, Alberta Branch Centra Gas Alberta Inc. Coincident Peak Canadian Western Natural Gas Company Limited Deferred Gas Account Energy Users Association of Alberta Federal Energy Regulatory Commission Gas Cost Recovery Rate High Level Forest Products Municipal Gas Co-ops Intervenors Modified Partial Plant Northwestern Utilities Limited Production and Gathering Public Utilities Board Small General Service Transportation customer Urban Municipalities

8 Decision U REFERENCES ORDER / DECISION / REPORT NO. DATE PARTICULARS E86110 December 30, 1986 Transportation Rates for Contract Carriage of Natural Gas (Report/Inquiry) E89001 February 3, 1989 Northwestern Utilities Limited (Decision /1988 General Rate Application, Phase II) E92020 April 15, 1992 Centra Gas Alberta Inc. (Decision /1992 General Rate Application, Phase II) E92040 August 6, 1992 Bonnyville Gas Company Limited (Decision /1992 General Rate Application) E95076 June 30, 1995 Centra Gas Alberta Inc. (Order - Buy/Sell Rate) U96002 January 5, 1996 Centra Gas Alberta Inc. (Decision /1996 General Rate Application, Phase I) U96019 February 16, 1996 Centra Gas Alberta Inc. (Order - Vary Decision U96002) U96052 May 31, 1996 Canadian Western Natural Gas Company Limited and Northwestern Utilities Limited (Decision - Direct Purchase Service for the Core Market)

9 8 Decision U INTRODUCTION Centra Gas Alberta Inc. (Centra) filed a general rate application (the Application) dated March 9, 1995 with the Alberta Energy and Utilities Board (the Board) for approval to change existing rates, tolls and charges for natural gas utility services provided by Centra to its customers in Alberta for the test years 1995 and Phase I of the general rate application, for which a hearing was held at the Board's offices in Edmonton from July 24, 1995 to July 27, 1995, dealt with the determination of rate base, fair return on rate base, utility revenue requirements and other matters relating to the test years. Decision U96002, dated January 5, 1996, as amended by Decision U96019, dated February 16, 1996, set forth the positions of the parties and reasons for the Board's findings with respect to Phase I of the general rate application. On March 18, 1996, Centra filed with the Board its Phase II submission, which included a revised cost of service study and supporting evidence to support its application for proposed annualized rates, tolls and charges to recover the non-gas component of the 1996 utility revenue requirement, as approved by the Board in Decision U In accordance with the instructions of the Board, Centra provided notice of a pre-hearing conference, to be held May 1, 1996 at the Board=s Edmonton offices, for Phase II of the general rate application in newspapers having general circulation in the areas serviced by Centra. Centra also served notice upon all interested parties registered in Phase I of Centra's 1995/1996 general rate application. The Board, at the pre-hearing conference deemed notice of these proceedings to be adequate. Centra filed responses by May 29, 1996 to information requests submitted by the Intervenors and the Board. No written evidence was submitted by the intervenors. The Phase II hearing of the general rate application was held in Edmonton at the Board's offices on June 18 and 19, 1996, before Gordon J. Miller, N. W. MacDonald, P.Eng. and B. T. McManus, Q.C. Written argument was received by July 3, 1996 and reply argument by July 12, The Board will now set forth its findings, with reasons, with respect to Centra's proposed rates.

10 Decision U BACKGROUND Centra's service territory covers a wide geographical area encompassing the districts of Athabasca, Drumheller, Grande Cache, Hanna, High Level, Barrhead/Westlock/Morinville, Pincher Creek, Leduc/Calmar/Wetaskiwin, St. Paul, Southeastern, Stettler, Three Hills and Two Hills/Willingdon. This geographical dispersion requires an extensive network of gas transmission and distribution pipelines, including interconnection with pipelines of other companies, to provide natural gas service to customers in Centra's service area. The Board's findings with respect to Phase I of this general rate application were set forth in Decision U96002, as amended by Decision U In Decision U96019, the Board approved the following: Mid-Year Rate Base ($) 112,979, ,780,513 Fair Return on Rate Base (%) Fair Return on Rate Base ($) 7,019,954 6,833,580 Revenue Requirement ($) 43,999,850 49,255,712 Revenues at Existing Rates Including GCRR Revenues ($) 43,979,912 49,291,946 Revenue (Deficiency) Surplus ($) (19,938) 36,234 The allocation of the revenue requirement by customer class, which results in rates, tolls and charges, is the subject of Phase II of the general rate application process. Centra last filed a general rate application with the Public Utilities Board (the PUB) on July 2, 1991 for the test years 1991 and The most recent rate design was approved by the PUB in its Phase II Decision E92020 issued on April 15, 1992 for the test years 1991 and The rates for all classes were effective May 1, In this Decision, the Board will deal with the issues pertaining to the determination of just and reasonable rates, tolls and charges effective for all consumption on or after January 1, 1997, based on the Board's determination of utility revenue requirements in Phase I Decision U96019.

11 10 Decision U PARTICULARS OF THE APPLICATION In the application dated March 18, 1996, Centra requested Board approval of its: (a) (b) (c) (d) (e) proposed sales rates, as contained in the application, and replacement of all previously approved rates and rate schedules; standards, regulations and practices and special charges contained therein; transportation-end user and transportation producer rates; transportation service regulations; and industrial buy/sell rate. Centra also requested approval of a proposed rate rider, effective September 1, 1996, to collect the Board determined deficiency for 1995 and refund or collect differences between existing and proposed rates to August 31, Centra stated that none of its customers would be receiving an increase in rates in light of the fact that the 1996 revenue requirement approved by the Board in Decision U96019 is $45,936 less than the annualized revenues that would be generated at rates approved in E Centra, therefore viewed this as an ideal time to restructure its rates and bring all rate classes to an appropriate level of cost recovery. In designing the proposed rates, Centra proposed to reorganize and renumber the rate classes to reflect similar types of rate groupings. This included replacing the existing Rate 10 with a new transportation Rate 13 for transportation end-use customers, and the existing Rate 11 with a new transportation Rate 10 for transportation producer customers. In the application, Centra also requested Board approval of: (c) (d) (e) core market buy/sell and transportation rates; core market special charges; core market regulations and contracts; Centra proposed that these rates, regulations and charges would follow, where practicable, those proposed by Canadian Western Natural Gas Company Limited (CWNG) and Northwestern Utilities Limited (NUL). Centra proposed that, where items, issues or methods for determining costs were generic or common, it would accept the decision of the Board with respect to the CWNG/NUL proceeding. Centra proposed that, to reduce hearing time and costs, only those

12 Decision U items unique to Centra be addressed in these proceedings. In its rate design, Centra developed new rate classes 11 and 12 for customers eligible for core market transportation service. The proposed rates for these new rate classes are the same as the proposed sales rates for Rate 1 and Rate 2, exclusive of the Gas Cost Recovery Rates. Centra proposed new rate classes 21 and 22 for core market buy/sell service. On May 28, 1996, Centra filed revised schedules amending its cost of service study to correct various errors in the schedules filed with the Application. On June 11, 1996, Centra convened a Technical Workshop to review and discuss with the Intervenors, issues arising from the Application. Centra filed with the Board on June 14, 1996, revisions to the Natural Gas Service Rules and General Conditions of Service to reflect areas where agreement had been reached with the Intervenors at the Technical Workshop. On May 31, 1996, the Board issued Decision U96052 approving the rate schedules and terms and conditions of Core Market direct purchase services for CWNG and NUL. In its letter dated June 14, 1996, Centra revised the Application to reflect the impact of Decision U96052 on the Company=s Core Market proposals. The revisions included amendments to Rate Schedules filed with the original Application, and the addition of rate schedules for Irrigation Core Market customers and Transition Costs.

13 12 Decision U COST OF SERVICE STUDY (a) General A fully allocated cost of service study distributes the embedded or historical utility costs among the rate groups. This distribution of embedded costs is accomplished through a three step procedure. The three steps are cost functionalization, cost classification and cost allocation. The functionalization step separates the Board approved revenue requirement into broad functions such as production, gathering, transmission, distribution, gas supply and management, accounting, metering, etc. The primary purpose of functionalization is for each customer class to be allocated costs associated with the functions used by the customer class. For example, a transportation customer (T-Customer) using only transmission facilities should not be allocated any portion of the distribution costs. However, the T-Customer will be allocated costs associated with metering, accounting and other overheads. These functionalized costs are then classified, in the second step, into costs that vary primarily with either demand, energy or customers. The classified costs are then allocated to the different customer classes based on the consumption, demand, and size of each customer class. Finally, the costs allocated to each customer class are compared with the revenue to be generated by the proposed rates for that class by calculating the ratio of class revenue to class costs. The extent of deviation of the revenue to cost ratio from unity is then used as one of the rate design criteria to determine a just and reasonable rate for the customer class. Centra last filed a cost of service study with the Board as part of the 1991/1992 general rate application. The rates designed with the aid of this 1992 cost of service study were approved by the Board in Decision E92020 and became effective May 1, 1992 for all rate classes. In the sections that follow, the Board will deal with issues related to the cost of service study submitted in the current general rate application. (b) Modified Partial Plant Methodology Centra's cost of service employs the Modified Partial Plant (MPP) methodology for allocating transmission, distribution and gas supply capacity costs to customer classes. This methodology assigns capacity responsibility to customer classes based on the daily demands of each customer class for each of the 365 days in the year. In contrast, the Peak Responsibility or Coincident Peak (CP) method assigns capacity costs based on the demand of each customer class on the day of the system peak only. The MPP method results in capacity costs being assigned to users that are not on the system at the time of the system peak, and in a reduction of the capacity costs assigned to the on peak users as a whole. The MPP method also results in the allocation of capacity costs at a lower unit cost to interruptible customer classes which use the capacity left unused by the firm classes in the off-peak period. UM

14 Decision U The UM acknowledged that the changes to the allocation of transmission and distribution capacity costs proposed by the EUAA/AIPA had little impact on other customer classes, but expressed concern that the changes constituted a selective departure from the MPP method, which provides a balance between usage and demand on a reasoned rather than an arbitrary basis. The UM noted the testimony of Mr. Bellin at Tr. p.583 that the theory and application of the MPP method is based on the entire year, and few costs could be identified which were specific to winter or summer only. The UM submitted that the EUAA/AIPA suggestion for use of average summer volumes to determine secondary capacity costs for irrigation was an example of a selective revision for one rate class. The UM disagreed that irrigation service was effectively interruptible and referred to testimony of Centra=s witness that irrigation service is, in fact, off-peak firm with a very small primary allocation as it is firm only during the summer. The UM submitted that the MPP method recognized off-peak usage and the high ratio of secondary to primary capacity for irrigation compared to other classes was largely due to its low allocation of primary capacity. The UM also submitted that, while irrigation load may be zero during the portion of the year that the service is disconnected from the system, costs should be allocated to the class on an annualized basis as capital and operating costs are incurred year round. With respect to the EUAA/AIPA reference to a reduction in irrigation capacity allocation arising from a 3W/9NW methodology, the UM submitted that this method was developed for use by electric utilities and was not applicable to the gas industry. MGCI The MGCI noted that customers with contracts reserved capacity on systems in such a manner that, when the contract customer=s load factor dropped below 100%, this excess capacity was unavailable to other customers. However, Centra=s cost of service study used forecast actual volumes rather than contracted volumes, which resulted in non-contract customers being allocated more capacity costs than was appropriate. The MGCI submitted that the Board should order Centra to reply to MGCI-7 so that a correction could be made to the current study. Furthermore, Centra should be directed to provide both Partial Plant and MPP methods as calculated in the current study and using contract demand rather than forecast actual usage. EUAA/AIPA

15 14 Decision U96116 The EUAA/AIPA noted that irrigation service differed from other rate classes in that it only received off-peak service 7 months of the year. However, Centra=s MPP study treated irrigation service as if it were connected 100% of the year. The result of Centra=s allocation was that irrigation customers were allocated a disproportionate secondary transmission capacity responsibility. This was a direct result of the MPP assumption that any daily volumes in excess of the average daily volumes caused secondary responsibility. The EUAA/AIPA submitted that excess capacity for irrigation customers should be calculated relative to the 214 day average consumption of GJ/day, not the GJ/day consumption which resulted from a 365 day average. The EUAA/AIPA submitted that the excess irrigation capacity should be 31,561 GJ, not the 60,695 GJ calculated by Centra. The EUAA/AIPA calculated that the irrigation class transmission costs had been overstated by $9,733, based on its analysis. By the same reasoning, EUAA/AIPA concluded that the irrigation customers= distribution costs had been overstated by $15,520. The EUAA/AIPA noted that Centra acknowledged its position but was reluctant to make the modifications as it would require a seasonal winter/summer MPP study. In the opinion of the EUAA/AIPA, such a study was not necessary at this time as the irrigation volumes represented a small percentage of Centra=s system volumes. In any case, all other customer classes are connected for the full 12 months of the year and a summer/winter MPP analysis would not be meaningful for these classes. Centra=s witness had admitted that the MPP method required exercising judgement. The EUAA/AIPA submitted that its result was reasonable as irrigation service was a seasonal offpeak service requiring less capacity than dual season customers. Centra=s proposal suggested that irrigation customers had a capacity responsibility of GJ/day. The EUAA/AIPA had proposed a capacity responsibility of GJ/day, based on its calculations. The EUAA/AIPA noted that a 3W/9NW allocation would result in an allocation of GJ/day. By the CP method, the irrigation capacity would be 0.0 GJ/day. The EUAA/AIPA submitted this modification was simple and had little effect on the costs allocated to the larger classes of service. The EUAA/AIPA pointed out in reply that the MPP method allocated irrigation service capacity responsibility on an annual basis of GJ/day which is equivalent to a summer period capacity responsibility of GJ/day (567.9*365/214). This equivalent capacity is almost at the level of the forecast peak irrigation load of 1,000 GJ/day, meaning that irrigation service is essentially being allocated full non-coincident peak capacity for the full 7 summer months. The EUAA/AIPA submitted that this further demonstrates the inequity in Centra=s approach. CAC-Alta

16 Decision U The CAC-Alta noted that the EUAA/AIPA submission that irrigation customers be assigned a capacity responsibility of GJ/day instead of GJ/day was based on the underlying premise that irrigation is effectively an interruptible service. The CAC-Alta considered that this assumption was inappropriate. By definition, an interruptible service is subject to interruption when the system is under stress, with a rate designed specifically on the understanding that no capacity is planned to serve such a load. The CAC-Alta submitted that, although irrigation service is physically disconnected in winter, transmission and distribution facilities had to be in place to serve the loads. There was no evidence that irrigation service did not cause any additional capacity on the system. Also, since Centra has a winter peak and the irrigation load is entirely a summer load, the CAC-Alta submitted that it was almost certain that irrigation customers would not be interrupted. The CAC-Alta held the view that the customer costs for the class identified in the cost of service study are not costs for 7 months but annualized costs to be recovered over 7 months. Accordingly, the CAC-Alta submitted that Centra=s method of prorating the irrigation volumes and the calculation of secondary capacity responsibility were appropriate. HLFP HLFP expressed concern that the EUAA/AIPA submission that there was an over allocation of transmission and distribution costs to irrigation service was based on a selective analysis which may have failed to recognize that segments of the relative facilities may have been designed and built to service areas made up primarily or exclusively of irrigation customers. HLFP noted the MGCI=s suggestion that the Partial Plant and MPP methods be recalculated using contract demand rather than forecast usage and disagreed on the basis that this would result in an inconsistent allocation methodology and bias the allocation against customers holding contracts. HLFP submitted that, although small customers have no contract demand, they contribute to peak demand costs beyond the level indicated by their forecast daily volumes, particularly as a result of facility requirements arising from the -40C system design criteria. Centra Centra disagreed with the adjustments proposed by the EUAA/AIPA to secondary capacity for irrigation customers and submitted that the MPP methodology had been correctly applied to all classes based on annual volumes. Centra considered that the EUAA/AIPA=s adjustments were conceptually incorrect, as they failed to recognize or calculate the effect of summer/winter differentials on the allocation of costs to all classes. Centra considered that, even if the data were available to prepare such an analysis, the result would not materially change any of the proposed rates.

17 16 Decision U96116 Centra accepted the EUAA/AIPA=s suggestion that the Company consider a seasonal winter/summer MPP study. Centra submitted that, if it proved to be cost effective and useful, the Company was prepared to consider such an approach in its next general rate application. Board Findings The Board considers that there should be a reasonable balance between capacity cost causation and usage and therefore considers that some portion of transmission, distribution and gas supply capacity costs are appropriately allocated to rate classes based on consumption. The Board considers that the MPP methodology gives a balanced weight to the objectives of economic efficiency and fairness and that the balance between demand and usage is determined on a reasoned basis rather than an arbitrary basis. The Board is further persuaded of the MPP=s appropriateness because of its characteristic of assigning lower unit demand costs in the secondary allocation for use of the unused capacity by loads of an off-peak nature. Accordingly, the Board will accept the MPP method for determining class demands and allocating transmission and distribution capacity costs. The Board notes the submission of the MGCI that non-contract customers are allocated more capacity than is appropriate due to Centra=s use of actual rather than contracted volumes in the cost of service study. However, the Board notes that Centra=s evidence is that contract demand is a billing mechanism designed to provide a convenient basis for determining monthly demand charges. Unless the customer operates at contract demand every day of the year, resulting in a 100% annual load factor, daily volumes can be expected to fluctuate. Centra pointed out, in its response to MGCI-7, that the Partial Plant Method assumes that, from the standpoint of cost assignment, costs are attributable to a customer only as the customer uses the facilities, regardless of the method of billing for such costs. Centra also indicated that contract demands have been recognized in the forecast of peak day and annual volumes, and submitted it was not correct to assume an annual load factor of 100% for all contract demand customers in the cost allocation study. The Board considers that, for the peak day, contract demand rather than actual demand should be used in the cost of service study. The Board agrees that the MPP method recognizes that the load factor is probably less than 100% which the proposal of the MGCI does not take into account. Accordingly the Board disagrees with the MGCI that Centra should be directed to provide both a Partial Plant and MPP allocation based on contract demand for every day of the year. The Board also agrees with HLFP that the MGCI=s proposal would result in an inconsistent allocation methodology and bias the allocation against customers holding contracts. The Board disagrees with the EUAA/AIPA proposal for a modification to the MPP methodology for reasons which have also been outlined by other intervenors. The changes proposed by the EUAA/AIPA represent a selective departure from the MPP methodology and would therefore counteract its effect of providing a balance between demand and usage on a reasoned rather than an arbitrary basis. The Board also agrees with the UM and the CAC-Alta that irrigation service

18 Decision U is, in fact, off-peak firm rather than interruptible. Although irrigation load is zero during disconnection in winter, facility capital and operating costs are incurred year round. The Board agrees with the UM that the MPP methodology recognizes the off-peak irrigation usage and that the high ratio of secondary to primary capacity compared to other classes was due to the small primary capacity allocation. The Board also agrees with the CAC-Alta that costs for the Irrigation class are not costs for 7 months but annualized costs to be recovered over 7 months. The Board acknowledges Centra=s submission that the MPP methodology has been correctly applied to all classes based on annual volumes and agrees that the EUAA/AIPA proposals for adjustments to secondary capacity for irrigation customers failed to recognize or calculate the effect of summer/winter differentials on the allocation of costs to all classes. The Board considers there is merit in the suggestion of the EUAA/AIPA that the Company consider a seasonal winter/summer MPP study. Accordingly, the Board directs Centra to determine at the time of the next general rate application whether preparation of a winter/summer MPP study would be cost effective and useful. (c) Classification of Gas Supply Costs Centra proposed to functionalize all administration and general expenses to customer categories for recovery in the fixed component of rates. This represented a change from the previous cost of service study where the gas supply overhead component of administration and general expense was identified and functionalized to commodity categories for recovery in the variable component of rates. UM The UM noted that Centra=s witness cited a Federal Energy Regulatory Commission (FERC) precedent, which suggested a fixed allocation of gas supply costs was preferable to variable, as precedent for Centra=s proposed allocation. The UM submitted that the FERC precedent related to interstate pipelines and not to gas distribution utilities. Centra=s proposal ignored the fact that gas supply costs are part of administration and general costs, which are allocated on the same basis as transmission, distribution and sales and accounting expenses. The effect of Centra=s proposal was to raise the customer costs of Rate 1 by $215,650. The UM submitted that Centra had not substantiated this change to the cost of service study. MGCI The MGCI submitted that gas supply costs may not be fixed but will vary with the complexity of the supply portfolio for transmission and direct purchase. Since there may be direct costs associated with gas supply, the MGCI submitted that the existing allocation for gas supply costs

19 18 Decision U96116 be maintained. As an alternative, the MGCI proposed that the gas supply costs be allocated based on a third each to capacity, commodity and customer costs. EUAA/AIPA The EUAA/AIPA disagreed with Centra=s proposal to classify $303,230 of gas supply overhead costs as customer costs. In the opinion of the EUAA/AIPA, these should remain functionalized to gas supply and classified accordingly. The EUAA/AIPA agreed that the FERC precedent cited by Centra was relevant to regulation of interstate pipelines but not to gas distribution utilities. The EUAA/AIPA noted that the merchant function of interstate pipelines had been separated from the transmission function, eliminating gas supply overheads. However, the merchant function was still undertaken by LDC=s. CAC-Alta The CAC-Alta considered that Centra had only identified $100,000 of its gas supply overhead as fixed. The CAC-Alta submitted that the Board should classify only $100,000 of gas supply overheads as customer costs and the remainder as commodity. HLFP HLFP agreed that Centra=s proposed method of allocating gas supply overheads of $300,000 reflected an incorrect functionalization, and submitted that these costs should continue to be classified to commodity as part of the gas supply function. Centra Centra referred to its witness= testimony at Tr. p.533, which indicated that gas costs were removed completely from Centra=s rate design in recognition that market conditions have changed and the Company is transporting much more gas than previously. Accordingly, Centra submitted it was more appropriate to reflect gas supply overheads as fixed, which is how they are incurred as they do not change based on the volume of gas. Centra noted the example of the FERC where a change in overhead cost classification from variable to fixed was also considered necessary to reflect the change in market conditions. Centra submitted that intervenors had failed to present evidence to indicate that any alternative approach would better meet existing market conditions. In particular, Centra noted that the UM and the EUAA/AIPA asserted that the change was not substantiated and proposed a return to the previous method, which evidence indicated was no longer appropriate. Also, the MGCI had not provided evidence to explain why its proposed allocation would be more appropriate and the CAC-Alta had failed to explain why costs not customer-related should be classified to commodity. Centra submitted that the evidence it provided supported the proposed change and noted that the proposal did not change the allocation of costs among rate classes but, rather, the way costs are classified within rate classes.

20 Decision U Board Findings The Board accepts Centra=s proposal to reclassify gas supply overheads from commodity to customer categories. The Board considers that Centra=s primary reason for the change in classification, i.e. that there are fundamental changes in gas market conditions, is a compelling one. In this respect, the Board notes that intervenors have failed to address Centra=s reasons in favouring the 1992 allocation of these costs. The Board notes that the precedent cited by Centra=s witness does indeed refer to transmission pipelines rather than to LDC=s. However, the change in the retail gas market is similar to that in the gas pipeline industry. LDC=s are opening the gas merchant function to competition and evolving into primarily gas transportation systems, similar to pipelines. The Board acknowledges that Centra, during the test period, has a significant gas supply portfolio. Given Centra=s stated objective of not submitting a general rate application for a number of years and that the significance of the gas portfolio will likely decline in the future, the Board must set rates on a forward-going basis and approve a cost allocation which will better reflect Centra=s requirements during this period. (d) Classification of Services and Meter Related Costs In its 1992 cost of service study, Centra classified meters and services costs to capacity and customers based on minimum plant analyses. Those costs were then allocated to rate classes based on number of customers and peak demand. Centra revised the 1992 study by classifying and allocating meter costs among classes based on a replacement cost new and minimum plant analysis. UM The UM stated that there was an apparent error in the analysis of replacement meter costs for one producer customer, as shown in the revision to information response UM-12. Since replacement meter costs were used as a proxy to classify and allocate meter costs, the UM calculated that correcting this error would increase costs to Rate 13 by $22,000 while reducing the cost to Rate 1 by $16,000 and by $6,000 to other rates. The UM considered that there was another error in Centra=s cost of service study in the allocation of the capacity cost of services at column 12 of page 7 of response EUAA/AIPA-3. The UM calculated that correcting this error would reduce the cost allocated to Rate 1 by $134,000. Since Centra had used a meter study, which UM considered to be incorrect, the cost of services allocated to Rate 1 should be reduced by a further $28,000. This would reduce the cost of services to Rate 1 by a total of $162,000.

21 20 Decision U96116 Notwithstanding these errors, the UM considered that Centra had not substantiated its allocation of gas supply overheads and meters and services to customer costs. Although Centra determined that the average customer costs for a Rate 1 customer to be $24.20/month, Centra had ignored the relationship between meter costs and the size of the customer. Centra=s meter replacement cost study showed that a replacement meter for a residential customer using 150 GJ/year was $187, whereas it was $2,841 for a Rate 1 customer using 5000 GJ/year. The UM submitted that this showed that Rate 1 customer costs were much less than the $21.47/month of the 1992 study. EUAA/AIPA The EUAA/AIPA noted that Centra was proposing that approximately $2 million of meter and service related costs, which were classified as capacity and commodity costs in the 1992 study, be classified as customer costs. The effect of this would be to raise the allocated customer costs for irrigation customers from $22.48/bill to $45.91/bill, or 104%. The EUAA/AIPA submitted that this represented a departure from Centra=s past practice of recovering a portion of customer rates in the commodity charge. Centra=s proposal was also inconsistent with the risk basis of cost recovery which was inherent in the rate of return set in the Phase I portion of these proceedings. The EUAA/AIPA noted that meter reading costs were allocated based on the number of meters read, and submitted that this could result in an over-allocation of costs to irrigation service. As an illustration, the EUAA/AIPA referred to the information provided in Undertaking 4 on the relative size of irrigation meters, which indicated that these meters are capable of storing many months of usage information before being reset to zero. The EUAA/AIPA considered, therefore, that meter costs might be over-allocated to irrigation service, as these meters may be read more often than necessary. Accordingly, the EUAA/AIPA submitted that the overall level of metering costs could be reduced by less frequent reading of irrigation meters and further savings realized by combining the reading of irrigation and farm meters. CAC-Alta The CAC-Alta noted that interrogatory UM-12 showed that the cost of meters varied with the customer=s load or demand. Centra had not provided sufficient support for its proposed classification of services and meters. Furthermore, the Board had, in the past, recognized that services and meters had both a demand and a customer cost element. The CAC-Alta submitted that the classification of services and meters be the same as in the 1992 cost of service study. Centra Centra submitted that the information provided in response to EUAA/AIPA-3, was, in fact, correct. The column of numbers noted by the UM were provided for information and were not used in the actual calculation.

22 Decision U Board Findings The Board is satisfied that Centra has not made an error in calculation, based on its explanation that the column of numbers used by the UM was intended for information only. This does raise the point whether Centra=s intent in providing the information was sufficiently clear. The Board considers that Centra, in the future, when supplying data for information purposes in its cost of service study, should label the information in that manner. With respect to the EUAA/AIPA=s position on meter reading costs, the Board considers that the costs of the irrigation rate class should reflect the less frequent numbers of readings and the possibility of combining the irrigation meter reading with that of the farm site reading. However, the evidence in these proceedings is unclear as to whether Centra already arranges for combined readings in this manner or not. The Board notes that the customer portion of the irrigation rate has a revenue/cost ratio of 54% according to the proposed rates and cost of service study. Therefore, it is unlikely that correcting for the fewer number of readings for a seasonal customer would materially change this ratio and the irrigation customer charge. However, as Centra moves the components of a rate closer to a unity revenue/cost ratio, it is important that a cost allocation more closely represent cost causation. Therefore, Centra is directed, in future cost of service studies, to correct its allocation of meter reading costs for combined farm/irrigation readings and the fewer readings of seasonal customers. With respect to the position of the EUAA/AIPA and CAC-Alta, that meter and service costs be partially recovered through the demand and commodity costs, the Board considers that Centra=s proposed classification represents better cost causality. The Board agrees with CAC-Alta that the meters of customers with higher demand are more costly. However, these higher costs are covered adequately by higher customer charges in the affected rates. (e) Producer Transportation Capacity Responsibility For the purpose of allocating transmission capacity to producer transportation, Centra proposed to treat this service in the cost of service study as a backhaul with no primary capacity responsibility for transmission. EUAA/AIPA The EUAA/AIPA noted Centra=s proposed treatment of producer transportation and submitted that the hearing evidence showed that producer transportation volumes were higher than the forward haul sales volumes in the same service area. The EUAA proposed that producer transportation be treated as forward haul and sales volumes treated as backhaul to reflect actual system flows. Alternatively, producer transportation could be assigned 50% of their capacity responsibility to reflect that backhaul rates are traditionally priced at approximately 50% of forward haul rates.

23 22 Decision U96116 Centra Centra noted the suggestions of the EUAA/AIPA about assigning capacity responsibility for transmission capacity, and submitted that the rate for the producer transportation class is set primarily on a value for service basis. Centra indicated that the cost of service study, as prepared, assigns a reasonable amount of cost to this class. Board Findings The Board agrees that the producer rate is a competitive rate and must be set at the value of service in order to prevent bypass of Centra=s transmission system. However, the Board considers that the cost of service study is not irrelevant to the producer rate as the producers must make a reasonable contribution beyond marginal cost. Otherwise, Centra=s customers would be better off if the producers chose other transporters. Therefore, the position of the EUAA/AIPA is a reasonable one, in the absence of clear evidence with respect to the use of Centra=s system by producers. Since the evidence in these proceedings is unclear as to the amount of forward versus back hauling that occurs on Centra=s transmission system, the Board will accept Centra=s present allocation of costs. However, the Board directs Centra to further study the usage of the transmission network by producers and demonstrate the extent to which producer transportation revenues contribute to the incremental costs arising. (f) Other Costs Centra proposed that these costs be allocated on the basis of the number of customers. UM The UM noted that Other Costs had increased from $330,000 in 1992 to $903,000 in The UM=s analysis showed that these costs included working capital, distribution supervision, service on customer premises, general communication and training, administration and general, insurance and employee costs. Although the major function was customer premises services, such as trouble calls line locations and building inspection, the UM submitted that the other expenses in the category showed that other costs were not customer related. The UM proposed that Other Costs be treated in the cost of service study in the same manner as other general and administration costs. Centra Centra disagreed that Other Costs should have been treated in the same manner as other general and administration costs. Centra submitted that the evidence indicated that many of the expenditure categories included under the heading of Other Costs were customer related. For example, Centra noted the significant increase in this account from 1992 resulted from increased inspections and safety related calls, which are customer related costs unrelated to demand on the system.

24 Decision U Board Findings The Board agrees with the UM that the classification of other costs in the cost of service study includes some costs which are not directly customer related, but considers that these do not represent a significant proportion of the total allocated as customer costs. The Board notes that the basis of allocation is consistent with the allocation used in the previous cost of service study. The Board also notes that the increases in the total allocated resulted from increased inspections and service calls which, as Centra pointed out, are customer related. Accordingly, the Board accepts Centra=s classification and allocation of other costs. (g) Production and Gathering (P&G) Costs Centra proposed classifying P&G Costs 100% to commodity in its current cost of service study. CAC-Alta The CAC-Alta considered Centra=s proposed allocation was not reasonable because P&G assets could have been added in lieu of additional transmission facilities. Furthermore, the evidence showed that the assets in question were used to provide balancing services and were available to meet peak demand. In the absence of precise data, the CAC-Alta proposed that P&G assets be classified 10% to demand and 90% to commodity. Furthermore, the CAC-Alta submitted that the Board should direct Centra to undertake a proper study to determine the extent to which these assets are used to meet demand. Centra Centra submitted that there was no evidence to support replacing the classification per the cost of service study with an arbitrary allocation, as proposed by the CAC-Alta. Centra calculated that the effect of such a modification would be a reduction of about $1,000 in total costs allocated to Rate 1. Board Findings The Board accepts Centra=s proposed allocation of P&G costs for the purposes of this Decision. The Board acknowledges that P&G facilities can be used at times for peaking purposes to substitute for additional transportation facilities. However, there is insufficient evidence in these proceedings that Centra uses P&G facilities for peaking or if they are used for base load. Accordingly, the Board directs Centra, at the time of its next general rate application, to provide evidence concerning the actual usage of its P&G assets and to incorporate the appropriate cost allocation in the next cost of service study.

25 24 Decision U96116 (h) Customer Accounting Costs Centra allocated customer accounting costs, including meter reading costs, to rate classes based on the number of customer bills or number of meter readings. UM The UM submitted that Centra=s allocation was not reasonable as the evidence showed that the cost of reading residential meters was $3-6 per read in urban areas and $12 per read in rural areas. For commercial Rate 1 customers, the cost was $24 per read. In 1992, relative meter reading costs ranging from $1.30 for Rate 1 to $88 for Rate 10 customers were used as the basis of allocation. The UM submitted that Centra should carry out its 1996 cost of service study on the same basis as its 1992 study, which would reduce Rate 1 costs by $12,000. The UM noted that credit and collection costs were also allocated on the basis of the number of bills, even though Centra=s witness had agreed that credit commissions varied by the size of the bill. This was further evidence that accounting costs should not be uniformly allocated on the basis of the number of bills. The UM noted that NUL allocated customer accounting costs 90% to customer costs and 10% to capacity. CWNG allocated customer accounting 86% to customer costs, 3% to commodity and 11% to demand. Both these utilities recognized the greater complexities in dealing with larger customers. Use of either NUL=s or CWNG=s allocation of customer accounting costs would reduce Rate 1 costs by $22,000. Centra Centra considered that these reductions were not significant in the context of total costs for the rate class, and submitted that the evidence presented supported its method of allocating customer accounting costs. Centra further submitted that minor adjustments of this nature were best resolved in cooperative discussions before the hearing process. Board Findings The Board is not convinced that the CWNG or NUL meter reading cost allocation results are comparable to Centra=s due to the differences among the utilities with respect to how meters are read (NUL has an Automatic Meter Reading program while Centra does not) and the relative proportion of industrial versus residential meters. However, the Board accepts that some meters are more costly to read than others and that allocating costs based on bills or number of meter readings may be less than accurate. The Board considers that the changes proposed by the UM for meter reading costs are insufficiently large to make a great deal of difference to the rate design at this time. The Board directs Centra to study the relative costs of reading different meter types and to allocate meter reading costs to the rate classes directly in this manner. (i) Functionalized Computer Costs CAC-Alta

26 Decision U The CAC-Alta noted that Centra was, in its 1996 cost of service study, assigning various computer costs, hardware, software and shared costs, to various functions based on estimates used in its 1992 cost of service study. The CAC-Alta considered it inappropriate to continue to assign $2,100,000 in costs based on judgement. The CAC-Alta noted that this resulted in Rate 1 customers bearing $63,601 of return and Income Tax costs, based on Centra=s guesses. The CAC-Alta submitted that the Board should direct Centra to determine what computer costs should be directly assigned to the Sales and Accounting function. For these proceedings, the CAC-Alta submitted that computer costs be prorated in the cost of service study on the basis of the subtotal of production, gathering, transmission and distribution plant. Centra Centra disagreed with CAC-Alta=s proposal as its witnesses had shown that the amount assigned in the 1992 study had not changed in the current study. Centra calculated that the modification proposed by the CAC-Alta would reduce costs allocated to Rate 1 by less than $5,000, which, in Centra=s view, would not be material even if the proposal were correct. Board Findings The Board notes the comments of Centra=s witness that the allocation of computer costs was studied in the current cost of service study and that no need was found to change the method of allocation. Furthermore, it appears that Centra has evaluated the modified allocation proposed by CAC-Alta and found the change to Rate 1 cost of service to be minimal. Accordingly, the Board will not direct any change be made to Centra=s allocation of computer costs, for the purposes of this Decision. However, the Board considers that a cost of service study should reflect cost causality of the rate classes and direct assignment of costs should be made wherever those costs are attributable to a function. Accordingly, the Board directs Centra, at its next general rate application, to determine if it is possible to directly assign computer costs to the Accounting and Sales function, and if so, the appropriate percentage to assign. (j) Penalty Revenues Penalty revenues are a credit item in the cost of service study. Centra proposed allocating penalty revenues on the basis of sales revenue at existing rates. MGCI The MGCI noted that Centra=s proposed allocation reduced the penalty revenues attributed to Rate 1 from 98% in the 1992 study to 88% in the current study. The MGCI submitted that there was no justification for this change and the allocation from the 1992 study should be used.