sr\ COL.u ~\ ~ ~<$> ~ ~·: ~ c, ~~tt ? / ~ •• '-/~ ............... /~s·~~~~' IN THE MATTER OF An Application by Methanex Corporation for Reconsideration of the PACIFIC NORTHERN GAS LTD. PACIFIC NORTHERN GAS (N.E.) LTD. 1995 Rate Design Decision RECONSIDERATION DECISION: Phase II July 11, 1996 BEFORE: Lorna R. Barr, Chair of the Division Ken L. Hall, P .Eng., Commissioner ~: ~ .. T j~ -~ y " " " " "'; "" "" . " . " , " . '} .,; .. , . 0 < : 'C liQ ~ i : •• --. r~ ; ~J
TABLE OF CONTENTS Page No. 1. 0 INTRODUCTION 1 1.1 Background 1 2.0 FORECAST OF INTERRUPTIBLE DELIVERIES TO METHANEX 2 3.0 IMPUTED VALUE OF SERVICE FOR VALLEY GAS 6 4. 0 OTHER MATTERS 1 0 4.1 Timing of Next Rate Design Application 10 4.2 Access to Interruptible Transportation Capacity and Sales Gas 11 4.3 Clarification of Imputed Value of Interruptible Delivery Service 11 4.4 Purchase of Valley Gas for Resale 12 5.0 RESULTS OF THE RECONSIDERATION 12 COMMISSION ORDER NO. G-74-96 APPENDIX A- Appearances APPENDIX B - List of Exhibits APPENDIX C - List of Exhibits from Exhibit Book
............... ~ ............... -. ............... . .. .... ... I Legend ---------- \ .. ---- ... \ 0 Com • pressor -·-FoRr ·-----------s NELSON ta tIon l 1 Fort Nelson 1 .A Gas Plant Plant • . . I ALBERTA I BRITISH . . Plant ., ., FORT,ST. JOHN PNG-WEST ! .i& Boundry Lake Plant ·-· PNG-NE WiCa@7 ::?iS U M MIT PRINCE GEORGE e' LAKE \ \,. \ ' Westcoast Energy L I Mainline '\..... CALGARY \ • ' \ eKAMLOOPS ". \ . \ ~ . ---- - - \ --..... .. .. .. - ---' . Pacific Northern Gas Ltd. System and Service Area Locations BCM23P
1. 0 INTRODUCTION Pacific Northern Gas Ltd. ("PNG", "the Company", "the Utility") is a British Columbia natural gas utility which is controlled by Westcoast Energy Inc. ("Westcoast"). The PNG system, operating in three divisions, serves approximately 30,000 customers in northern British Columbia. The PNG-West Division serves about 23,000 customers in communities west of Prince George extending as far as the Pacific Coast deep water ports of Kitimat and Prince Rupert. This division is primarily an industrial gas transmission system serving large industrial customers of which Methanex Corporation ("Methanex") is the dominant customer. PNG's wholly owned subsidiary, Pacific Northern Gas (N.E.) Ltd. ("PNG(N.E.)"), operates the other two smaller divisions, namely, the Dawson Creek Division and the Tumbler Ridge Division. 1 . 1 Background PNG and PNG(N.E) submitted a Rate Design Application (the "Rate Design Application") dated July 6, 1995, to the B.C. Utilities Commission ("the Commission"). Subsequently, the Commission held a public hearing into the Application from October 23 through October 25, 1995, followed by written argument. On December 15, 1995, the Commission issued its Decision (the "Rate Design Decision") and Order No. G-1 06-95 on the Application. On February 1, 1996, Methanex applied (the "Reconsideration Application") to the Commission under Section 114 of the Utilities Commission Act, for reconsideration of two aspects of the Rate Design Decision with respect to the PNG West Division, namely: • The forecast volume of interruptible gas sales to Methanex used by the Commission. • The decision of the Commission to combine firm and interruptible sales revenues in the revenue to cost ratio calculations. On February 8, 1996, the Commission issued Order No. G-14-96 asking for written submissions on the Reconsideration Application from registered intervenors and other affected parties. In the written submissions regarding the Reconsideration Application, Methanex and Inland Pacific Energy Services Limited on behalf of its clients, Eurocan Pulp and Paper Company and Skeena Cellulose Inc. (the "Mills"), raised further issues for reconsideration. On March 15, 1996, the Commission issued its Reconsideration Decision: Phase I, and Order No. G-26-96. The Commission allowed the first part of the Methanex Reconsideration Application
2 concerning the forecasting of the interruptible volumes to proceed to a Reconsideration Hearing scheduled for May 31, 1996. The second part of the Application for reconsideration, involving the combined revenue to cost ratios, was denied. The supplementary issues for reconsideration were required to proceed through the reconsideration process and a timetable for addressing those issues was established. Methanex confirmed that it wished its supplementary application to proceed. Methanex requested reconsideration of the figure of $0.42 per gigajoule ("$0.42/GJ") as the imputed value of service for valley gas which it buys from PNG as interruptible sales gas. On April 23, 1996 the Commission issued its decision as a Supplement to the Reconsideration Decision: Phase I, and Order No. G-37-96. The Commission allowed the supplementary application from Methanex concerning the use of $0.42/GJ as the imputed value of service for valley gas to proceed to the May 31, 1996 Reconsideration Hearing. The evidentiary part of the Reconsideration Hearing was completed on May 31, 1996. Methanex filed its Argument on June 17, 1996 and PNG filed its Argument on June 21, 1996. Reply Argument from Methanex was filed on July 2, 1996. In summary, two issues proceeded to the Reconsideration Hearing, namely: • the forecast quantity of interruptible deliveries to Methanex. • the imputed value of service for valley gas sold to interruptible customers, including the methodology for determining the imputed value. 2. 0 FORECAST OF INTERRUPTIBLE DELIVERIES TO METHANEX This matter revisits the forecast of 3,298,806 GJ/y (3.30 PJ/y) for interruptible deliveries to Methanex which PNG used in the Rate Design Application. The Commission used this figure in the Rate Design Decision. Rate Design Decision The 1995 Rate Design Application was based on PNG's 1995 Revenue Requirements which were established through an Alternative Dispute Resolution process and approved by Order No. G-32-95. The Revenue Requirements information regarding deliveries and costs were not reviewed in the rate design proceeding, but were accepted as a starting point for the cost of service study. Evidence presented in the October, 1995 hearing indicated that actual interruptible deliveries to Methanex in 1995 would be
3 considerably less than forecast. No questions were raised about the 3.30 PJ/y forecast of interruptible deliveries projected from 1996 onward (T: 60-62). The rate design set out in the Rate Design Decision was intended to be representative of conditions for at least 3 years. Methanex Application In its Reconsideration Application, Methanex requested reconsideration of: "The use of volumes of interruptible gas sales to Methanex in the rate design determination which are demonstrably not an accurate representation of actual or anticipated volumes for 1995 or 1996." In support of its Application, Methanex referred to evidence at the October, 1995 hearing that it would take less than 1.30 PJ of interruptible gas in 1995, and that it believed the final calculation following reclassification would indicate it did not purchase any interruptible gas in 1995. Furthermore, Methanex stated that, on reviewing its requirements, it expected to take at most 0.5 PJ of interruptible gas in 1996. Methanex submitted that using 3.3 PJ/y of interruptible gas in the cost of service study distorted the revenue to cost ratio for Methanex, and led the Commission to conclude that the ratio for Methanex was much lower than would otherwise have been the case. Evidence The amount of interruptible gas delivered to Methanex appears to be a simple concept but, as the evidence shows, there are several measures of interruptible deliveries for a particular year. Each measure is appropriate for the purpose for which it is intended, but the magnitude of each can differ from the others. Total Interruptible Deliveries is the sum over a year of daily interruptible deliveries, which PNG defined as follows: "Deliveries of gas on a daily basis above the DCQ (i.e. the contract demand) are deliveries of interruptible gas" (Exhibit 1, Tab 13, page 3). The total refers to gas that was transported by PNG for Methanex on an interruptible basis. Under the terms of Methanex's service contracts, some interruptible deliveries may be reclassified to firm for billing purposes, or are considered recovery of deficiency volumes, and so do not attract the interruptible transportation rate. The difference between Total Interruptible Deliveries and the reclassified/deficiency quantity is the Deliveries at Interruptible Rate.
4 Some of the gas which Methanex receives via interruptible transportation service is gas which Methanex purchases directly from suppliers other than PNG. The rest is gas which PNG sells to Methanex as interruptible sales gas and is known as Net Interruptible Sales ("Net" means that the amount excludes any line pack transfer gas which Methanex had previously delivered to the PNG system, and so this figure is the total amount of interruptible gas that PNG sold to Methanex). Most of PNG's sales to Methanex are Valley Gas Sales, which is interruptible gas that is supplied from purchases under PNG's firm system supply contracts ("valley gas"). The remainder is supplied by spot gas which PNG buys for resale to interruptible customers. The following actual 1993, 1994 and 1995 information about deliveries was filed by PNG (Exhibit 1, Tab 13, Question 1) . The 1996 numbers are a combination of actual deliveries through April, 1996 and forecast for the rest of the year, as provided by Methanex (Exhibit 1, Tab 17, Question 1). PNG generally was in agreement with the 1996 numbers (T: 166): Table 1 Methanex Interruptible Deliveries and Sales 1993 Total Interruptible Deliveries, PJ 5.90 Deliveries at Interruptible Rate, PJ 5.67 Net Interruptible Sales, PJ 4.29 Valley Gas Sales, PJ 3.55 Valley Gas/Net Interruptible Sales 83% Valley Gas!fotal Interruptible Deliv. 60% PNG noted that the 1995 calendar year was the first full year of operating the Methanex ammonia plant expansion completed in the fall of 1994. This plant completion resulted in a transfer of 4,000 Mcf/d (4 408 GJ/d) of interruptible gas to the firm contract demand. In Argument, PNG agreed that the forecast of interruptible deliveries to Methanex for rate design purposes should be reduced from the 3.3 PJ/y figure used in the Rate Design Decision. In response to a Commission staff Information Request, PNG forecast Total Interruptible Deliveries to Methanex of 2.7 PJ/y for 1997 and 1998 (Exhibit 1, Tab 13, p. 29). Interruptible Deliveries probably would be greater than this forecast when calculated on an actual delivered basis (T: 175). 1994 1995 1996 4.58 2.32 2.62 3.64 0.00 0.33 3.57 1.75 2.39 3.31 1.58 N/A 93% 90% -72% 68% --PNG suggested that Total
5 For 1997 and 1998 Methanex forecasts that it will consume 3.3 PJ/y of interruptible gas and anticipates that it will take 70 to 80 percent of its interruptible gas from PNG (Exhibit 1, Tab 5, Question 4). In Argument, Methanex stated that the imputed value of valley gas should apply to only 70 percent of Total Interruptible Deliveries. Methanex also recommended that the Commission should adopt the PNG forecasts of Total Interruptible Deliveries of 1.9 PJ/y for 1996, and 2.7 PJ/y thereafter. In Reply Argument Methanex noted that periodically-scheduled turnarounds and other plant interruptions introduced a variability in volumes which rendered accurate forecasting difficult. Methanex urged the Commission to take this into account in determining the levels of interruptible deliveries and the methodology to be utilized. In Argument PNG recommended that the Commission should average the forecasts of PNG and Methanex for 1997 and 1998, and use the average of 3.0 PJ/y as forecast normal Total Interruptible Deliveries for 1996 through 1998. PNG also recommended that 80 percent be used as the portion of these deliveries to be considered as valley gas. PNG arrived at this value by excluding line pack transfers from the Total Interruptible Deliveries. Commission Determination The Deliveries at Interruptible Rate are billed at the interruptible transportation rate and are quite visible to the customer. Methanex appears to have been referring to this amount as "takes of interruptible gas" in its Reconsideration Application. However, as the evidence in the proceeding unfolded, it became apparent that the amount billed was not the appropriate measure of interruptible deliveries. The Commission accepts the PNG definition that interruptible deliveries are deliveries of gas on a daily basis which exceed the contract demand. Therefore, this Decision will focus on Total Interruptible Deliveries. The figures for 1993 and, to a lesser extent, 1994 may overstate present circumstances, since, as noted earlier, Methanex's contract demand increased during 1994. Actual interruptible deliveries in 1995 were lower than the 3.30 PJ/y forecast used in the Rate Design Decision, and deliveries in 1996 are likely to be lower also. However, Methanex acknowledged that the reductions in both 1995 and 1996 are largely the result of occurrences that are not of an ongoing nature (T. 42). The Commission has considered a specific adjustment to the forecast for 1996 to recognize that interruptible deliveries to Methanex are expected to be about 2.6 PJ/y, but has decided against doing so. The Commission is prepared to revise the forecast of interruptible deliveries used in the Rate Design
6 Decision, but, in the interest of rate certainty, is reluctant to make a further change for 1996 simply because actual deliveries in 1996 may be somewhat less than the revised forecast. The additional information which is available as a result of the Reconsideration raises a concern with regard to the amount of interruptible deliveries to which the imputed value of service for valley gas applies. The Rate Design Decision applied a factor of 89 percent to the valley gas price differential, as the portion of interruptible PNG sales (i.e. of Net Interruptible Sales) which is valley gas, and Table 1 confirms this figure. However, the number does not reflect the considerable amount of gas that Methanex buys direct from other suppliers which is delivered by PNG using interruptible service. Table 1 indicates that valley gas typically makes up about 70 percent of Total Interruptible Deliveries to Methanex. For convenience, this factor will be used to recalculate the imputed value of service for valley gas for Methanex in Chapter 3. The evidence in the hearing indicates that other interruptible customers rely more heavily on purchases from PNG than Methanex (T: 13, 185). The Commission will continue to use 89 percent for the other customers. The Commission concludes that, on the basis of the evidence, it is reasonable to accede to the request of PNG and Methanex to reduce the forecast of Total Interruptible Deliveries to Methanex. The Commission determines that an amount of 3.00 PJ/y be used for rate design purposes for the duration of the Rate Design Decision. The Commission also determines that 70 percent of this amount is deemed to be valley gas. 3.0 IMPUTED VALUE OF SERVICE FOR VALLEY GAS This issue revisits the imputed value of service for valley gas sold to interruptible customers, which the Rate Design Decision determined as $0.42/GJ. Consistent with Methanex's Application, both the magnitude of the imputed value and the methodology used to determine it are reviewed. Rate Design Decision In the Rate Design Decision, the Commission states: "In 1991, the large industrials were concerned that interruptible rates based on market value would be very sensitive to short term market fluctuations. It is difficult to imagine any single number which, if used as the interruptible rate for a period of time, will fully reflect the market value on each day during the period. Efforts to determine a value of interruptible service that will have some durability face the same difficulty."
7 Nevertheless, the Commission adopted the value of interruptible service approach and, after considering a market-based pricing approach which Methanex raised in the October, 1995 hearing, directed that an imputed value of service for valley gas sold to interruptible customers be included in the cost of service study. The imputed value of service for valley gas was based on a price differential of $0.42/GJ. This figure was calculated as the simple arithmetic (rather than weighted) average of the differentials at Station 2 between spot gas prices and PNG's average commodity cost of valley gas over 1993 through 1996, as follows: Table 2 Station 2 Price Differentials 1993-1996 Price Differential Year at Station 2 1993 Adjusted Actual $0.62/GJ 1994 Actual $0.44/GJ 1995 Estimate $0.20/GJ 1996 Forecast $0.42/GJ Average $0.42/GJ The average price differential was multiplied by 89 percent as the portion of interruptible PNG sales that is supplied from valley gas. The result of $0.37/GJ was increased by $0.05/GJ for the Westcoast transportation charge from Station 2 to Summit Lake, to arrive at an imputed value of service of $0.42/GJ. Methanex Application In its March 11, 1996 Supplementary Reconsideration Application, Methanex requested reconsideration of " ... the imputed value received by Methanex with respect to interruptible gas sale purchases." (Exhibit 1, Tab 10). This request was largely based on the average unit net revenue figure of $0.176/GJ for off-system sales which PNG referenced in the 1996 Off-System Sales Incentive Program proposal filed with the Commission (Exhibit 1, Tab 7). Methanex maintained that the imputed value of $0.42/GJ resulted in a serious misstatement of Methanex's revenue to cost ratio.
8 Evidence Methanex repeated evidence from the October, 1995 hearing which indicated that the net value to Methanex of purchasing valley gas over the preceding year had been approximately $0.10 to $0.20/GJ. For 1996 onward, Methanex described its firm gas procurement strategy of buying gas at Station 2 based on the Sumas, Washington price less Westcoast' s transportation-south charges. Methanex believes this would yield lower prices at Station 2 than those found on the spot market (Exhibit 1, Tab 15, Question 6). Methanex filed a projection of the Station 2 price differential for the January through October, 1996 period which averaged $0.29/GJ (Ex. 2). In Argument, Methanex stated that $0.29/GJ should be used as the starting point for the imputed value calculation and that the $0.05/GJ transportation differential to Summit Lake should not be included. Methanex also expressed concern that the difference between spot prices and the cost of valley gas is very volatile, and too problematic to project far into the future. It strongly advocated market-based pricing for valley gas sold on-system, and removal of the imputed value of service for valley gas from the cost of service study. PNG filed evidence which indicates that the difference between spot prices and the commodity cost of valley gas averaged $0.197 /GJ in 1995 (Ex 1, Tab 13, p. 25). It also provided the actual differentials for January through April, 1996 and forecast differentials for the rest of the year. An arithmetic average of the numbers for 1996 is $0.417 /GJ (Ex. 7). PNG went on to explain that about 30 percent of the Station 2 prices under the Company's system supply contracts are demand charges which are deducted when calculating the commodity cost of valley gas. This deduction for demand charges amounts to approximately $0.40 to $0.45/GJ. Since all of PNG's system supply contracts now have index-based prices and both system supply gas prices and spot prices are related to index, this differential will continue to apply across a considerable range of prices. PNG indicated that the relationship between spot prices and the cost of valley gas will continue through the 1996/97 gas year (T: 177 -179). PNG argued that the methodology used to determine the imputed value of valley gas was reasonable and that the forecast of $0.42/GJ for 1996 is supportable. The Utility opposed the introduction of market-based pricing until it has had an opportunity to discuss the matter thoroughly with its customers. PNG indicated that, considering the time available to hold discussions and that certain individuals may not be available during the summer, it would be very difficult to get agreement with its industrial customers for the implementation of market-based pricing on January I, 1997 (T: 188).
9 Commission Determination The Commission accepts the position of PNG that more discussion with its customers is needed before market-based pricing can be implemented. However, the Commission continues to be concerned about the variability of the price differential and the difficulty of generating an imputed value of service for valley gas that will be reasonably accurate for several years. Variances between actuals and the forecasts used in the cost of service study could be handled by deferral account treatment of the impact of the variances, or by an annual review of the forecast and adjustment of the rate design. PNG did not support either approach, on the basis that they would increase regulatory involvement and reduce rate stability (T.195-200). Methanex may be able to buy firm gas in a manner which at this time gives a differential relative to the cost of valley gas at Station 2 of $0.29/GJ. Nevertheless, the valley gas is available at Station 2, and there is no reason for the Commission to deem a market value for the gas which is less than the spot price at that location. The Commission recognizes that the use of an arithmetic average to calculate the imputed value could be somewhat imprecise, but notes that a weighted average based on the Net Interruptible Sales numbers in Table 1 would likely be higher. The evidence gives the Commission no cause to revise its forecast of price differential. The average figure of $0.42/GJ was based on actual numbers for 1993 and 1994 and projections for 1995 and 1996. The estimate of $0.20/GJ for 1995 has been substantiated and the present expectation for 1996 is consistent with $0.42/GJ. Moreover, because the price that PNG pays for valley gas is generally based on an index at Sumas which correlates with spot prices at Station 2, it is expected that the differential should remain at this level through to the October 31, 1997 end of the 1996/97 gas contract year. As discussed in Chapter 2, the Commission recognizes that valley gas constitutes only about 70 percent of total interruptible deliveries to Methanex. To arrive at a value of the price differential that can be applied to all interruptible deliveries to Methanex, the average differential should be reduced by this ratio to $0.29/GJ. Methanex currently pays about $0.06/GJ for moving interruptible gas from Station 2 to Summit Lake (Exhibit 1, Tab 15, Question 3). A similar value should apply to all PNG interruptible sales gas deliveries, but not to Methanex's direct purchases. To arrive at a number which applies to Total Interruptible Deliveries, a Westcoast charge of $0.05/GJ must be added to the discounted price differential, which gives an imputed value of $0.34/GJ for Methanex.
10 The imputed value of $0.42/GJ from the Rate Design Decision will continue to apply for PNG' s other interruptible sales customers. This will address to some extent Methanex's concern that its lower priority of access to interruptible sales gas should be reflected in a lower value. The Commission confirms that the value which interruptible customers obtain through their access to valley gas is to be incorporated into the cost of service study by including an imputed value of service for valley gas. The Commission directs PNG to use $0.34/GJ as the imputed value of service for valley gas sold to Methanex and confirms $0.42/GJ as the imputed value for valley gas sold to other interruptible sales customers. These imputed values are to be applied to Total Interruptible Deliveries. 4. 0 OTHER MATTERS 4 .1 Timing of Next Rate Design Application In the Rate Design Decision, the Commission directed PNG to file a revised cost of service study and rate design application in 1998. PNG is carrying on discussions with its customers concerning long term issues and has indicated that an earlier filing of its next rate design application is a possibility (T: 184 ). Both PNG and Methanex were reluctant to forecast prices beyond 1996 (T: 176, 99). However, the evidence discussed in Chapter 3 indicates that there are reasons to expect that the imputed value of service for valley gas will be acceptable for at least most of 1997. Commission Determination Although the Commission confirms its earlier Decision that market-based pricing for interruptible sales should not be implemented at this time, the Commission recognizes that the approach appears to offer a solution to concerns with the present methodology. Market-based pricing would avoid the need to include forecasts of the quantity and imputed value for valley gas in the cost of service study. Forecasting of valley gas sales would still be necessary, but it would likely be incorporated into the gas cost component of revenue requirements. This forecast could readily be updated annually and variances accumulated in a deferral account. The Commission agrees with PNG that a market-based pricing proposal should be developed in consultation with its industrial customers and wishes to give PNG sufficient time for such consultation. However, it has become clear to the Commission that the issue requires earlier resolution than that
11 provided by the three year period set out in the Rate Design Decision. Also, implementation is likely to require adjustments to the delivery margin portion of firm rates, and this should be done in a rate design proceeding. The Commission directs PNG to advance the filing of a revised cost of service study and rate design application to no later than September 1, 1997 for implementation on January 1, 1998. The application is to include a detailed proposal for the implementation of market-based prices for on-system interruptible sales. 4. 2 Access to Interruptible Transportation Capacity and Sales Gas In Argument, Methanex asked the Commission to instruct " ... PNG to work with Methanex to implement a workable nomination/authorization procedure". While it is evident that Methanex' s access to interruptible service is less reliable than it would desire, it is also apparent that PNG transports direct purchase gas for Methanex using interruptible service. A similar situation relates to access to interruptible sales gas from PNG. This matter is outside the scope of the Reconsideration. The Commission expects the Company and its customers to collectively address matters of this nature and to bring a resolution forward to the Commission. Preferably, this would be done as part of a regular rate design or revenue requirement proceeding. 4. 3 Clarification of Imputed Value of Interruptible Delivery Service While the imputed value of service for interruptible deliveries was not raised by Methanex for review in this Reconsideration, it has become apparent to the Commission that clarification of this part of the Rate Design Decision is in order. For example, Methanex used $0.62/GJ as the imputed value of delivery service in its Evidence (Exhibit 1, Tab 14, p. 2). The imputed value of delivery service numbers in the Rate Design Decision includes the actual variable cost of delivery (e.g. compressor fuel). However, this actual variable cost is recovered in either the firm or the interruptible rate for all deliveries. A detailed inspection of Table 7 from the Decision confirms that the actual variable cost was deducted in the calculation of the imputed value of service credit as used in the cost of service study. For example, Exhibit 7 illustrates that the imputed value of $0.625/GJ for Methanex was reduced to an average net value of $0.522/GJ in the cost of service study.
12 4 . 4 Purchase of Valley Gas for Resale To offset some of its concerns about including an imputed value of valley gas in the cost of service study, Methanex argued that it should be permitted to buy valley gas at Station 2 for resale off-system when it does not require the gas at its plant. Such access to valley gas may provide an interim response to some of Methanex's concerns. This could be implemented during a Methanex shutdown, such as the one scheduled for October, 1996. An interruptible customer's access to valley gas would likely have a lower priority than on-system requirements, and may have to be limited to the customer's normal requirements on an annual or peak day basis. The Commission encourages PNG to discuss the matter further with Methanex and its other interruptible industrial customers and, providing there are no serious concerns with the approach, to file an implementation proposal. 5.0 RESULTS OF THE RECONSIDERATION Tables 7 and 12 from the Rate Design Decision have been updated for the reduced forecast of interruptible deliveries and the revised value of service for valley gas that apply to Methanex, and are attached as Tables 7R and 12R. The Commission considers that the impact on revenue to cost ratios does not warrant a change to the increases in residential rates of 10 percent in 1996 and of 5 percent in 1997 which are set out in the Rate Design Decision. The revisions do affect the allocation of the additional revenue from the residential class to other customers, and in particular increase the amount that is allocated to Methanex. This will result in a small reduction to Methanex's firm rate. The Commission is concerned that the revenue to cost ratio of residential customers continues to lie outside the 0.90 to 1.10 zone of reasonableness adopted in the Rate Design Decision. The Commission requires PNG to address this matter specifically in the revised cost of service and rate design application due by September 1, 1997.
13 DATED at the City of Vancouver, in the Province of British Columbia, this day of July, 1996. Lorna R. Barr Chair of the Division 'ken L. Hall, P.Eng. Commissioner
Reconsideration of 1995 Rate Design Decision Pacific Northern Gas Ltd. - West Determination of Revenue/Cost Ratios Table No. 1 Plus Imputed Value of Interruptible Transportation and Valley Gas Credit Total Interruptible Deliveries of 3.00 PJ/y and Imputed Value of Service for Valley Gas of $0.34/GJ used for Methanex Excluding the Cost of Gas and Westcoast Demand Tolls; Methanex Interruptible at 125% Load Factor Customer Deliveries Gross Revision Revision Revised lmput. Value Costs 75 to 0 BP Reverse Gross Interrupt. to lndust. 56.7E3m3 Costs Transport (GJ) ($k) ($k) ($k) ($k) ($k) Residential, sales 1,904,073 10,332 138 196 10,666 -1,458 Commercial, firm sales 1 ,508, 102 5,037 88 201 5,326 -1 '155 Commercial, int. sales 87,500 10 0 0 10 Small Industrial, sales 312,565 479 9 -32 456 Small Industrial, trans. 1 ,330,401 1,312 27 -45 1,294 Nat. Gas Vehicles, sales 74,068 81 1 -4 78 Off Season, interr. sales 24,000 4 0 0 4 Methanex, firm trans. 22,901 '195 17,196 -213 -245 16,738 ~thanex, interr. trans. 0 0 0 0 0 Methanex, interr. sales 3,000,000 308 0 0 308 Methanex Total 25,901,195 17,504 -213 -245 17,046 Skeena, firm trans. 2,930,220 2,608 -21 -36 2,551 Skeena, interr. trans. 0 0 0 0 0 Skeena, interr. sales 969,780 11 7 0 0 117 Skeena Total 3,900,000 2,725 -21 -36 2,668 Eurocan, firm trans. 2,574,288 2,064 -25 -29 2,010 Eurocan, in terr. trans. 0 0 0 0 0 Eurocan, interr. sales 204,526 21 0 0 21 Eurocan Total 2, 778,814 2,085 -25 -29 2,031 Alcan, firm trans. 436,905 371 -4 -4 363 Alcan, interr. trans. 0 0 0 0 0 Alcan, interr. sales 363,095 37 0 0 37 Alcan Total 800,000 408 -4 -4 400 BC Hydro, interr. sales 3,000 1 0 0 1 TOTAL 38,623,718 39,978 0 2 39,980 Notes: 1. Deliveries, Gross Costs and Existing Revenue from Exhibit 78. 2. Revision to Gross Costs to reverse the allocation of 75 basis points of Risk Premium to Large Industrials from Exhibit 4, Tab PNG p. 28. 3. Revision to Gross Costs to reverse 56.7 of the 113.4 E3m3/d reduction to resid., comm. design peak days, as dif. between Exhibit 4, BCUC IR p. 15 and Methanex IR p. 26. 4. lnterr. Transportation Value allocated to Firm Sales and Small lndust. using ((1-LF)·co·km] developed from Exhibit 4, Methanex IR p. 23 and BCUC IR p.15. 5. Valley Gas Credit allocated to Firm Sales using ((1-LF)'CD•km) developed from Exhibit 4, Methanex IR p. 23 and BCUC IR p.15. Table No. 7R Imputed Revised Revised Existing Existing Rev/Cost Valley Gas Allocated Allocated Revenue Revenue Ratio Credit Costs Costs ($k) ($k) ($/GJ) ($k) ($/GJ) -929 8,279 4.348 5,402 2.837 0.65 -736 3,435 2.278 3,286 2.179 0.96 95 37 142 1.625 128 1.463 0.90 -74 -47 334 1.069 445 1.424 1.33 -116 0 1 '178 0.885 1 ,515 1.139 1.29 -2 -1 76 1.021 81 1.094 1.07 29 1 0 44 1.813 48 2.000 1.10 0 0 16,738 0.731 20,469 0.894 1.22 ...... 0 0 0 0 +:-1,567 1,020 2,895 0.965 667 0.222 0.23 1,567 1,020 19,633 0.758 21 '136 0.816 1.08 0 0 2,551 0.871 3,161 1.079 1.24 0 0 0 0 694 407 1,218 1.256 957 0.987 0.79 694 407 3,769 0.967 4,118 1.056 1.09 0 0 2,010 0.781 2,673 1.038 1.33 0 0 0 0 150 86 257 1.256 210 1.027 0.82 1 50 86 2,267 0.816 2,883 1.037 1.27 0 0 363 0.832 522 1.195 1.44 0 0 0 0 267 152 456 1.256 358 0.986 0.79 267 152 819 1.024 880 1.100 1.07 3 4 1.249 20 6.667 5.34 0 0 39,979 39,942 BCUC
Reconsideration of 1995 Rate Design Decision Pacific Northern Gas ltd. - West Determination of Revenue/Cost Ratios Table No. 7 Plus Residential Rate Increases in 1996 and 1997 Total Interruptible Deliveries of 3.00 PJ/y and Imputed Value of Service for Valley Gas of $0.34/GJ used for Methanex Excluding the Cost of Gas and Westcoast Demand Tolls; Methanex Interruptible at 125% Load Factor Customer Deliveries Gross Revised Revised Existing Rev/Cost Costs Gross Allocated Revenue Ratio Costs Costs (GJ) ($k) ($k) ($k) ($k) Residential, sales 1,904,073 10,332 10,666 8,279 5,402 Commercial, firm sales 1 ,508, 102 5,037 5,326 3,435 3,286 Commercial, int. sales 87,500 1 0 1 0 142 128 Small Industrial, sales 312,565 479 456 334 445 Small Industrial, trans. 1,330,401 1,312 1,294 1 '178 1 ,515 Nat. Gas Vehicles, sales 74,068 81 78 76 81 Off Season, interr. sales 24,000 4 4 44 48 Methanex, firm trans. 22,901 '195 17,196 16,738 16,738 20,469 Methanex, interr. trans. 0 0 0 0 0 Methanex, interr. sales 3,000,000 308 308 2,895 667 Methanex Total 25,901 '195 17,504 17,046 19,633 21 '136 Skeena, firm trans. 2,930,220 2,608 2,551 2,551 3,161 Skeena, interr. trans. 0 0 0 0 0 Skeena, interr. sales 969,780 11 7 117 1,218 957 Skeena Total 3,900,000 2,725 2,668 3,769 4,118 Eurocan, firm trans. 2,574,288 2,064 2,010 2,010 2,673 Eurocan, interr. trans. 0 0 0 0 0 Eurocan, interr. sales 204,526 21 21 257 210 Eurocan Total 2,778,814 2,085 2,031 2,267 2,883 Alcan, firm trans. 436,905 371 363 363 522 Alcan, interr. trans. 0 0 0 0 0 Alcan, interr. sales 363,095 37 37 456 358 Alcan Total 800,000 408 400 819 880 BC Hydro, interr. sales 3,000 1 4 20 TOTAL 38,623,718 39,978 39,980 39,979 39,942 Notes: 1. Deliveries, Gross Costs and Existing Revenue from Exhibit 78. 2. Revision to Gross Costs to reverse the allocation of 75 basis points of Risk Premium to Large Industrials from Exhibit 4, Tab PNG p. 28. 3. Revision to Gross Costs to reverse 56.7 of the 113.4 E3m3/d reduction to resid., comm. design peak days, as dif. between Exhibit 4, BCUC IR p. 15 and Methanex IR p. 26. 4. lnterr. Transportation Value allocated to Firm Sales and Small lndust. using [(1-LF)*CD*km) developed from Exhibit 4, Methanex IR p. 23 and BCUC IR p.15. 5. Valley Gas Credit allocated to Firm Sales using [{1-LF)*CD*km] developed from Exhibit 4, Methanex IR p. 23 and BCUC I R p.15. 6. Residential increases allocated to Small Industrial, NGV, Eurocan, Methanex, Skeena and Alcan, so as to give the same RIC ratio for each class. Table No. 12R Residential +10% in 1996 Residential +5% in 1997 Revenue Revised Rev/Cost Revenue Revised Rev/Cost Change Revenue Ratio Change Revenue Ratio ($k) ($k) ($k) ($k) 0.65 1,082 6,484 0.78 595 7,079 0.86 0.96 0 3,286 0.96 0 3,286 0.96 0.90 0 1 28 0.90 0 128 0.90 1.33 -88 357 1.07 -7 350 1.05 1.29 -257 1,258 1.07 -25 1,233 1.05 1.07 0 81 1.07 -2 79 1.05 1.10 0 48 1.10 0 48 1.10 1.22 -174 20,295 1.21 -416 19,879 1.19 0 0 0 VI 0.23 0 667 0.23 0 667 0.23 1.08 -174 20,961 1.07 -416 20,545 1.05 1.24 -93 3,068 1 .20 -80 2,988 1 .17 0 0 0 0.79 0 957 0.79 0 957 0.79 1.09 -93 4,025 1.07 -80 3,945 1.05 1.33 -463 2,210 1 .1 0 -48 2,162 1.08 0 0 0 0.82 0 210 0.82 0 210 0.82 1.27 -463 2,420 1.07 -48 2,372 1.05 1.44 -5 517 1.42 -17 499 1.37 0 0 0 0.79 0 358 0.79 0 358 0.79 1.07 -5 875 1.07 -17 857 1.05 5.34 0 20 5.34 0 20 5.34 0 39,942 0 39,942 BCUC
cor\ col.u ~\ ~ ~<5> q:.; ht ., .. . Q;) c .... A ,.~~""-' z l,·· ~'7.,.~ ···I 0 SIXTH FLOOR, 900 HOWE STREET, BOX 250 '( VANCOUVER, B.C. V6Z 2N3 //: -... ~ ;~ CANADA /12's co~~' IN THE MATTER OF the Utilities Commission Act, S.B.C. 1980, c. 60, as amended and An Application by Methanex Corporation for Reconsideration of the Pacific Northern Gas Ltd. and Pacific Northern Gas (N.E.) Ltd. December 15, 1995 Rate Design Decision and Commission Order No. G-106-95 BEFORE: L.R. Barr, Deputy Chairperson; and ) K.L. Hall, Commissioner ORDER WHEREAS: A. On February 1, 1996 Methanex Corporation ("Methanex") applied to the Commission, pursuant to Section 114 of the Utilities Commission Act ("the Act"), for a reconsideration (the "Methanex Reconsideration Application") of the Pacific Northern Gas Ltd. ("PNG") and Pacific Northern Gas (N.E.) Ltd. ("PNG(N.E.)") Rate Design Decision dated December 15, 1995 (the "Decision"); and B. On February 29, 1996 Eurocan Pulp and Paper Company and Skeena Cellulose Inc. (the "Mills") filed a submission which included a request for a reconsideration of other parts of the Decision which directly impact on the Mills; and C. On March 11, 1996 Methanex filed a submission which included a request for a reconsideration of the imputed value of service for interruptible sales gas which is purchased from PNG; and E. On March 15, 1996 the Commission issued its Reconsideration Decision: Phase I and Order No. G-26-96 which allowed the first part of the Methanex Reconsideration Application concerning the forecasting of the interruptible Methanex volumes to proceed to the next phase of the reconsideration and established an oral public hearing for May 31, 1996, and denied the second part of the application concerning the use of a combined revenue to cost ratio; and F. The Reconsideration Decision: Phase I and Order No. G-26-96 also established a schedule for dealing with supplementary reconsideration applications; and G. Methanex confirmed its March 11, 1996 supplementary application, but the Commission did not receive any other supplementary reconsideration applications; and H. On April 23, 1996 the Commission issued its decision as a Supplement to the Reconsideration Decision: Phase I, and Order No. G-37-96 which allowed Methanex the supplementary reconsideration application concerning the imputed value of service for interruptible sales gas to proceed to the Reconsideration hearing; and BRITISH COLUMBIA UTIUTIES CO;'.t\MISSiON ·: t . . i _ ii . . i : .. ;....r. lr/. 'Y ORDER NU\·1BER G-7 4-96 ......................... , ................ ... . · \' . : • ~ : : ... ' 'o0 TELEPHONE: (604) 660-4700 BC TOLL FREE: 1-800-663-1385 FACSIMILE: (604) 660-1102 ) July 11, 1996 .. .12
I. The public hearing into the Methanex Reconsideration Application and the supplementary reconsideration application was held in Vancouver, B.C. on May 31, 1996; and J. The Commission has considered the applications and evidence presented at the hearing, and the written arguments and reply argument that were filed after the hearing. NOW THEREFORE the Commission orders PNG and PNG(N.E.) to comply with the directions in the Commission's Reconsideration Decision: Phase II issued concurrently with and having the same date as this Order. DATED at the City of Vancouver, in the Province of British Columbia, this Order/PNG-Mthnx Jul.ll Decision BRITISH COLUMBIA UTILITIES COMMISSION ORDER 2 NUMBER G-74-96 •••••••ouooooooo .. ••••••••••••uooo•nHuo• II v:= day of July, 1996. BY ORDER ~~ f-2.. (] C-V\.. Lorna R. Barr Deputy Chairperson
APPEARANCES G.A. FULTON J. LUTES R.B. WALLACE M.MCCORDIC WITNESS PANEL METHANEX PANEL: J. TYSON PNGPANEL: C.P. DONOHUE A.R. FORD R. BROWNELL J.B. WILLISTON ALLW EST COURT REPORTERS LTD. APPENDIX A Page 1 of 1 Commission Counsel Pacific Northern Gas Ltd. Pacific Northern Gas (N.E.) Ltd. Methanex Corporation Eurocan Pulp and Paper Ltd.; Skeena Cellulose Inc. Manager of Gas Supply and Regulatory Affairs Manager of Regulatory Affairs Regulatory Analyst Commission Staff Court Reporters & Hearing Officer
LIST OF EXHIBITS Pacific Northern Gas Ltd. and Pacific Northern Gas (N.E.) Ltd. 1995 Rate Design Application Reconsideration Hearing - Exhibit Book (List of Exhibits from Exhibit Book is Appendix C, attached) Page 31 of Pacific Northern Gas's Response to BCUC Information Request No.1 revised to illustrate Methanex's response to BCUC Information Request No. 1, Question 6 Pacific Northern Gas Ltd. and Methanex Corporation 1995 Forecast Deliveries Pacific Northern Gas Ltd. and Methanex Corporation 1995 Actual Deliveries (GJ) 1995 Margin Analysis Chart Calculation of Interruptible Deliveries to Methanex, Witness Aid based on PNG Response to BCUC Information Request #1 Table 7 from the 1995 Rate Design Decision Comparison of 1996 Methanex Deliveries to the Forecasted Deliveries in Decision Table of Interruptible Gas Prices, revised page 25 of Pacific Northern Gas Ltd. response to BCUC Information Request No. 1 Page 31 of Pacific Northern Gas Ltd.'s Response to BCUC Information Request No. 1, revised Supply/Demand Balance Summary, May 30, 1996 Daily Gas Nomination Authorization for Methanex Corporation May 27, 1996 Daily Gas Nomination Authorization for Methanex Corporation February 26, 1996 Daily Gas Nomination Authorization for Methanex Corporation January 29, 1996 Adjustment of 1993 and 1994 Interruptible Amounts for 4,000 Mcfd Firm-Up, based on Interruptible Deliveries from PNG Response to BCUC Information Request #1, page 2 APPENDIX B Page 1 of 1 Exhibit No. 1 2 3A 3B 3C 4 SA 5B 6 7 8A 8B 8C 8D 9
APPENDIX C Page 1 of 2 pages PACIFIC NORTHERN GAS LTD. PACIFIC NORTHERN GAS (N.E.) LTD. 1995 RATE DESIGN APPLICATION RECONSIDERATION LIST OF EXHIBITS TAB ITEM British Columbia Utilities Commission Order Number G-14-96 dated February 8,1996 2 Reconsideration Decision: Phase I dated March 15, 1996 3 British Columbia Utilities Commission Order Number G-26-96 dated March 15, 1996 4 Reconsideration Decision: Phase I Supplement dated April23, 1996 5 British Columbia Utilities Commission Order Number G-37-96 dated April 23, 1996 6 Letter dated February 1, 1996 from R. Brian Wallace of Bull, Hausser & Tupper on behalf of Methanex Corporation to the British Columbia Utilities Commission 7 Letter dated February 19, 1996 from C.P. Donohue of Pacific Northern Gas Ltd. to the British Columbia Utilities Commission 8 Letter dated February 22, 1996 from C.P. Donohue of Pacific Northern Gas Ltd. to the B.C. Utilities Commission 9 Letter dated February 29, 1996 from Richard Hopp of Inland Pacific Energy Services on behalf of Eurocan Pulp and Paper Company Ltd. and Skeena Cellulose Inc. to the British Columbia Utilities Commission 10 Letter dated March 11, 1996 from R. Brian Wallace of Bull, Hausser & Tupper on behalf of Methanex Corporation to the British Columbia Utilities Commission 11 Letter dated March 25, 1996 from R. Brian Wallace of Bull, Hausser & Tupper on behalf of Methanex Corporation to the British Columbia Utilities Commission
APPENDIX C Page 2 of 2 pages LIST OF EXHIBITS - PAGE 2 TAB ITEM 12 Letter dated March 28, 1996 from Robert Pellatt of the British Columbia Utilities Commission toR. Brian Wallace of Bull, Housser & Tupper 13 Pacific Northern Gas Ltd. response to BCUC I.R. No. 1 dated April 25, 1996 14 Evidence ofMethanex Corporation dated May 3, 1996 15 Letter dated May 15, 1996 from J.L. Tyson of Methanex Corporation to the British Columbia Utilities Commission enclosing response to BCUC Staff Information Request No. 1 16 Pacific Northern Gas Ltd. Information Request No. 1 to Methanex Corporation revised May 16, 1996 17 Letter dated May 23, 1996 from J.L. Tyson of Methanex Corporation to the British Columbia Utilities Commission enclosing response to BCUC Staff Information Request No.2 18 Letter dated May 23, 1996 from J.L. Tyson of Methanex Corporation to Pacific Northern Gas Ltd. enclosing response to Pacific Northern Gas Ltd. Information Request No. 1 to Methanex Corporation
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